EXHIBIT 13.1

Quarterly report to shareholders

Third quarter 2018

Financial highlights

	three months ended September 30				nine months ended September 30
(unaudited - millions of $, except per share amounts)	2018		2017		2018		2017
Income
Revenues	3,156		3,195		9,775		9,832
Net income attributable to common shares	928		612		2,447		2,136
per common share – basic		$1.02		$0.70		$2.72		$2.46
– diluted		$1.02		$0.70		$2.72		$2.45
Comparable EBITDA1	2,056		1,667		6,110		5,474
Comparable earnings1	902		614		2,534		1,971
per common share1		$1.00		$0.70		$2.82		$2.27
Cash flows
Net cash provided by operations	1,299		1,185		4,516		3,840
Comparable funds generated from operations1	1,571		1,316		4,641		4,191
Comparable distributable cash flow1	1,413		1,170		4,158		3,691
per common share1		$1.56		$1.34		$4.63		$4.24
Capital spending2	2,798		2,543		7,491		6,658
Dividends declared
Per common share		$0.69		$0.625		$2.07		$1.875
Basic common shares outstanding (millions)
– weighted average for the period	906		873		898		870
– issued and outstanding at end of period	914		874		914		874

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

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

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Management’s discussion and analysis

October 31, 2018

This management’s discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the three and nine months endedSeptember 30, 2018, and should be read with the accompanying unaudited condensed consolidated financial statements for the three and nine months endedSeptember 30, 2018, which have been prepared in accordance with U.S. GAAP.

This MD&A should also be read in conjunction with our December 31, 2017 audited consolidated financial statements and notes and the MD&A in our 2017 Annual Report. Capitalized and abbreviated terms that are used but not otherwise defined herein are identified in our 2017 Annual Report. Certain comparative figures have been adjusted to reflect the current period’s presentation.

FORWARD-LOOKING INFORMATION

We disclose forward-looking information to help current and potential investors understand management’s assessment of our future plans and financial outlook, and our future prospects overall.

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

Forward-looking statements in this MD&A include information about the following, among other things:

• planned changes in our business

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

• expectations or projections about strategies and goals for growth and expansion

• expected cash flows and future financing options available to us

• expected dividend growth

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

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

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

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

• expected capital expenditures and contractual obligations

• expected operating and financial results

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

• expected impact of U.S. Tax Reform

• expected industry, market and economic conditions.

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

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

Assumptions

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

• inflation rates and commodity prices

• nature and scope of hedging activities

• regulatory decisions and outcomes, including those related to the 2018 FERC Actions

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

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

• integrity and reliability of our assets

• access to capital markets

• anticipated construction costs, schedules and completion dates.

Risks and uncertainties

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

• the operating performance of our pipeline and energy assets

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

• the availability and price of energy commodities

• the amount of capacity payments and revenues from our energy business

• regulatory decisions and outcomes, including those related to the 2018 FERC Actions

• outcomes of legal proceedings, including arbitration and insurance claims

• performance and credit risk of our counterparties

• changes in market commodity prices

• changes in the regulatory environment

• changes in the political environment

• changes in environmental and other laws and regulations

• competitive factors in the pipeline and energy sectors

• construction and completion of capital projects

• costs for labour, equipment and materials

• access to capital markets

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

• weather

• cyber security

• technological developments

• economic conditions in North America as well as globally.

You can read more about these factors and others in this MD&A and in other disclosure documents we have filed with Canadian securities regulators and the SEC, including the MD&A in our 2017 Annual Report.

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

FOR MORE INFORMATION

You can find more information about TransCanada in our Annual Information Form and other disclosure documents, which are available on SEDAR (www.sedar.com).

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NON-GAAP MEASURES

This MD&A references the following non-GAAP measures:

• comparable earnings

• comparable earnings per common share

• comparable EBITDA

• comparable EBIT

• funds generated from operations

• comparable funds generated from operations

• comparable distributable cash flow

• comparable distributable cash flow per common share.

These measures do not have any standardized meaning as prescribed by GAAP and therefore may not be similar to measures presented by other entities.

Comparable measures

We calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. Except as otherwise described herein, these comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

Our decision not to adjust for a specific item is subjective and made after careful consideration. Specific items may include:

• certain fair value adjustments relating to risk management activities

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

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

• legal, contractual and bankruptcy settlements

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

• restructuring costs

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

• acquisition and integration costs.

We exclude the unrealized gains and losses from changes in the fair value of derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives generally provide effective economic hedges but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them reflective of our underlying operations.

The following table identifies our non-GAAP measures against their most directly comparable GAAP measures.

Comparable measure	Original measure
comparable earnings	net income attributable to common shares
comparable earnings per common share	net income per common share
comparable EBITDA	segmented earnings
comparable EBIT	segmented earnings
comparable funds generated from operations	net cash provided by operations
comparable distributable cash flow	net cash provided by operations

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Comparable earnings and comparable earnings per common share

Comparable earnings represents earnings or loss attributable to common shareholders on a consolidated basis, adjusted for specific items. Comparable earnings is comprised of segmented earnings, interest expense, AFUDC, interest income and other, income taxes and non-controlling interests, adjusted for specific items. See the Consolidated results section for reconciliations to net income attributable to common shares and net income per common share.

Comparable EBIT and comparable EBITDA

Comparable EBIT represents segmented earnings, adjusted for specific items. We use comparable EBIT as a measure of our earnings from ongoing operations as it is a useful indicator of our performance and an effective tool for evaluating trends in each segment. Comparable EBITDA is calculated the same way as comparable EBIT but excludes the non-cash charges for depreciation and amortization. See the Reconciliation of non-GAAP measures section for a reconciliation to segmented earnings.

Funds generated from operations and comparable funds generated from operations

Funds generated from operations reflects net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period, and is used to provide a consistent measure of the cash generating performance of our assets. Comparable funds generated from operations is adjusted for the cash impact of specific items. See the Financial condition section for a reconciliation to net cash provided by operations.

Comparable distributable cash flow and comparable distributable cash flow per common share

We believe comparable distributable cash flow is a useful supplemental measure of performance that defines cash available to common shareholders before capital allocation. Comparable distributable cash flow is defined as comparable funds generated from operations less preferred share dividends, distributions to non-controlling interests and non-recoverable maintenance capital expenditures.

Maintenance capital expenditures are expenditures incurred to maintain our operating capacity, asset integrity and reliability, and include amounts attributable to our proportionate share of maintenance capital expenditures on our equity investments. We have the opportunity to recover effectively all of our pipeline maintenance capital expenditures in Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines through tolls. Canadian natural gas pipelines maintenance capital expenditures are reflected in rate bases, on which we earn a regulated return and subsequently recover in tolls. Our U.S. natural gas pipelines can recover maintenance capital expenditures through tolls under current rate settlements, or have the ability to recover such expenditures through tolls established in future rate cases or settlements. Tolling arrangements in our liquids pipelines provide for the recovery of maintenance capital expenditures. As such, in 2018 our presentation of comparable distributable cash flow and comparable distributable cash flow per common share only includes a reduction for non-recoverable maintenance capital expenditures in their respective calculations. Comparative figures have been adjusted to reflect this presentation.

See the Financial condition section for a reconciliation to net cash provided by operations.

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Consolidated results - third quarter2018

	three months ended September 30						nine months ended September 30
(unaudited - millions of $, except per share amounts)	2018			2017			2018			2017
Canadian Natural Gas Pipelines	267			316			800			903
U.S. Natural Gas Pipelines	545			337			1,734			1,299
Mexico Natural Gas Pipelines	127			95			382			333
Liquids Pipelines	316			203			1,047			681
Energy	223			237			464			1,080
Corporate	(68		)	(29		)	(77		)	(102		)
Total segmented earnings	1,410			1,159			4,350			4,194
Interest expense	(577		)	(504		)	(1,662		)	(1,528		)
Allowance for funds used during construction	147			145			365			367
Interest income and other	168			84			139			193
Income before income taxes	1,148			884			3,192			3,226
Income tax expense	(120		)	(188		)	(394		)	(781		)
Net income	1,028			696			2,798			2,445
Net income attributable to non-controlling interests	(59		)	(44		)	(229		)	(189		)
Net income attributable to controlling interests	969			652			2,569			2,256
Preferred share dividends	(41		)	(40		)	(122		)	(120		)
Net income attributable to common shares	928			612			2,447			2,136
Net income per common share — basic		$1.02			$0.70			$2.72			$2.46
— diluted		$1.02			$0.70			$2.72			$2.45

Net income attributable to common shares increased by $316 million and $311 million, or $0.32 and $0.26 per common share, for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017. Net income per common share in 2018 reflects the dilutive impact of common shares issued in 2017 and 2018 under our DRP and Corporate ATM program.

Net income in both periods included unrealized gains and losses from changes in risk management activities, which we exclude, along with other specific items as noted below to arrive at comparable earnings.

2018 results included:

• after-tax income of $8 million and $3 million for the three and nine months endedSeptember 30, 2018 related to our U.S. Northeast power marketing contracts primarily due to income recognized on the sale of our retail contracts in first quarter and earnings from the remaining contracts. These amounts have been excluded from Energy's comparable earnings effective January 1, 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020.

2017 results included:

• a $12 million after-tax loss and a $243 million after-tax gain, for the three and nine months ended September 30, 2017, related to the monetization of our U.S. Northeast power generation assets. This included a $440 million after-tax gain on the sale of TC Hydro, an incremental loss of $183 million after tax recorded on the sale of the thermal and wind package and $14 million year-to-date of after-tax disposition costs and income tax adjustments

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• an after-tax charge of $30 million in third quarter and $69 million year-to-date for integration-related costs associated with the acquisition of Columbia

• an after-tax charge of $8 million in third quarter and $19 million year-to-date related to the maintenance of Keystone XL assets which was expensed in 2017 pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized

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

A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.

RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS

	three months ended September 30						nine months ended September 30
(unaudited - millions of $, except per share amounts)	2018			2017			2018			2017
Net income attributable to common shares	928			612			2,447			2,136
Specific items (net of tax):
U.S. Northeast power marketing contracts	(8		)	—			(3		)	—
Net loss/(gain) on sales of U.S. Northeast power generation assets	—			12			—			(243		)
Integration and acquisition related costs – Columbia	—			30			—			69
Keystone XL asset costs	—			8			—			19
Keystone XL income tax recoveries	—			—			—			(7		)
Risk management activities1	(18		)	(48		)	90			(3		)
Comparable earnings	902			614			2,534			1,971
Net income per common share — basic		$1.02			$0.70			$2.72			$2.46
Specific items (net of tax):
U.S. Northeast power marketing contracts	(0.01		)	—			—			—
Net loss/(gain) on sales of U.S. Northeast power generation assets	—			0.01			—			(0.28		)
Integration and acquisition related costs – Columbia	—			0.03			—			0.08
Keystone XL asset costs	—			0.01			—			0.02
Keystone XL income tax recoveries	—			—			—			(0.01		)
Risk management activities	(0.01		)	(0.05		)	0.10			—
Comparable earnings per common share		$1.00			$0.70			$2.82			$2.27

1	Risk management activities	three months ended September 30				nine months ended September 30
	(unaudited - millions of $)	2018		2017		2018		2017
	Canadian Power	—		1		3		5
	U.S. Power	31		59		(31	)	(97	)
	Liquids marketing	(65	)	(19	)	(10	)	(15	)
	Natural Gas Storage	—		4		(6	)	5
	Interest rate	—		(1	)	—		(1	)
	Foreign exchange	60		33		(79	)	89
	Income tax attributable to risk management activities	(8	)	(29	)	33		17
	Total unrealized gains/(losses) from risk management activities	18		48		(90	)	3

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Comparable earnings increased by $288 million or $0.30 per common share for the three months endedSeptember 30, 2018 compared to the same period in 2017 and was primarily the net effect of:

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

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

• lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform

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

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

Comparable earnings increasedby $563 millionor $0.55 per common share for the nine months endedSeptember 30, 2018 compared to the same period in 2017 and was primarily the net effect of:

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

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

• lower income tax expense primarily due to lower income tax rates as a result of U.S. Tax Reform

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

• increased Western Power results due to higher realized margins on higher generation volumes

• lower earnings from U.S. Power mainly due to the sales of the U.S. Northeast power generation assets in second quarter 2017 combined with the U.S. Northeast Power marketing results being excluded from comparable earnings in 2018

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

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

• lower Eastern Power results mainly due to the sale of our Ontario solar assets in December 2017.

Comparable earnings per common share for the three and nine months endedSeptember 30, 2018 also reflect the dilutive impact of common shares issued in 2017 and 2018 under our DRP and our Corporate ATM program.

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2018 FERC Actions

BACKGROUND

In December 2016, FERC issued a Notice of Inquiry (NOI) seeking comment on how to address the issue of whether its existing policies resulted in a ‘double recovery’ of income taxes in a pass-through entity such as a master limited partnership (MLP). This NOI was in response to a decision by the U.S. Court of Appeals for the District of Columbia Circuit in July 2016 in United Airlines, Inc., et al. v. FERC (the United case), directing FERC to address the issue.

On December 22, 2017, U.S. Tax Reform was signed resulting in significant changes to U.S. tax law including a decrease in the U.S. federal corporate income tax rate from 35 per cent to 21 per cent effective January 1, 2018. As a result of this change, accumulated deferred income tax (ADIT) assets and liabilities related to our U.S. businesses, including amounts related to our proportionate share of assets held in TC PipeLines, LP, were remeasured as at December 31, 2017 to reflect the new lower U.S. federal corporate income tax rate. With respect to our U.S. rate-regulated natural gas pipelines and storage entities, the impact of this remeasurement was recorded as a net regulatory liability.

On March 15, 2018, FERC issued (1) a Revised Policy Statement to address the treatment of income taxes for rate-making purposes for MLPs; (2) a Notice of Proposed Rulemaking (NOPR) proposing natural gas pipeline and storage entities file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the Revised Policy Statement on each entity's ROE assuming a single-issue adjustment to an entity's rates; and (3) a NOI seeking comment on how FERC should address changes related to ADIT and bonus depreciation. On July 18, 2018, FERC issued (1) an Order on Rehearing of the Revised Policy Statement dismissing rehearing requests; and (2) a Final Rule adopting and revising procedures from, and clarifying aspects of, the NOPR (Final Rule), (collectively, the “2018 FERC Actions”). The Final Rule became effective September 13, 2018, and is subject to requests for further rehearing and clarification. The impacts of the Final Rule relate to both FERC-regulated natural gas pipeline and gas storage assets. Discussion within this 2018 FERC Actions section describes the impact to our natural gas pipelines, but also applies to our FERC-regulated natural gas storage assets.

FERC Revised Policy Statement on Treatment of Income Taxes for MLPs

The Revised Policy Statement changes FERC's long-standing policy allowing income tax amounts to be included in rates subject to cost-of-service rate regulation for pipelines owned by an MLP. The Revised Policy Statement 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. On July 18, 2018, FERC dismissed requests for rehearing and provided clarification of the Revised Policy Statement. In this Order on Rehearing, FERC noted that an MLP is not automatically precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance in its cost-of-service rates. Additionally, FERC provided guidance with regard to ADIT for MLP pipelines and other pass-through entities. FERC found 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. As a result, the Revised Policy Statement also precludes the recognition and subsequent amortization of any related regulatory assets or liabilities that might have otherwise impacted rates charged to customers as a refund or collection of excess or deficient deferred income tax assets or liabilities.

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Final Rule on Tax Law Changes for Interstate Natural Gas Pipelines and Storage Entities

The Final Rule established a schedule by which interstate pipelines must either (i) file a new uncontested rate settlement or (ii) file a one-time report, called FERC Form 501-G, that quantifies the isolated rate impact of U.S. Tax Reform on FERC-regulated pipelines and the impact of the Revised Policy Statement on pipelines held by MLPs. A pipeline filing the FERC Form 501-G must do so by established dates in fourth quarter 2018 and will have four options:

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

• commit to file either a pre-packaged uncontested rate settlement or a general Section 4 rate case if it believes that using the limited Section 4 option will not result in just and reasonable rates. If the pipeline commits to file either by December 31, 2018, FERC will not initiate a Section 5 investigation of its rates prior to that date

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

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

NOI Regarding the Effect of U.S. Tax Reform on Commission-Jurisdictional Rates

In the NOI, FERC sought comment on the effects of U.S. Tax Reform to determine additional action, if any, required by FERC related to ADIT balances that were reserved in anticipation of being paid to or refunded by the Internal Revenue Service, but which no longer accurately reflect the future income tax liability or asset. The NOI also sought comment on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of U.S. Tax Reform on regulated rates or earnings.

As noted above, FERC's Order on Rehearing of the Revised Policy Statement provided guidance with regard to ADIT for MLP pipelines, finding that if an MLP pipeline's income tax allowance is eliminated from its cost-of-service rates, then its existing ADIT balance used for rate-making purposes should also be eliminated from its rate base.

IMPACT OF 2018 FERC ACTIONS ON TRANSCANADA

Our U.S. natural gas pipelines are held through a number of different ownership structures. We do not anticipate that the earnings and cash flows from our directly-held U.S. natural gas pipelines, including ANR, Columbia Gas and Columbia Gulf, will be materially impacted by the Revised Policy Statement as a significant proportion of their overall revenues are earned under non-recourse rates. Columbia Gas is required under existing settlements to adjust certain of its recourse rates for the decrease in the U.S. federal corporate income tax rate enacted December 22, 2017, with the changes implemented January 1, 2018. As ANR, Columbia Gas, Columbia Gulf and other wholly-owned regulated assets undergo future rate proceedings, future rates may be impacted prospectively as a result of U.S. Tax Reform, but the impact is expected to be largely mitigated by lower corporate income tax rates. Therefore, the impact on earnings and cash flows resulting from the 2018 FERC Actions on our U.S. natural gas pipelines held outside of TC PipeLines, LP is expected to be limited in comparison to pre-U.S. Tax Reform.

The following is an update on our filings outside of TC Pipelines, LP, in response to the Final Rule subsequent to September 30, 2018:

• Millennium Pipeline filed its Form 501-G October 11, 2018

• ANR, ANR Storage, Columbia Gas, Columbia Gulf and Crossroads are scheduled to file their respective Form 501-Gs on December 6, 2018 unless new uncontested rate settlements are filed

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• Hardy Storage and Blue Lake Storage have reached rate settlements in principle. We expect to file the settlement agreements with FERC in fourth quarter 2018. As outlined in 2018 FERC Actions, pipeline and storage assets that file an uncontested settlement will be relieved of their obligations to file a Form 501-G.

The Revised Policy Statement also prohibits an income tax allowance for liquids pipelines held in MLP structures. We do not expect an impact on our U.S. liquids pipelines as they are not held in MLP form.

Financing

In March 2018, as a result of the initially proposed 2018 FERC Actions, further drop downs of assets into TC PipeLines, LP were considered to no longer be a viable funding lever. In addition, the TC PipeLines, LP ATM program ceased to be utilized. Pursuant to the 2018 FERC Actions issued on July 18, 2018, it is yet to be determined if and when in the future these might be restored as competitive financing options. Regardless, we believe we have the financial capacity to fund our existing capital program through predictable and growing cash flow generated from operations, access to capital markets including through our Corporate ATM program and our DRP, portfolio management, cash on hand and substantial committed credit facilities.

Impact of 2018 FERC Actions on TC PipeLines, LP

On October 16, 2018, GTN filed with FERC an uncontested settlement with its customers to address the changes proposed by the 2018 FERC Actions via an amendment to its prior settlement in 2015 (“2018 GTN Settlement”). Among the terms of the latest settlement, GTN has agreed to (i) a refund of US$10 million to its firm customers in 2018, (ii) a reduction to its existing maximum system reservation rates by 10 per cent effective January 1, 2019, and (iii) an additional 6.6 per cent reduction effective January 1, 2020 through December 31, 2021. GTN and its customers have also agreed upon a moratorium on further rate changes prior to January 1, 2022. The uncontested settlement, subject to approval by the FERC, will relieve GTN of its obligation to file a Form 501-G.

The following is an update on other TC PipeLines, LP filings in response to the Final Rule subsequent to September 30, 2018:

• PNGTS filed its Form 501-G with FERC along with an explanation why no rate change is needed

• North Baja elected to make a limited NGA Section 4 filing and reduce its recourse rates by approximately 11 per cent, which is the percentage reduction in the cost of service per the FERC Form 501-G

• Iroquois requested a waiver of its requirement to file a Form 501-G from FERC based on its existing moratorium precluding rate changes prior to September 2020

• Bison is scheduled to file its response by November 8, 2018 and Northern Border, Great Lakes and Tuscarora are scheduled to file by December 6, 2018.

Following the 2018 GTN Settlement, TC PipeLines, LP’s earnings, cash flows and financial position are less adversely impacted by the 2018 FERC Actions than initially expected. A number of uncertainties still exist with respect to the variability of outcomes around the ultimate resolution of the issues arising from the 2018 FERC Actions, but any additional impact in 2018 is expected to be limited for TC PipeLines, LP while subsequent periods could be more significantly affected. Mitigating this impact, approximately half of TC PipeLines, LP’s revenues, including those of equity investments, are earned under non-recourse rates which are not expected to be impacted by the 2018 FERC Actions. Furthermore, as our ownership in TC PipeLines, LP is approximately 25 per cent, the impact of the 2018 FERC Actions related to TC PipeLines, LP is not expected to be significant to TransCanada's consolidated earnings or cash flows.

Individual pipelines owned by TC PipeLines, LP do not currently have a requirement to file for new rates until 2022, however, that timing may be accelerated by the Final Rule, except where moratoria exist. As noted above, the change in the Final Rule to allow MLPs to remove the ADIT liability from rate base, thus increasing rate base in general, is expected to further mitigate the loss of the tax allowance in cost-of-service based rates.

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As a result of the 2018 FERC Actions initially proposed in March 2018, and in order to retain cash in anticipation of a possible reduction of revenues, TC PipeLines, LP reduced its quarterly distribution to common unitholders by 35 per cent to US$0.65 per unit beginning with its first quarter 2018 distribution.

Impairment Considerations

We review plant, property and equipment and equity investments for impairment whenever events or changes in circumstances indicate the carrying value of the asset may not be recoverable.

Goodwill is tested for impairment on an annual basis, or more frequently if events or changes in circumstance indicate that it might be impaired. We can initially make this assessment based on qualitative factors. If we conclude that it is not more likely than not that the fair value of the reporting unit is less than its carrying value, then an impairment test is not performed.

We continue to monitor developments following the Final Rule on the 2018 FERC Actions. We will incorporate results to date, future filings for individual pipelines, as well as FERC responses to others in the industry into our annual goodwill impairment tests as well as our normal review of plant, property and equipment and equity investments for recoverability.

As at September 30, 2018, the goodwill balances related to Great Lakes and Tuscarora are US$573 million and US$82 million (December 31, 2017 – US$573 million and US$82 million), respectively. At December 31, 2017, the estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. There is a risk that the goodwill balances related to both of these assets could be negatively impacted by the FERC developments, once finalized, or by other changes in management's estimates of fair value resulting in a goodwill impairment charge.

U.S. Tax Reform

Pursuant to the enactment of U.S. Tax Reform, we recorded net regulatory liabilities and a corresponding reduction in net deferred income tax liabilities in the amount of $1,686 million at December 31, 2017 related to our U.S. natural gas pipelines subject to RRA. Amounts recorded to adjust income taxes remain provisional as our interpretation, assessment and presentation of the impact of U.S. Tax Reform may be further clarified with additional guidance from tax authorities. Should additional guidance be provided by tax authorities during the one-year measurement period permitted by the SEC, we will review the provisional amounts and adjust as appropriate.

Commencing January 1, 2018, we have amortized the net regulatory liabilities using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine and immediately begin recording amortization based on their composite depreciation rates. For the three and nine months endedSeptember 30, 2018, amortization of the net regulatory liabilities in the amount of $12 million and $36 million was recorded and included in Revenues. Once the final impact of the 2018 FERC Actions is determined there may be prospective adjustments to our net regulatory liabilities.

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THIRD QUARTER 2018

Capital Program

We are developing quality projects under our capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flows.

Our capital program consists of approximately $36 billion of secured projects and approximately $20 billion of projects under development. Our secured projects include commercially supported, committed projects that are either under construction or that are in or preparing to commence the permitting stage but are not yet fully approved. Our projects under development are commercially supported except where noted, but have greater uncertainty with respect to timing and estimated project costs and are subject to certain approvals.

Three years of maintenance capital expenditures for all of our businesses are also included in the secured projects table. Maintenance capital expenditures on our regulated Canadian and U.S. natural gas pipelines are added to rate base on which we have the opportunity to earn a return and recover these expenditures through current or future tolls, which is similar to our capacity capital projects on these pipelines. Tolling arrangements in Liquids Pipelines provide for the recovery of maintenance capital expenditures.

All projects are subject to cost adjustments due to weather, market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits, among other factors. Amounts presented in the following tables exclude capitalized interest and AFUDC.

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THIRD QUARTER 2018

Secured projects

	Expected in-service date	Estimated project cost1	Carrying value at September 30, 2018
(unaudited - billions of $)
Canadian Natural Gas Pipelines
Canadian Mainline	2018-2021	0.2	0.1
NGTL System	2018	0.6	0.5
	2019	2.8	0.8
	2020	1.7	0.1
	2021	2.5	—
	2022	1.5	—
Coastal GasLink2,3	2023	6.2	0.5
Regulated maintenance capital expenditures	2018-2020	1.9	0.5
U.S. Natural Gas Pipelines
Columbia Gas
Mountaineer XPress	2018	US 3.0	US 2.2
WB XPress	2018	US 0.9	US 0.8
Modernization II	2018-2020	US 1.1	US 0.4
Buckeye XPress	2020	US 0.2	—
Columbia Gulf
Gulf XPress	2018	US 0.6	US 0.5
Other	2018-2020	US 0.3	US 0.2
Regulated maintenance capital expenditures	2018-2020	US 1.9	US 0.4
Mexico Natural Gas Pipelines
Sur de Texas4	2018	US 1.4	US 1.3
Villa de Reyes4	2019	US 0.8	US 0.6
Tula4	2020	US 0.7	US 0.6
Liquids Pipelines
White Spruce	2019	0.2	0.1
Recoverable maintenance capital expenditures	2018-2020	0.1	—
Energy
Napanee	2019	1.6	1.4
Bruce Power – life extension5	2018-2023	2.2	0.5
Other
Non-recoverable maintenance capital expenditures6	2018-2020	0.8	0.2
		33.2	11.7
Foreign exchange impact on secured projects7		3.2	2.0
Total secured projects (Cdn$)		36.4	13.7

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

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

3 Carrying value excludes the reduction for the fourth quarter 2018 elections made to date by certain LNG Canada participants to reimburse approximately $0.4 billion of pre-development costs pursuant to project agreements. Refer to the Recent Developments section for additional details.

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

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

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

7 Reflects U.S./Canada foreign exchange rate of 1.29 at September 30, 2018.

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THIRD QUARTER 2018

Projects under development

The costs provided in the table below reflect the most recent estimates for each project as filed with the various regulatory authorities or otherwise determined.

	Estimated project cost1	Carrying value at September 30, 2018
(unaudited - billions of $)
Canadian Natural Gas Pipelines
NGTL System – Merrick	1.9	—
Liquids Pipelines
Heartland and TC Terminals2,3	0.9	0.1
Grand Rapids Phase 22,3	0.7	—
Keystone XL4	US 8.0	US 0.4
Keystone Hardisty Terminal2,3,4	0.3	0.1
Energy
Bruce Power – life extension5	6.0	—
	17.8	0.6
Foreign exchange impact on projects under development6	2.3	0.1
Total projects under development (Cdn$)	20.1	0.7

1 Amounts reflect our proportionate share of joint venture costs where applicable and 100 per cent of costs related to wholly-owned assets.

2 Regulatory approvals have been obtained.

3 Additional commercial support is being pursued.

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

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

6 Reflects U.S./Canada foreign exchange rate of 1.29 at September 30, 2018.

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THIRD QUARTER 2018

Outlook

Consolidated comparable earnings

In fourth quarter 2018, we expect continued strong performance across our business segments consistent with the results reported in the first nine months of 2018. Our overall comparable earnings outlook for 2018 has increased compared to what was included in the 2017 Annual Report primarily due to the net effect of:

• improved earnings from additional contract sales in U.S. Natural Gas Pipelines

• higher contracted and uncontracted volumes on the Keystone Pipeline System as well as higher contributions from liquids marketing activities

• increased revenues in Mexico Natural Gas Pipelines

• increased benefit from and better visibility into the impacts of U.S. Tax Reform

• the sale of our 62 per cent share of the Cartier Wind power facilities.

The 2018 FERC Actions are not anticipated to have a significant impact on our earnings or cash flows in 2018. Refer to the 2018 FERC Actions section for additional details.

Consolidated capital spending

We expect to spend approximately $10.5 billion in 2018 on growth projects, maintenance capital expenditures and contributions to equity investments. The increase from the amount included in the 2017 Annual Report primarily reflects incremental spending required to complete construction of our secured projects capital program in 2018, as well as the capitalization of costs to further advance our projects under development.

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THIRD QUARTER 2018

Canadian Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2018		2017		2018		2017
NGTL System	302		256		884		722
Canadian Mainline	195		263		592		774
Other1	25		25		85		79
Comparable EBITDA	522		544		1,561		1,575
Depreciation and amortization	(255	)	(228	)	(761	)	(672	)
Comparable EBIT and segmented earnings	267		316		800		903

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

Canadian Natural Gas Pipelines segmented earnings decreased by $49 million and $103 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 and are equivalent to comparable EBIT.

Net income and comparable EBITDA for our rate-regulated Canadian natural gas pipelines are generally affected by our approved ROE, our investment base, our level of deemed common equity and incentive earnings or losses. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow-through basis.

NET INCOME AND AVERAGE INVESTMENT BASE

	three months ended September 30		nine months ended September 30
(unaudited - millions of $)	2018	2017	2018	2017
Net Income
NGTL System	101	92	289	261
Canadian Mainline	40	49	121	149
Average investment base
NGTL System			9,419	8,210
Canadian Mainline			3,855	4,165

Net income for the NGTL System increased by $9 million and $28 million for the three and nine months ended

September 30, 2018 compared to the same periods in 2017 mainly due to a higher average investment base resulting from continued system expansions, partially offset by lower OM&A incentive earnings. On June 19, 2018, the NEB approved NGTL's 2018-2019 Revenue Requirement Settlement Application (the 2018-2019 Settlement). This settlement, which is effective from January 1, 2018 to December 31, 2019, includes an ROE of 10.1 per cent on 40 per cent deemed equity, a mechanism for sharing variances above and below a fixed annual OM&A amount, flow-through treatment of all other costs and an increase in depreciation rates. See the Recent developments section for additional details.

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THIRD QUARTER 2018

Net income for the Canadian Mainline decreased by $9 million and $28 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 primarily due to incentive earnings recorded in 2017. Incentive earnings have not been recognized in 2018 pending an NEB decision on the 2018-2020 Tolls Review. As a result of the pending decision, the Canadian Mainline earnings to date reflect the last approved ROE of 10.1 per cent on 40 per cent deemed equity.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $27 million and $89 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 mainly due to NGTL System facilities that were placed in service and an increase in the approved depreciation rates in the 2018-2019 Settlement.

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THIRD QUARTER 2018

U.S. Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended September 30				nine months ended September 30
(unaudited - millions of US$, unless noted otherwise)	2018		2017		2018		2017
Columbia Gas	204		125		637		446
ANR	111		86		370		301
TC PipeLines, LP1,2,3	30		28		102		87
Great Lakes4	18		9		74		49
Midstream	42		27		101		70
Columbia Gulf	34		16		90		55
Other U.S. pipelines3,5	19		14		50		64
Non-controlling interests6	89		80		304		266
Comparable EBITDA	547		385		1,728		1,338
Depreciation and amortization	(130	)	(116	)	(380	)	(340	)
Comparable EBIT	417		269		1,348		998
Foreign exchange impact	128		68		386		311
Comparable EBIT (Cdn$)	545		337		1,734		1,309
Specific item:
Integration and acquisition related costs – Columbia	—		—		—		(10	)
Segmented earnings (Cdn$)	545		337		1,734		1,299

1 Results reflect our earnings from TC PipeLines, LP’s ownership interests in GTN, Great Lakes, Iroquois, Northern Border, Bison, PNGTS, North Baja and Tuscarora, as well as general and administrative costs related to TC PipeLines, LP.

2 TC PipeLines, LP periodically conducts ATM equity issuances which decrease our ownership in TC PipeLines, LP. For the three months endedSeptember 30, 2018, our ownership interest in TC PipeLines, LP was 25.5 per cent compared to 26.0 per cent for the same period in 2017. Our ownership interest for the nine months endedSeptember 30, 2018, was 25.5 per cent compared to a range of 26.5 to 26.0 per cent for the same period in 2017.

3 TC PipeLines, LP acquired 49.34 per cent of our 50 per cent interest in Iroquois and our remaining 11.81 per cent interest in PNGTS on June 1, 2017.

4 Results reflect our 53.55 per cent direct interest in Great Lakes. The remaining 46.45 per cent is held by TC PipeLines, LP.

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

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

U.S. Natural Gas Pipelines segmented earnings increased by $208 million and $435 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017.

Segmented earnings for the nine months endedSeptember 30, 2017 included a $10 million pre-tax charge for integration and acquisition related costs associated with the Columbia acquisition. This amount has been excluded from our calculation of comparable EBIT. A weaker U.S. dollar in 2018 had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. operations compared to the same period in 2017, although the U.S. dollar was stronger in third quarter 2018 compared to the same period in 2017.

Earnings from our U.S. Natural Gas Pipelines operations are generally affected by contracted volume levels, volumes delivered and the rates charged as well as by the cost of providing services. Columbia Gas and ANR results are also affected by the contracting and pricing of their storage capacity and commodity sales.

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THIRD QUARTER 2018

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$162 million and US$390 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017. This was primarily the net effect of:

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

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

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

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by US$14 million and US$40 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 mainly due to new projects placed in service.

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THIRD QUARTER 2018

Mexico Natural Gas Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended September 30				nine months ended September 30
(unaudited - millions of US$, unless noted otherwise)	2018		2017		2018		2017
Topolobampo	42		39		128		119
Tamazunchale	33		29		96		85
Mazatlán	19		16		58		49
Guadalajara	18		17		53		51
Sur de Texas1	4		3		14		14
Other	—		(10	)	4		(10	)
Comparable EBITDA	116		94		353		308
Depreciation and amortization	(19	)	(18	)	(56	)	(54	)
Comparable EBIT	97		76		297		254
Foreign exchange impact	30		19		85		79
Comparable EBITand segmented earnings (Cdn$)	127		95		382		333

1 Represents equity income from our 60 per cent interest.

Mexico Natural Gas Pipelines segmented earnings increased by $32 million and $49 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 and are equivalent to comparable EBIT. Earnings from our Mexico operations are underpinned by long-term, stable, primarily U.S. dollar-denominated revenue contracts, and are affected by the cost of providing service. A weaker U.S. dollar in the first nine months of 2018 had a negative impact on Canadian dollar equivalent segmented earnings from our Mexico operations compared to the same period in 2017, although the U.S. dollar was stronger in third quarter 2018 compared to the same period in 2017.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$22 million and US$45 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 as a result of:

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

• the impairment of our equity investment in TransGas in third quarter 2017.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization remained largely consistent for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017.

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THIRD QUARTER 2018

Liquids Pipelines

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2018		2017		2018		2017
Keystone Pipeline System	350		302		1,042		937
Intra-Alberta pipelines	46		4		122		4
Liquids marketing and other	71		(3	)	147		6
Comparable EBITDA	467		303		1,311		947
Depreciation and amortization	(86	)	(71	)	(254	)	(228	)
Comparable EBIT	381		232		1,057		719
Specific items:
Keystone XL asset costs	—		(10	)	—		(23	)
Risk management activities	(65	)	(19	)	(10	)	(15	)
Segmented earnings	316		203		1,047		681
Comparable EBIT denominated as follows:
Canadian dollars	96		63		278		175
U.S. dollars	218		135		605		416
Foreign exchange impact	67		34		174		128
	381		232		1,057		719

Liquids Pipelines segmented earnings increased by $113 million and $366 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 and included the following specific items:

• pre-tax charges related to the maintenance of Keystone XL assets which were expensed in 2017 pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized

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

Liquids Pipelines earnings are generated primarily by providing pipeline capacity to shippers for fixed monthly payments that are not linked to actual throughput volumes. The Keystone Pipeline System also offers uncontracted capacity to the market on a spot basis which provides opportunities to generate incremental earnings. Our liquids marketing business provides customers with a variety of crude oil marketing services including transportation, storage, and crude oil supply, primarily transacted through the purchase and sale of crude oil.

Comparable EBITDA for Liquids Pipelines increasedby $164 million and $364 millionfor the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 and was the net effect of:

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

• a higher contribution from liquids marketing activities

• higher contracted and uncontracted volumes on the Keystone Pipeline System

• foreign exchange impact on the Canadian dollar equivalent earnings from our U.S. operations.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $15 million and $26 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 as a result of new facilities being placed in service.

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THIRD QUARTER 2018

Energy

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the most directly comparable GAAP measure).

	three months ended September 30				nine months ended September 30
(unaudited - millions of Canadian $, unless noted otherwise)	2018		2017		2018		2017
Canadian Power
Western Power	37		24		108		77
Eastern Power1	69		75		221		252
Bruce Power1	100		91		245		314
U.S. Power (US$)2	—		22		—		108
Foreign exchange impact on U.S. Power	—		7		—		34
Natural Gas Storage and other	4		8		21		40
Business Development	(3	)	(3	)	(10	)	(9	)
Comparable EBITDA	207		224		585		816
Depreciation and amortization	(27	)	(39	)	(92	)	(118	)
Comparable EBIT	180		185		493		698
Specific items:
U.S. Northeast power marketing contracts	12		—		5		—
Net (loss)/gain on sales of U.S. Northeast power generation assets	—		(12	)	—		469
Risk management activities	31		64		(34	)	(87	)
Segmented earnings	223		237		464		1,080

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

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

Energy segmented earnings decreased by $14 million and $616 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 and included the following specific items:

• a gain of $12 million and $5 million for the three and nine months endedSeptember 30, 2018 related to our U.S. Northeast power marketing contracts. The year-to-date amount includes a gain in first quarter 2018 on the sale of our retail contracts. These amounts have been excluded from Energy's comparable earnings effective January 1, 2018 as we do not consider the wind-down of the remaining contracts part of our underlying operations. The contract portfolio is scheduled to run-off through to mid-2020

• a net loss of $12 million and a net gain of $469 million before tax for the three and nine months endedSeptember 30, 2017 related to the monetization of our U.S. Northeast power generation assets

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

Risk management activities	three months ended September 30		nine months ended September 30
(unaudited - millions of $, pre-tax)	2018	2017	2018		2017
Canadian Power	—	1	3		5
U.S. Power	31	59	(31	)	(97	)
Natural Gas Storage and Other	—	4	(6	)	5
Total unrealized gains/(losses) from risk management activities	31	64	(34	)	(87	)

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THIRD QUARTER 2018

Comparable EBITDA for Energy decreased by $17 million and $231 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 primarily due to the net effect of:

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

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

• lower Eastern Power results due to the sale of our Ontario solar assets in December 2017

• increased Western Power results due to higher realized margins on higher generation volumes

• decreased Natural Gas Storage results primarily due to lower realized natural gas storage price spreads.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization decreased by $12 million and $26 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017 primarily due to the sale of our Ontario solar assets in December 2017 as well as the cessation of depreciation on our Cartier Wind power facilities upon classification as held for sale on June 30, 2018.

BRUCE POWER

The following reflects our proportionate share of the components of comparable EBITDA and comparable EBIT.

	three months ended September 30						nine months ended September 30
(unaudited - millions of $, unless noted otherwise)	2018			2017			2018			2017
Equity income included in comparable EBITDA and EBIT comprised of:
Revenues	397			383			1,153			1,212
Operating expenses	(204		)	(205		)	(640		)	(638		)
Depreciation and other	(93		)	(87		)	(268		)	(260		)
Comparable EBITDA and EBIT1	100			91			245			314
Bruce Power – other information
Plant availability2	89		%	86		%	88		%	89		%
Planned outage days	30			81			180			178
Unplanned outage days	43			19			77			39
Sales volumes (GWh)1	6,087			5,801			17,810			18,093
Realized sales price per MWh3		$67			$67			$67			$67

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

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

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

Planned outage work on Unit 1 and Unit 4 was completed in the first half of 2018. Planned maintenance on Unit 8 began in September 2018 and is scheduled to be completed in fourth quarter 2018. Planned maintenance is expected to begin on Unit 3 in fourth quarter 2018 and continue into early 2019. The overall average plant availability percentage in 2018 is expected to be in the high 80 per cent range.

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THIRD QUARTER 2018

Corporate

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the most directly comparable GAAP measure).

	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2018		2017		2018		2017
Comparable EBITDA and EBIT	(8	)	(4	)	(25	)	(20	)
Specific items:
Foreign exchange (loss)/gain – inter-affiliate loan1	(60	)	7		(52	)	(1	)
Integration and acquisition related costs – Columbia	—		(32	)	—		(81	)
Segmented losses	(68	)	(29	)	(77	)	(102	)

1 Reported in Income from equity investments in our Corporate segment.

Corporate segmented losses increased by $39 million and decreased by $25 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017. These results included the following specific items that have been excluded from comparable EBIT:

• foreign exchange losses and gains on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the affiliate's project financing. There are corresponding foreign exchange gains and losses included in Interest income and other on the inter-affiliate loan receivable which fully offset these amounts

• in 2017, integration-related costs associated with the acquisition of Columbia.

OTHER INCOME STATEMENT ITEMS

Interest expense

	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2018		2017		2018		2017
Interest on long-term debt and junior subordinated notes
Canadian dollar-denominated	(142	)	(130	)	(407	)	(356	)
U.S. dollar-denominated	(335	)	(314	)	(981	)	(954	)
Foreign exchange impact	(103	)	(79	)	(283	)	(293	)
	(580	)	(523	)	(1,671	)	(1,603	)
Other interest and amortization expense	(30	)	(29	)	(80	)	(74	)
Capitalized interest	33		49		89		150
Interest expense included in comparable earnings	(577	)	(503	)	(1,662	)	(1,527	)
Specific Item:
Risk management activities	—		(1	)	—		(1	)
Interest expense	(577	)	(504	)	(1,662	)	(1,528	)

Interest expense increased by $73 million and $134 million for the three and nine months endedSeptember 30, 2018compared to the same periods in 2017 and primarily reflects the net effect of:

• long-term debt and junior subordinated notes issuances, net of maturities

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

TRANSCANADA [26

THIRD QUARTER 2018

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

• foreign exchange impact on translation of U.S. dollar-denominated interest.

Allowance for funds used during construction

	three months ended September 30		nine months ended September 30
(unaudited - millions of $)	2018	2017	2018	2017
Canadian dollar-denominated	27	44	68	149
U.S. dollar-denominated	91	81	230	168
Foreign exchange impact	29	20	67	50
Allowance for funds used during construction	147	145	365	367

AFUDC increased by $2 million and decreased by $2 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017.

The decrease in Canadian dollar-denominated AFUDC is primarily due to the October 2017 decision not to proceed with the Energy East pipeline project and completion of various expansion programs in first quarter 2018.

The increase in U.S. dollar-denominated AFUDC is primarily due to additional investment in and higher AFUDC rates on Columbia Gas and Columbia Gulf growth projects and continued investment in Mexico projects, partially offset by the commercial in-service of Leach Xpress and Cameron Access in first quarter 2018.

Interest income and other

	three months ended September 30			nine months ended September 30
(unaudited - millions of $)	2018	2017		2018		2017
Interest income and other included in comparable earnings	48	58		166		103
Specific items:
Foreign exchange gain/(loss) – inter-affiliate loan	60	(7	)	52		1
Risk management activities	60	33		(79	)	89
Interest income and other	168	84		139		193

Interest income and other increased by $84 million for the three months ended September 30, 2018 compared to the same period in 2017 and was primarily the net effect of:

• higher interest income and a $60 million foreign exchange gain compared to a $7 million loss in 2017 related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange loss are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related gain and loss amounts are excluded from comparable earnings

• higher unrealized gains on risk management activities in 2018 compared to 2017. These amounts have been excluded from comparable earnings

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

• income of $10 million recognized in 2017 on termination of the PRGT project, related to the recovery of carrying costs.

TRANSCANADA [27

THIRD QUARTER 2018

Interest income and other decreased by $54 million for the nine months ended September 30, 2018 compared to the same period in 2017 and was primarily the net effect of:

• higher interest income and a $52 million foreign exchange gain related to an inter-affiliate loan receivable from the Sur de Texas joint venture. The corresponding interest expense and foreign exchange loss are reflected in Income from equity investments in the Mexico Natural Gas Pipelines and Corporate segments, respectively. The offsetting currency-related gain and loss amounts are excluded from comparable earnings

• unrealized losses on risk management activities in 2018 compared to unrealized gains in 2017. These amounts have been excluded from comparable earnings

• income of $20 million related to reimbursement of Coastal GasLink (CGL) project costs in 2017

• income of $10 million recognized in 2017, on termination of the PRGT project, related to the recovery of carrying costs.

Income tax expense

	three months ended September 30				nine months ended September 30
(unaudited - millions of $)	2018		2017		2018		2017
Income tax expense included in comparable earnings	(108	)	(163	)	(425	)	(605	)
Specific items:
U.S. Northeast power marketing contracts	(4	)	—		(2	)	—
Integration and acquisition related costs – Columbia	—		2		—		22
Keystone XL asset costs	—		2		—		4
Net gain on sales of U.S. Northeast power generation assets	—		—		—		(226	)
Keystone XL income tax recoveries	—		—		—		7
Risk management activities	(8	)	(29	)	33		17
Income tax expense	(120	)	(188	)	(394	)	(781	)

Income tax expense included in comparable earnings decreased by $55 million and $180 million for the three and nine months endedSeptember 30, 2018 compared to the same periods in 2017. This was primarily due to lower income tax rates as a result of U.S. Tax Reform and lower flow-through income taxes in Canadian rate-regulated pipelines, partially offset by higher comparable earnings before income taxes.

Net income attributable to non-controlling interests

	three months ended September 30	nine months ended September 30
(unaudited - millions of $)	2018