EXHIBIT 13.1

Quarterly report to shareholders

First quarter 2018

Financial highlights

	three months ended March 31
(unaudited - millions of $, except per share amounts)	2018		2017
Income
Revenues	3,424		3,407
Net income attributable to common shares	734		643
per common share – basic and diluted		$0.83		$0.74
Comparable EBITDA1	2,071		1,977
Comparable earnings1	870		698
per common share1		$0.98		$0.81
Cash flows
Net cash provided by operations	1,412		1,302
Comparable funds generated from operations1	1,619		1,508
Comparable distributable cash flow1
– reflecting all maintenance capital expenditures	1,223		1,203
– reflecting only non-recoverable maintenance capital expenditures	1,447		1,340
Comparable distributable cash flow per common share1
– reflecting all maintenance capital expenditures		$1.38		$1.39
– reflecting only non-recoverable maintenance capital expenditures		$1.64		$1.55
Capital spending2	2,096		1,794
Dividends declared
Per common share		$0.69		$0.625
Basic common shares outstanding (millions)
– weighted average for the period	885		866
– issued and outstanding at end of period	891		867

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

April 26, 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 months endedMarch 31, 2018, and should be read with the accompanying unaudited condensed consolidated financial statements for the three months endedMarch 31, 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 recent FERC policy changes

• 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 recent FERC policy changes

• 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 recent FERC policy changes

• 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, including the economic benefit of asset drop downs to TC PipeLines, LP

• 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 equivalent 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 measure 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 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. 

Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, we have the ability to recover the majority of these costs in Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines. As such, our presentation of comparable distributable cash flow and comparable distributable cash flow per common share also illustrates the impact of excluding recoverable maintenance capital expenditures from their respective calculations.

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

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Consolidated results - first quarter2018

	three months ended March 31
(unaudited - millions of $, except per share amounts)	2018			2017
Canadian Natural Gas Pipelines	253			282
U.S. Natural Gas Pipelines	648			561
Mexico Natural Gas Pipelines	137			118
Liquids Pipelines	341			227
Energy	50			198
Corporate	(81		)	(33		)
Total segmented earnings	1,348			1,353
Interest expense	(527		)	(500		)
Allowance for funds used during construction	105			101
Interest income and other	63			20
Income before income taxes	989			974
Income tax expense	(121		)	(200		)
Net income	868			774
Net income attributable to non-controlling interests	(94		)	(90		)
Net income attributable to controlling interests	774			684
Preferred share dividends	(40		)	(41		)
Net income attributable to common shares	734			643
Net income per common share - basic and diluted		$0.83			$0.74

Net income attributable to common shares increased by $91 millionor $0.09 per common share for the three months endedMarch 31, 2018 compared to the same period in 2017. Net income per common share in 2018 reflects the effect 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.

2017 results included:

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

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

• a $7 million after-tax charge 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 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.

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RECONCILIATION OF NET INCOME TO COMPARABLE EARNINGS

	three months ended March 31
(unaudited - millions of $, except per share amounts)	2018		2017
Net income attributable to common shares	734		643
Specific items (net of tax):
Risk management activities1	136		21
Integration and acquisition related costs – Columbia	—		24
Loss on sales of U.S. Northeast power generation assets	—		10
Keystone XL asset costs	—		7
Keystone XL income tax recoveries	—		(7		)
Comparable earnings	870		698
Net income per common share		$0.83		$0.74
Specific items (net of tax):
Risk management activities	0.15		0.03
Integration and acquisition related costs – Columbia	—		0.03
Loss on sales of U.S. Northeast power generation assets	—		0.01
Keystone XL asset costs	—		0.01
Keystone XL income tax recoveries	—		(0.01		)
Comparable earnings per common share		$0.98		$0.81

1	Risk management activities	three months ended March 31
	(unaudited - millions of $)	2018		2017
	Liquids marketing	(7	)	—
	Canadian Power	2		1
	U.S. Power	(101	)	(62	)
	Natural Gas Storage	(3	)	5
	Foreign exchange	(79	)	15
	Income tax attributable to risk management activities	52		20
	Total unrealized losses from risk management activities	(136	)	(21	)

Comparable earnings increased by $172 millionor $0.17 per common share for the three months endedMarch 31, 2018 compared to the same period in 2017 and was primarily the net effect of:

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

• 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

• lower income tax expense 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

• higher contribution from Mexico Natural Gas Pipelines mainly due to higher revenues

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

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

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

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

Comparable earnings per common share for the three months endedMarch 31, 2018 also reflect the effect of common shares issued in 2017 and 2018 under our DRP and 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). The 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, H.R. 1, the Tax Cuts and Jobs Act (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, deferred income tax assets and deferred income tax 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.

On March 15, 2018, FERC issued (1) a revised Policy Statement to address the treatment of income taxes for ratemaking purposes for MLPs; (2) a Notice of Proposed Rulemaking (NOPR) proposing interstate pipelines 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 pipeline's return on equity (ROE) assuming a single-issue adjustment to a pipeline’s rates; and (3) a NOI seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation (collectively, the 2018 FERC Actions). Each is described below.

FERC Revised Policy Statement on Treatment of Income Taxes in MLPs

FERC changed its long-standing policy on the treatment of income tax amounts to be included in pipeline rates subject to cost of service rate regulation within a MLP. The Policy Statement no longer permits entities organized as MLPs to recover an income tax allowance in their cost of service rates.

On April 16, 2018, we filed a Request for Clarification and If Necessary Rehearing of the FERC Policy Statement addressing concerns over the lack of clarity around entities with non-MLP ownership structures, entities with shared ownership between a MLP and a corporation, as well as entities owned by MLPs that are, in turn, owned partially by corporations. We sought clarification or a rehearing on the basis that FERC erred in not assessing the propriety of income tax allowances for pipelines on a case-by-case basis; overturned applicable legal precedent expressly not affected by the United case; failed to consider the effects of its order on industry; and failed to exhibit reasoned decision making or to support its decision with substantial evidence on the record.

NOPR on Tax Law Changes for Interstate Natural Gas Pipelines

The NOPR proposes a rule that would require interstate pipelines, in certain circumstances, to file a one-time report, called FERC Form No. 501-G, that quantifies the rate impact of U.S. Tax Reform on FERC-regulated pipelines and the revised Policy Statement on pipelines held by MLPs. In addition to filing the one-time report, each pipeline would have four options:

• make a limited Natural Gas Act Section 4 filing to reduce its rates by the percentage reduction in its cost of service shown in its FERC Form No. 501-G

• 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 Natural Gas Act 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

• file the one-time report without taking any other action. At that point, FERC would consider whether to initiate a Section 5 investigation of any pipeline that has not submitted a limited Section 4 rate reduction filing or committed to file a general Section 4 rate case.

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We submitted comments on the NOPR on April 25, 2018. Following the public comment period, we expect FERC to issue final order(s) in the late summer or early fall of 2018. We are evaluating this NOPR and our next courses of action, however, we do not expect an immediate or a retroactive impact from the NOPR or the revised Policy Statement described above.

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

In the NOI, FERC seeks comment on the effects of U.S. Tax Reform to determine additional action, if any, required by FERC related to accumulated deferred income taxes that were collected from shippers in anticipation of paying the Internal Revenue Service, but which no longer accurately reflect the future income tax liability. The NOI also seeks comment on the elimination of bonus depreciation for regulated natural gas pipelines and other effects of U.S. Tax Reform. We plan to submit comments in response to the NOI, which are due May 21, 2018.

IMPACT OF 2018 FERC ACTIONS ON TRANSCANADA

We own our U.S. natural gas pipelines through a number of different ownership structures. If the 2018 FERC Actions are enacted as proposed, 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 they are held through wholly-owned taxable corporations and a significant proportion of their 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 and Columbia Gulf and other wholly-owned regulated assets undergo future rate proceedings, some of which may be accelerated by the NOPR issued in March 2018, future rates may be impacted prospectively as a result of U.S. Tax Reform, but the impact is expected to be substantially mitigated by lower corporate income tax rates. Therefore, the impact on earnings and cash flows resulting from the 2018 FERC Actions on our wholly-owned U.S. natural gas pipelines is expected to be limited.

The revised Policy Statement also makes reference to prohibiting an income tax allowance for liquids pipelines held in MLP structures. We do not expect an impact on our liquids pipelines in the U.S. as they are not held in MLP form.

Financing

In the absence of changes to the 2018 FERC Actions or the identification and implementation of appropriate mitigation measures, further drop downs of assets into TC PipeLines, LP are not considered to be a viable funding lever. In addition, the TC PipeLines, LP ATM program is not currently being utilized. It is uncertain whether these will be restored as competitive financing options in the future. 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

U.S. natural gas pipelines owned wholly or in part through TC PipeLines, LP are expected to be adversely impacted by the 2018 FERC Actions, if they are enacted as proposed, particularly as contemplated by the policy change prohibiting the recovery of an income tax allowance for pipelines held through MLPs. While approximately half of TC PipeLines, LP’s revenues, including those of equity investments, are earned under non-recourse rates, the remaining revenues under recourse rates are expected to decline as rate adjustments occur without a compensating offset on income taxes paid. 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 NOPR, except where moratoria exist. While a number of uncertainties exist with respect to the changes resulting from the 2018 FERC Actions, in the absence of mitigation, TC PipeLines, LP’s earnings, cash flows and financial position could be materially adversely impacted. The impact in 2018 is expected to be limited, but as rate adjustments are enacted following proceedings with customers and the FERC, subsequent periods could be more significantly affected. As our ownership interest in TC PipeLines, LP is approximately 25 per cent, the

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impact of the 2018 FERC Actions related to TC PipeLines, LP is not expected to be significant to our consolidated earnings or cash flows.

We are closely monitoring these developments as they relate to TC PipeLines, LP in order to identify the strategy that best positions us for the long term. As noted above, we do not anticipate further asset drop downs into TC PipeLines, LP as they are not considered to be a viable funding alternative at this time.

Additional Considerations

In addition to the direct impacts of the 2018 FERC Actions, each individual pipeline will be separately evaluated, including all cost of service elements, to ensure rates are deemed to be just and reasonable. In situations where a pipeline is realizing a relatively higher or lower ROE than is viewed to be just and reasonable, there may be additional prospective adjustments to future rates. The impact to our earnings and cash flows as a result of these potential changes is not expected to be significant. As well, the impact of the 2018 FERC Actions on certain pipelines with shared ownership between corporations and MLPs, or under other ownership structures, remains unclear at this time, with FERC expected to address these in future proceedings. We are monitoring developments on this and will assess the impact as more information becomes available.

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.

Until the proposed 2018 FERC Actions are finalized, implementation requirements are clarified, including the applicability to assets partially-owned by a MLP or held in non-MLP structures, and we and TC PipeLines, LP have fully evaluated our respective alternatives to minimize the impact of the 2018 FERC Actions, we believe that it is not more likely than not that the fair value of any of the reporting units is less than its respective carrying value. Therefore, a goodwill impairment test was not performed. Also, we have determined there is no indication that the carrying values of plant, property and equipment and equity investments potentially impacted by FERC's proposals are not recoverable. We will continue to monitor developments and assess our goodwill for impairment. We will also review our property, plant and equipment and equity investments for recoverability as new information becomes available.

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 2018 FERC Actions, once finalized, could result in a goodwill impairment charge. The goodwill balance for Great Lakes is US$573 million at March 31, 2018 (December 31, 2017 - US$573 million). There is also a risk that the goodwill balance of US$82 million at March 31, 2018 (December 31, 2017 - US$82 million) related to Tuscarora could be negatively impacted by the 2018 FERC Actions.

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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 rate-regulated accounting (RRA). Such amounts remain provisional as our interpretation, assessment and presentation of the impact of U.S. Tax Reform may be further clarified with additional guidance from regulatory, tax and accounting authorities. Should additional guidance be provided by these authorities or other sources during the one-year measurement period permitted by the SEC, we will review the provisional amounts and adjust as appropriate. Other than the amortizations discussed below, no adjustments were made to these amounts during first quarter 2018. There may be prospective adjustments to regulatory liabilities related to natural gas pipelines subject to RRA once the 2018 FERC Actions are finalized and take effect.

Commencing January 1, 2018, the regulatory liabilities are being amortized using the Reverse South Georgia methodology. Under this methodology, rate-regulated entities determine amortization based on their composite depreciation rate and immediately begin recording amortization. Amortization of the net regulatory liability in the amount of $9 million was recorded in first quarter 2018 and included in Revenues.

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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 flow.

Our capital program consists of approximately $21 billion of near-term projects and approximately $24 billion of commercially-supported medium to longer-term projects. Amounts presented exclude maintenance capital expenditures, capitalized interest and AFUDC.

All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.

Near-term projects

	Expected in-service date	Estimated project cost	Carrying value at March 31, 2018
(unaudited - billions of $)
Canadian Natural Gas Pipelines
Canadian Mainline	2018-2021	0.2	—
NGTL System	2018	0.6	0.4
	2019	2.4	0.4
	2020	1.7	0.1
	2021+	2.5	—
U.S. Natural Gas Pipelines
Columbia Gas
Mountaineer XPress	2018	US 3.0	US 0.7
WB XPress	2018	US 0.9	US 0.5
Modernization II	2018-2020	US 1.1	US 0.2
Buckeye XPress	2020	US 0.2	—
Columbia Gulf
Gulf XPress	2018	US 0.6	US 0.3
Other1	2018-2020	US 0.3	US 0.1
Mexico Natural Gas Pipelines
Sur de Texas2	2018	US 1.3	US 1.1
Villa de Reyes	2018	US 0.8	US 0.5
Tula	2019	US 0.7	US 0.5
Liquids Pipelines
White Spruce	2019	0.2	—
Energy
Napanee	2018	1.3	1.1
Bruce Power – life extension3	up to 2020	0.9	0.3
		18.7	6.2
Foreign exchange impact on near-term projects4		2.6	1.1
Total near-term projects (Cdn$)		21.3	7.3

1 Reflects our proportionate share of costs related to Portland XPress and various expansion projects.

2 Reflects our proportionate share.

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

4 Reflects U.S./Canada foreign exchange rate of 1.29 at March 31, 2018.

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Medium to longer-term projects

The medium to longer-term projects have greater uncertainty with respect to timing and estimated project costs. The expected in-service dates of these projects are post-2020, and costs provided in the schedule below reflect the most recent costs for each project as filed with the various regulatory authorities or otherwise determined. These projects are subject to approvals that include FID and/or complex regulatory processes, however, each project has commercial support except where noted.

	Estimated project cost	Carrying value at March 31, 2018
(unaudited - billions of $)
Canadian Natural Gas Pipelines
Canadian west coast LNG-related projects
Coastal GasLink	4.8	0.4
NGTL System – Merrick	1.9	—
Liquids Pipelines
Heartland and TC Terminals1	0.9	0.1
Grand Rapids Phase 22	0.7	—
Keystone XL3	US 8.0	US 0.3
Keystone Hardisty Terminal1,3	0.3	0.1
Energy
Bruce Power – life extension2	5.3	—
	21.9	0.9
Foreign exchange impact on medium to longer-term projects4	2.3	0.1
Total medium to longer-term projects (Cdn$)	24.2	1.0

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

2 Reflects our proportionate share.

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

4 Reflects U.S./Canada foreign exchange rate of 1.29 at March 31, 2018.

Outlook

Consolidated comparable earnings

Our overall comparable earnings outlook for 2018 has increased compared to what was included in the 2017 Annual Report primarily as a result of higher volumes on the Keystone Pipeline System and higher contribution from liquids marketing activities in first quarter 2018. We do not anticipate the 2018 FERC Actions will have a material impact on our earnings or cash flows in 2018. See the 2018 FERC Actions section for further information.

Consolidated capital spending

We expect to spend approximately $10 billion in 2018 on growth projects, maintenance capital and contributions to equity investments for 2018. The increase in capital spending from the amount included in the 2017 Annual Report primarily reflects incremental spending required to complete construction of our near-term capital program in 2018, including Columbia Gas projects, as well as the capitalization of costs to further advance our medium to longer-term projects.

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FIRST 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 equivalent GAAP measure).

	three months ended March 31
(unaudited - millions of $)	2018		2017
NGTL System	271		230
Canadian Mainline	193		247
Other1	30		27
Comparable EBITDA	494		504
Depreciation and amortization	(241	)	(222	)
Comparable EBIT and segmented earnings	253		282

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

Canadian Natural Gas Pipelines segmented earnings decreased by $29 million for the three months endedMarch 31, 2018 compared to the same period 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.

three months ended March 31	NGTL System		Canadian Mainline
(unaudited - millions of $)	2018	2017	2018	2017
Net Income	92	82	37	52
Average investment base	9,091	7,853	3,817	4,103

Net income for the NGTL System increased by $10 million for the three months endedMarch 31, 2018 compared to the same period in 2017 mainly due to a higher average investment base reflecting continued expansion of the system. Pending a NEB decision on the 2018 and 2019 Revenue Requirement Settlement Application, NGTL System earnings reflect the last approved ROE of 10.1 per cent on 40 per cent deemed equity and no incentive earnings have been recorded in 2018.

Net income for the Canadian Mainline decreased by $15 million for the three months endedMarch 31, 2018 compared to the same period in 2017 primarily because no incentive earnings have been recorded in 2018 pending a NEB decision on the 2018 - 2020 Tolls Review. As directed by the NEB, the Canadian Mainline filed an application for approval of 2018 - 2020 tolls on December 18, 2017.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $19 million for the three months endedMarch 31, 2018 compared to the same period in 2017 mainly due to facilities that were placed in service for the NGTL System.

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FIRST 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 equivalent GAAP measure).

	three months ended March 31
(unaudited - millions of US$, unless noted otherwise)	2018		2017
Columbia Gas	231		185
ANR	141		122
TC PipeLines, LP1,2,3	39		32
Great Lakes4	35		27
Midstream	30		23
Columbia Gulf	26		18
Other U.S. pipelines3,5	15		28
Non-controlling interests6	118		108
Comparable EBITDA	635		543
Depreciation and amortization	(122	)	(112	)
Comparable EBIT	513		431
Foreign exchange impact	135		140
Comparable EBIT (Cdn$)	648		571
Specific items:
Integration and acquisition related costs – Columbia	—		(10	)
Segmented earnings (Cdn$)	648		561

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 ended March 31, 2018, our ownership interest in TC PipeLines, LP ranged between 25.7 per cent and 25.5 per cent compared to a range of 26.8 per cent and 26.4 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 Iroquois, Crossroads 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 $87 million for the three months endedMarch 31, 2018 compared to the same period in 2017.

Segmented earnings for the three months endedMarch 31, 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. As well, a weaker U.S. dollar had a negative impact on the Canadian dollar equivalent segmented earnings from our U.S. operations.

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 and ANR results are also affected by the contracting and pricing of their storage capacity and commodity sales. Transmission and storage revenues are generally higher in winter months due to increased seasonal demand for our services.

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FIRST QUARTER 2018

Comparable EBITDA for U.S. Natural Gas Pipelines increased by US$92 million for the three months endedMarch 31, 2018 compared to the same period 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 favourable commodity prices in Midstream

• increased earnings due to the amortization of the net regulatory liability recognized in 2017 as a result of U.S. Tax Reform.

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by US$10 million for the three months endedMarch 31, 2018 compared to the same period in 2017 mainly due to projects placed in service on Columbia Gas.

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FIRST 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 equivalent GAAP measure).

	three months ended March 31
(unaudited - millions of US$, unless noted otherwise)	2018		2017
Topolobampo	44		40
Tamazunchale	31		29
Mazatlán	20		16
Guadalajara	19		17
Sur de Texas1	9		4
Other	4		—
Comparable EBITDA	127		106
Depreciation and amortization	(19	)	(17	)
Comparable EBIT	108		89
Foreign exchange impact	29		29
Comparable EBITand segmented earnings (Cdn$)	137		118

1 Represents our 60 per cent equity interest.

Mexico Natural Gas Pipelines segmented earnings increased by $19 millionfor the three months endedMarch 31, 2018 compared to the same period 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 had a negative impact on the Canadian dollar equivalent segmented earnings from our Mexico operations.

Comparable EBITDA for Mexico Natural Gas Pipelines increased by US$21 million for the three months endedMarch 31, 2018 compared to the same period in 2017 primarily due to:

• higher revenues from operations

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

DEPRECIATION AND AMORTIZATION

Depreciation and amortization remained largely consistent for the three months endedMarch 31, 2018 compared to the same period in 2017.

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FIRST QUARTER 2018

Liquids Pipelines

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

	three months ended March 31
(unaudited - millions of $)	2018		2017
Keystone Pipeline System	340		306
Intra-Alberta pipelines	39		—
Other1	52		6
Comparable EBITDA	431		312
Depreciation and amortization	(83	)	(77	)
Comparable EBIT	348		235
Specific items:
Risk management activities	(7	)	—
Keystone XL asset costs	—		(8	)
Segmented earnings	341		227
Comparable EBIT denominated as follows:
Canadian dollars	93		55
U.S. dollars	202		135
Foreign exchange impact	53		45
	348		235

1 Includes primarily liquids marketing and business development activities.

Liquids Pipelines segmented earnings increased by $114 million for the three months endedMarch 31, 2018 compared to the same period in 2017 and included:

• unrealized losses in 2018 from changes in the fair value of derivatives related to our liquids marketing business

• in 2017, an $8 million charge related to the maintenance of Keystone XL assets which was expensed pending further advancement of the project. In 2018, Keystone XL expenditures are being capitalized.

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 offers uncontracted capacity to the market on a spot basis which provides opportunities to generate incremental earnings.

Comparable EBITDA for Liquids Pipelines increasedby $119 millionfor the three months endedMarch 31, 2018 compared to the same period 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

• higher volumes on the Keystone Pipeline System

• a higher contribution from liquids marketing activities

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

DEPRECIATION AND AMORTIZATION

Depreciation and amortization increased by $6 million for the three months endedMarch 31, 2018 compared to the same period in 2017 as a result of the timing of new facilities being placed in service, partially offset by the effect of a weaker U.S. dollar.

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FIRST QUARTER 2018

Energy

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

	three months ended March 31
(unaudited - millions of Canadian $, unless noted otherwise)	2018		2017
Canadian Power
Western Power	37		30
Eastern Power1	82		94
Bruce Power1	54		91
U.S. Power (US$)2	6		54
Foreign exchange impact on U.S. Power	2		18
Natural Gas Storage and other	7		21
Business Development	(4	)	(3	)
Comparable EBITDA	184		305
Depreciation and amortization	(32	)	(40	)
Comparable EBIT	152		265
Specific items:
Risk management activities	(102	)	(56	)
Loss on sales of U.S. Northeast power generation assets	—		(11	)
Segmented earnings	50		198

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 $148 million for the three months endedMarch 31, 2018 compared to the same period in 2017 and included the following specific items:

• 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

• in 2017, $11 million of pre-tax costs related to the monetization of our U.S. Northeast power generation business.

Risk management activities	three months ended March 31
(unaudited - millions of $, pre-tax)	2018		2017
Canadian Power	2		1
U.S. Power	(101	)	(62	)
Natural Gas Storage	(3	)	5
Total unrealized losses from risk management activities	(102	)	(56	)

The variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our positions for these derivatives over a certain period of time, however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impacts of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them reflective of our underlying operations.

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FIRST QUARTER 2018

Comparable EBITDA for Energy decreased by $121 million for the three months endedMarch 31, 2018 compared to the same period in 2017 mainly due to the net effect of:

• lower contribution from U.S. Power due to the sales of our generation assets in second quarter 2017 and the continued wind down of our U.S. Power marketing operations, partially offset by income recognized on the sale of our retail contracts in the first quarter of 2018

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

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

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

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

DEPRECIATION AND AMORTIZATION

Depreciation and amortization decreased by $8 million for the three months endedMarch 31, 2018 compared to the same period in 2017 following the sale of our Ontario solar assets in December 2017.

BRUCE POWER

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

	three months ended March 31
(unaudited - millions of $, unless noted otherwise)	2018			2017
Equity income included in comparable EBITDA and EBIT comprised of:
Revenues	371			401
Operating expenses	(227		)	(224		)
Depreciation and other	(90		)	(86		)
Comparable EBITDA and EBIT1	54			91
Bruce Power – other information
Plant availability2	85		%	89		%
Planned outage days	74			56
Unplanned outage days	31			17
Sales volumes (GWh)1	5,696			5,983
Realized sales price per MWh3		$67			$67

1 Represents our 48.4 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 was completed in first quarter 2018. Planned outage work commenced on Unit 4 in March 2018 and is scheduled to be completed in second quarter 2018. Planned maintenance is expected to occur on Bruce Units 3 and 8 in the second half of 2018. The overall average plant availability percentage in 2018 is expected to be in the high 80 per cent range.

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FIRST QUARTER 2018

Corporate

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

	three months ended March 31
(unaudited - millions of $)	2018		2017
Comparable EBITDA and EBIT	(2	)	(4	)
Specific items:
Foreign exchange loss – inter-affiliate loan1	(79	)	—
Integration and acquisition related costs – Columbia	—		(29	)
Segmented loss	(81	)	(33	)

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

Corporate segmented loss increased by $48 million for the three months endedMarch 31, 2018 compared to the same period in 2017 and included the following specific items that have been excluded from comparable EBIT:

• in 2018, foreign exchange loss on a peso-denominated inter-affiliate loan to the Sur de Texas project for our proportionate share of the project's financing. There is a corresponding foreign exchange gain included in Interest income and other on the inter-affiliate loan receivable which fully offsets this loss

• in 2017, pre-tax integration and acquisition costs associated with the acquisition of Columbia.

OTHER INCOME STATEMENT ITEMS

Interest expense

	three months ended March 31
(unaudited - millions of $)	2018		2017
Interest on long-term debt and junior subordinated notes
Canadian dollar-denominated	(134	)	(108	)
U.S. dollar-denominated	(314	)	(317	)
Foreign exchange impact	(83	)	(103	)
	(531	)	(528	)
Other interest and amortization expense	(22	)	(17	)
Capitalized interest	26		45
Interest expense	(527	)	(500	)

Interest expense increased by $27 million in the three months endedMarch 31, 2018compared to the same period in 2017 and primarily reflects the net effect of:

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

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

• the positive impact of a weaker U.S. dollar in translating U.S. dollar denominated interest

• lower capitalized interest primarily due to completion of construction of Grand Rapids and Northern Courier in 2017.

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FIRST QUARTER 2018

Allowance for funds used during construction

	three months ended March 31
(unaudited - millions of $)	2018	2017
Canadian dollar-denominated	20	50
U.S. dollar-denominated	67	38
Foreign exchange impact	18	13
Allowance for funds used during construction	105	101

AFUDC increased by $4 million for the three months endedMarch 31, 2018 compared to the same period 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.

The increase in U.S. dollar-denominated AFUDC is primarily due to additional investment in and higher rates on Columbia Gas and Columbia Gulf growth projects, as well as continued investment in Mexico projects.

Interest income and other

	three months ended March 31
(unaudited - millions of $)	2018		2017
Interest income and other included in comparable earnings	63		5
Specific items:
Foreign exchange gain – inter-affiliate loan	79		—
Risk management activities	(79	)	15
Interest income and other	63		20

Interest income and other increased by $43 millionfor the three months endedMarch 31, 2018 compared to the same period in 2017 and was primarily the net effect of:

• interest income along with the $79 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. Both currency-related 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

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

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FIRST QUARTER 2018

Income tax expense

	three months ended March 31
(unaudited - millions of $)	2018		2017
Income tax expense included in comparable earnings	(173	)	(244	)
Specific items:
Risk management activities	52		20
Integration and acquisition related costs – Columbia	—		15
Keystone XL income tax recoveries	—		7
Loss on sales of U.S. Northeast power generation assets	—		1
Keystone XL asset costs	—		1
Income tax expense	(121	)	(200	)

Income tax expense included in comparable earnings decreased by $71 millionfor the three months endedMarch 31, 2018 compared to the same period in 2017 mainly 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.

Net income attributable to non-controlling interests

	three months ended March 31
(unaudited - millions of $)	2018		2017
Net income attributable to non-controlling interests	(94	)	(90	)

Net income attributable to non-controlling interests increased by $4 millionfor the three months endedMarch 31, 2018 compared to the same period in 2017 primarily due to higher earnings, partially offset by our acquisition of the remaining outstanding publicly held common units of CPPL in February 2017.

Preferred share dividends

	three months ended March 31
(unaudited - millions of $)	2018		2017
Preferred share dividends	(40	)	(41	)

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FIRST QUARTER 2018

Recent developments

CANADIAN NATURAL GAS PIPELINES

NGTL System

The NGTL 2017 Expansion Program is now complete and approximately $160 million of facilities have been placed in service since December 31, 2017, including the Northwest Mainline Loop-Boundary Lake pipeline on April 2, 2018. The 2017 Expansion Program added approximately 230 km (143 miles) of new pipeline along with additional compression facilities and increased the NGTL System capacity by approximately 535 TJ/d (500 MMcf/d).

On March 20, 2018, we announced the successful completion of an open season for additional expansion capacity at the Empress / McNeill Export Delivery Point for service expected to commence in November 2021. The offering of 300 TJ/d (280 MMcf/d) was oversubscribed, with an average awarded contract term of approximately 22 years. The facilities and capital requirements for the expansion are still being finalized and are currently anticipated to increase NGTL's $7.2 billion capital program by approximately $120 million.

Sundre Crossover Project

On April 9, 2018, we announced that the Sundre Crossover project was placed in service. The approximate $100 million pipeline project increases NGTL System capacity at our Alberta / B.C. export delivery point by 245 TJ/d (228 MMcf/d), enhancing connectivity to key downstream markets in the Pacific Northwest and California.

NGTL 2018 - 2019 Revenue Requirement Settlement

On March 23, 2018, we filed an application with the NEB for approval of a negotiated settlement with our customers and other interested parties on the annual costs required to operate the NGTL System for 2018 and 2019, along with final 2018 tolls and revised interim 2018 tolls. The settlement fixes ROE at 10.1 per cent on 40 per cent deemed equity and increases the composite depreciation rate from 3.18 per cent to 3.45 per cent. OM&A costs are fixed at $225 million for 2018 and $230 million for 2019 with a 50/50 sharing mechanism for any variances between the fixed amounts and actual OM&A costs. All other costs, including pipeline integrity expenses and emissions costs, are treated as flow-through expenses. The NEB is reviewing comments from interested parties and we anticipate a decision on the application in second quarter 2018.

Canadian Mainline

Canadian Mainline 2018 - 2020 Toll Review

On March 16, 2018, the NEB provided its Notice of Public Hearing for our Supplemental Agreement with the Eastern LDCs filed on December 18, 2017. Our reply evidence is due September 18, 2018. The NEB will provide further details regarding an oral or written hearing process to consider the written submissions of the interested parties.

Maple Compressor Expansion Project

We continue to await an NEB decision on our application seeking project approval and are reviewing project plans to continue to meet our in-service timelines.

U.S. NATURAL GAS PIPELINES

Cameron Access

The Cameron Access project was placed in service on March 13, 2018 and is a Columbia Gulf project designed to transport approximately 0.9 PJ/d (0.8 Bcf/d) of gas supply to the Cameron LNG export terminal in Louisiana.

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FIRST QUARTER 2018

Mountaineer XPress and WB XPress

In first quarter 2018, estimated project costs of US$3.0 billion for Mountaineer XPress and US$0.9 billion for WB XPress have increased by US$0.4 billion and US$0.1 billion, respectively. These increases primarily reflect the impact of delays of various regulatory approvals from FERC and other agencies, increased contractor construction costs due to unusually high demand for construction resources in the region, and modifications to contractor work plans and resources to maintain our projected in-service dates.

Great Lakes and Norther Border Rate Settlements

In February 2018, FERC approved the 2017 Great Lakes Rate Settlement and the 2017 Northern Border Rate Settlement, both of which were uncontested.

MEXICO NATURAL GAS PIPELINES

Tula and Villa de Reyes

We continue to work toward finalizing amending agreements for both of these pipelines with the CFE to formalize the schedule and payments resulting from their respective force majeure events. The CFE has commenced payments on both pipelines in accordance with the TSAs.

Sur de Texas

Offshore construction is now approximately 80 per cent complete and the project continues to progress toward an anticipated in-service date of late 2018.

LIQUIDS PIPELINES

Keystone XL

In December 2017, an appeal to Nebraska's Court of Appeals was filed by intervenors after the Nebraska Public Service Commission (PSC) issued an approval of an alternative route for the Keystone XL project in November 2017. On March 14, 2018, the Nebraska Supreme Court, on its own motion, agreed to bypass the Court of Appeals and hear the appeal case against the PSC’s alternative route itself. We expect the Nebraska Supreme Court, as the final arbiter, could reach a decision by late 2018 or first quarter 2019.

The Keystone XL Presidential Permit, issued in March 2017, has been challenged in two separate lawsuits commenced in Montana. Together with the U.S. Department of Justice, we are actively participating in these lawsuits to defend both the issuance of the permit and the exhaustive environmental assessments that support the U.S. President’s actions. Legal arguments addressing the merits of these lawsuits are scheduled to be heard in late May 2018 and we believe the court’s decisions may be issued by year-end 2018.

The South Dakota Public Utilities Commission permit for the Keystone XL project was issued in June 2010 and recertified in January 2016. An appeal of that recertification was denied in June 2017 and that decision has been further appealed to the South Dakota Supreme Court. On April 6, 2018 the Supreme Court directed the parties to address whether the Court lacks jurisdiction under the governing statute to consider the appeal. Legal arguments are scheduled for April 2018. A decision from the Supreme Court is expected in second quarter or third quarter 2018.

White Spruce

In February 2018, the AER issued a permit for the construction of the White Spruce pipeline. Construction has commenced with an anticipated in-service date in second quarter 2019.

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FIRST QUARTER 2018

ENERGY

Monetization of U.S. Northeast power business

On March 1, 2018, as part of the continued wind down of our U.S. power marketing operations, we closed the sale of our U.S. power retail contracts for proceeds of approximately US$23 million and recognized income of US$10 million (US$7 million after tax).

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FIRST QUARTER 2018

Financial condition

We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.

We believe we have the financial capacity to fund our existing capital program through our predictable and growing cash flow from operations, access to capital markets, including through our corporate ATM program and our Dividend Reinvestment Plan, portfolio management, cash on hand and substantial committed credit facilities. In light of the 2018 FERC Actions, further drop downs of assets into TC PipeLines, LP are not considered to be a viable funding lever. In addition, the TC PipeLines, LP ATM program is not currently being utilized. It is uncertain whether these will be restored as competitive financing options in the future. See the 2018 FERC Actions section for further information.

At March 31, 2018, our current assets totaled $4.6 billion and current liabilities amounted to $11.9 billion, leaving us with a working capital deficit of $7.3 billion compared to a deficit of $5.2 billion at December 31, 2017. Our working capital deficiency is considered to be in the normal course of business and is managed through:

• our ability to generate cash flow from operations

• our access to capital markets

• approximately $9.1 billion of unutilized, unsecured credit facilities.

CASH PROVIDED BY OPERATING ACTIVITIES

	three months ended March 31
(unaudited - millions of $, except per share amounts)	2018			2017
Net cash provided by operations	1,412			1,302
Increase in operating working capital	207			155
Funds generated from operations1	1,619			1,457
Specific items:
Integration and acquisition related costs – Columbia	—			32
Keystone XL asset costs	—			8
Net loss on sales of U.S. Northeast power generation assets	—			11
Comparable funds generated from operations1	1,619			1,508
Dividends on preferred shares	(39		)	(39		)
Distributions paid to non-controlling interests	(69		)	(80		)
Maintenance capital expenditures
– recoverable in future tolls	(224		)	(137		)
– other	(64		)	(49		)
Comparable distributable cash flow1
– reflecting all maintenance capital expenditures	1,223			1,203
– reflecting only non-recoverable maintenance capital expenditures	1,447			1,340
Comparable distributable cash flow per common share1
– reflecting all maintenance capital expenditures		$1.38			$1.39
– reflecting only non-recoverable maintenance capital expenditures		$1.64			$1.55

1 See the Non-GAAP measures section of this MD&A for further discussion of funds generated from operations, comparable funds generated from operations, comparable distributable cash flow and comparable distributable cash flow per common share.

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FIRST QUARTER 2018

COMPARABLE FUNDS GENERATED FROM OPERATIONS

Comparable funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our operations by excluding the timing effects of working capital changes.

Despite the sales of our U.S. power generation assets in second quarter 2017 and the continued wind down of our U.S. Power marketing operations, comparable funds generated from operations increased by $111 million for the three months endedMarch 31, 2018 compared to the same period in 2017. This increase is primarily due to higher comparable EBITDA (excluding income from equity investments) and higher interest income and other, partially offset by higher interest expense.

COMPARABLE DISTRIBUTABLE CASH FLOW

Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholders before capital allocation.

The increase in comparable distributable cash flow for the three months endedMarch 31, 2018 compared to the same period in 2017 primarily reflects higher comparable funds generated from operations, as described above, partially offset by higher recoverable maintenance capital expenditures on Canadian and U.S. natural gas pipelines. Comparable distributable cash flow per common share for the three months endedMarch 31, 2018 also reflects the effect of common shares issued in 2017 and 2018.

Although we deduct maintenance capital expenditures in determining comparable distributable cash flow, we have the ability to recover the majority of these costs in Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Liquids Pipelines. Canadian natural gas pipelines maintenance capital expenditures are reflected in rate bases, on which we earn a regulated return and subsequently recover in tolls. Almost all of our U.S. natural gas pipelines can recover maintenance capital 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 Liquids Pipelines provide for recovery of maintenance capital.

The following provides a breakdown of maintenance capital expenditures:

	three months ended March 31
(unaudited - millions of $)	2018	2017
Canadian Natural Gas Pipelines	119	48
U.S. Natural Gas Pipelines	103	86
Liquids Pipelines	3	3
Other1	63	49
Maintenance capital expenditures	288	186

1 Includes contributions to Bruce Power to fund our proportionate share of maintenance capital expenditures.

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FIRST QUARTER 2018

CASH USED IN INVESTING ACTIVITIES

	three months ended March 31
(unaudited - millions of $)	2018		2017
Capital spending
Capital expenditures	(1,702	)	(1,560	)
Capital projects in development	(36	)	(42	)
Contributions to equity investments	(358	)	(192	)
	(2,096	)	(1,794	)
Other distributions from equity investments	121		363
Deferred amounts and other	110		(85	)
Net cash used in investing activities	(1,865	)	(1,516	)

Capital expenditures in 2018 were incurred primarily for the expansion of the Columbia Gas, Columbia Gulf and NGTL System natural gas pipelines, the construction of Mexico natural gas pipelines and the Napanee power generating facility, as well as capital additions to, and maintenance of, our ANR pipeline.

Costs incurred on capital projects in development were predominantly related to spending on Keystone XL.

Contributions to equity investments increased in 2018 compared to 2017 primarily due to our investments in Bruce Power, Sur de Texas and Millenium, partially offset by decreased contributions to Grand Rapids which went into service in August 2017. Contributions to equity investments also includes our proportionate share of Sur de Texas debt financing.

Other distributions from equity investments primarily reflects our proportionate share of Bruce Power financings undertaken to fund its capital program and make distributions to its partners. In 2018, Bruce Power issued senior notes in capital markets which resulted in distributions totaling $121 million being received by us.

CASH PROVIDED BY FINANCING ACTIVITIES 

	three months ended March 31
(unaudited - millions of $)	2018		2017
Notes payable issued, net	1,812		670
Long-term debt issued, net of issue costs1	93		—
Long-term debt repaid1	(1,226	)	(1,051	)
Junior subordinated notes issued, net of issue costs	—		1,982
Dividends and distributions paid	(466	)	(419	)
Common shares issued, net of issue costs	340		18
Partnership units of TC PipeLines, LP issued, net of issue costs	49		92
Common units of Columbia Pipeline Partners LP acquired	—		(1,205	)
Net cash provided by financing activities	602		87

1 Includes draws and repayments on unsecured loan facility by TC PipeLines, LP.

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LONG-TERM DEBT REPAID

In first quarter 2018, long-term debt repaid included retirements by TCPL of US$500 million of Senior Unsecured Notes bearing interest at a fixed rate of 1.875 per cent, US$250 million of Senior Unsecured Notes bearing interest at a floating rate and $150 million of Debentures bearing interest at a fixed rate of 9.45 per cent.

DIVIDEND REINVESTMENT PLAN

With respect to dividends declared on February 15, 2018, the DRP participation rate amongst common shareholders was approximately 38 per cent, resulting in $234 million reinvested in common equity under the program.

TRANSCANADA CORPORATION ATM EQUITY ISSUANCE PROGRAM

In the three months endedMarch 31, 2018, 5.8 million common shares were issued under the TransCanada ATM program at an average price of $56.51 per common share for gross proceeds of $329 million. Related commissions and fees totaled approximately $3 million, resulting in net proceeds of $326 million. An additional 1.6 million common shares were issued in April 2018, bringing year-to-date gross proceeds to $415 million at an average price of $55.64 per common share.

TC PIPELINES, LP ATM EQUITY ISSUANCE PROGRAM

In the three months endedMarch 31, 2018, 0.7 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$39 million. At March 31, 2018, our ownership interest in TC PipeLines, LP was 25.5 per cent as a result of issuances under the ATM program and resulting dilution.

The TC PipeLines, LP ATM is not currently being utilized, with future issuances under the program uncertain at this time as a result of the 2018 FERC Actions.

DIVIDENDS

On April 26, 2018, we declared quarterly dividends as follows:

Quarterly dividend on our common shares

$0.69 per share

Payable on July 31, 2018 to shareholders of record at the close of business on June 29, 2018.

Quarterly dividends on our preferred shares
Series 1	$0.204125
Series 2	$0.19477534
Series 3	$0.1345
Series 4	$0.15444658
Payable on June 29, 2018 to shareholders of record at the close of business on May 31, 2018.
Series 5	$0.1414375
Series 6	$0.16367534
Series 7	$0.25
Series 9	$0.265625
Payable on July 30, 2018 to shareholders of record at the close of business on July 3, 2018.
Series 11	$0.2375
Series 13	$0.34375
Series 15	$0.30625
Payable on May 31, 2018 to shareholders of record at the close of business on May 15, 2018.

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SHARE INFORMATION

as at April 23, 2018
Common shares	Issued and outstanding
	893 million
Preferred shares	Issued and outstanding	Convertible to
Series 1	9.5 million	Series 2 preferred shares
Series 2	12.5 million	Series 1 preferred shares
Series 3	8.5 million	Series 4 preferred shares
Series 4	5.5 million	Series 3 preferred shares
Series 5	12.7 million	Series 6 preferred shares
Series 6	1.3 million	Series 5 preferred shares
Series 7	24 million	Series 8 preferred shares
Series 9	18 million	Series 10 preferred shares
Series 11	10 million	Series 12 preferred shares
Series 13	20 million	Series 14 preferred shares
Series 15	40 million	Series 16 preferred shares
Options to buy common shares	Outstanding	Exercisable
	13 million	8 million

CREDIT FACILITIES

We have several committed credit facilities that support our commercial paper programs and provide short-term liquidity for general corporate purposes. In addition, we have demand credit facilities that are also used for general corporate purposes, including issuing letters of credit and providing additional liquidity.

At April 23, 2018, we had a total of $11.3 billion of committed revolving and demand credit facilities, including:

Amount	Unused capacity	Borrower	Description	Matures
Committed, syndicated, revolving, extendible, senior unsecured credit facilities
$3.0 billion	$3.0 billion	TCPL	Supports TCPL's Canadian dollar commercial paper program and for general corporate purposes	December 2022
US$2.0 billion	US$2.0 billion	TCPL	Supports TCPL's U.S. dollar commercial paper program and for general corporate purposes	December 2018
US$1.0 billion	US$0.9 billion	TCPL USA	Used for TCPL USA general corporate purposes, guaranteed by TCPL	December 2018
US$1.0 billion	US$0.4 billion	Columbia	Used for Columbia general corporate purposes, guaranteed by TCPL	December 2018
US$0.5 billion	US$0.5 billion	TAIL	Supports TAIL's U.S. dollar commercial paper program and for general corporate purposes, guaranteed by TCPL	December 2018
Demand senior unsecured revolving credit facilities
$2.1 billion	$0.6 billion	TCPL/TCPL USA	Supports the issuance of letters of credit and provides additional liquidity, TCPL USA facility guaranteed by TCPL	Demand
MXN$5.0 billion	MXN$4.9 billion	Mexican subsidiary	Used for Mexico general corporate purposes, guaranteed by TCPL	Demand

At April 23, 2018, our operated affiliates had an additional $0.4 billion of undrawn capacity on committed credit facilities.

See Financial risks and financial instruments for more information about liquidity, market and other risks.

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CONTRACTUAL OBLIGATIONS

Our capital expenditure commitments have increased by approximately $1.5 billion since December 31, 2017. Increased commitments for Columbia Gas growth projects, as well as our proportionate share of commitments for the ongoing construction of the Sur de Texas natural gas pipeline and the Bruce Power six-unit life extension program, were partially offset by decreased commitments for the Napanee power generating facility.

There were no other material changes to our contractual obligations in first quarter2018 or to payments due in the next five years or after. See the MD&A in our 2017 Annual Report for more information about our contractual obligations.

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Financial risks and financial instruments

We are exposed to liquidity risk, counterparty credit risk and market risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value. These are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance.

See our 2017 Annual Report for more information about the risks we face in our business. Our risks have not changed substantially since December 31, 2017, other than as described below.

On March 1, 2018, as part of the continued wind down of our U.S. power marketing operations, we closed the sale of our U.S. power retail contracts for proceeds of approximately US$23 million and recognized income of US$10 million (US$7 million after tax). We expect to realize the value of the remaining marketing contracts and working capital over time. As a result, our exposure to commodity risk has been reduced.

LIQUIDITY RISK

We manage our liquidity risk by continuously forecasting our cash flow for a 12-month period to ensure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.

COUNTERPARTY CREDIT RISK

We have exposure to counterparty credit risk in the following areas:

• accounts receivable

• the fair value of derivative assets

• cash and cash equivalents

• loans receivable.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. At March 31, 2018, we had no significant credit losses, no significant credit risk concentration and no significant amounts past due or impaired.

We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.

LOAN RECEIVABLE FROM AFFILIATE

We hold a 60 per cent equity interest in a joint venture with IEnova to build, own and operate the Sur de Texas pipeline. We account for the joint venture as an equity investment.

In April 2017, we entered into a MXN$13.6 billion unsecured revolving credit facility with the joint venture, which bears interest at a floating rate and matures in March 2022. In December 2017, an amended agreement was entered into to increase the credit facility to MXN$21.3 billion. Draws on the credit facility result in a loan receivable from the joint venture representing our proportionate share of the debt financing requirements advanced to the joint venture. At March 31, 2018, the balance of our loan receivable from the joint venture totaled $1.2 billion (December 31, 2017 - $919 million) and Interest income and other of $27 million for the three months endedMarch 31, 2018 (2017 - nil). Interest income and other is offset by a corresponding proportionate share of interest expense recorded in Income from equity investments.

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FOREIGN EXCHANGE

We generate revenues and incur expenses that are denominated in currencies other than Canadian dollars. As a result, our earnings and cash flows are exposed to currency fluctuations.

A portion of our businesses generate earnings in U.S. dollars, but since we report our financial results in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.

INTEREST RATE RISK

We utilize short-term and long-term debt to finance our operations which subjects us to interest rate risk. We typically pay fixed rates of interest on our long-term debt and floating rates on our commercial paper programs and amounts drawn on our credit facilities. A small portion of our long-term debt is at floating interest rates. In addition, TransCanada is exposed to interest rate risk on financial instruments and contractual obligations containing variable interest rate components. We mitigate our interest rate risk using a combination of interest rate swaps and option derivatives.

Average exchange rate - U.S. to Canadian dollars

The average exchange rate for one U.S. dollar converted into Canadian dollars was as follows:

three months ended March 31, 2018	1.27
three months ended March 31, 2017	1.32

The impact of changes in the value of the U.S. dollar on our U.S. operations is partially offset by interest on U.S. dollar-denominated long-term debt, as set out in the table below. Comparable EBIT is a non-GAAP measure. See our Reconciliation of non-GAAP measures section for more information.

Significant U.S. dollar-denominated amounts

	three months ended March 31
(unaudited - millions of US$)	2018		2017
U.S. Natural Gas Pipelines comparable EBIT	513		431
Mexico Natural Gas Pipelines comparable EBIT1	130		89
U.S. Liquids Pipelines comparable EBIT	202		135
U.S. Power comparable EBIT	6		54
AFUDC on U.S. dollar-denominated projects	67		38
Interest on U.S. dollar-denominated long-term debt	(314	)	(317	)
Capitalized interest on U.S. dollar-denominated capital expenditures	3		—
U.S. dollar non-controlling interests and other	(80	)	(70	)
	527		360

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

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Net investment hedge

We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options.

The fair values and notional amounts for the derivatives designated as a net investment hedge were as follows:

	March 31, 2018			December 31, 2017
(unaudited - millions of Canadian $, unless noted otherwise)	Fair value1,2		Notional amount	Fair value1,2		Notional amount
U.S. dollar cross-currency interest rate swaps (maturing 2018 to 2019)3	(132	)	US 800	(199	)	US 1,200
U.S. dollar foreign exchange options (maturing 2018)	(2	)	US 300	5		US 500
	(134	)	US 1,100	(194	)	US 1,700

1 Fair values equal carrying values.

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

3 In the three months endedMarch 31, 2018, Net income includes net realized gains of $1 million (2017 - $1 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:

(unaudited - millions of Canadian $, unless noted otherwise)	March 31, 2018	December 31, 2017
Notional amount	26,200 (US 20,300)	25,400 (US 20,200)
Fair value	29,000 (US 22,500)	28,900 (US 23,100)

FINANCIAL INSTRUMENTS

With the exception of Long-term debt and Junior subordinated notes, our derivative and non-derivative financial instruments are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.

Derivative instruments

We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify and are designated for hedge accounting treatment. 

The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.

Balance sheet presentation of derivative instruments

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

(unaudited - millions of $)	March 31, 2018		December 31, 2017
Other current assets	132		332
Intangible and other assets	72		73
Accounts payable and other	(301	)	(387	)
Other long-term liabilities	(80	)	(72	)
	(177	)	(54	)

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Unrealized and realized (losses)/gains of derivative instruments

The following summary does not include hedges of our net investment in foreign operations.

	three months ended March 31
(unaudited - millions of $)	2018		2017
Derivative instruments held for trading1
Amount of unrealized (losses)/gains in the period
Commodities2	(109	)	(56	)
Foreign exchange	(79	)	15
Interest rate	—		1
Amount of realized gains/(losses) in the period
Commodities	110		(48	)
Foreign exchange	15		(4	)
Derivative instruments in hedging relationships
Amount of realized gains in the period
Commodities	3		6
Foreign exchange	—		5
Interest rate	1		1

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

2 In the three months endedMarch 31, 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 (2017 - nil).

Derivatives in cash flow hedging relationships

The components of the Condensed consolidated statement of OCI related to derivatives in cash flow hedging relationships including the portion attributable to non-controlling interests is as follows:

	three months ended March 31
(unaudited - millions of $)	2018		2017
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Commodities	(3	)	5
Interest rate	9		1
	6		6
Reclassification of (losses)/gains on derivative instruments from AOCI to net income1
Commodities2	(1	)	(4	)
Interest rate3	5		4
	4		—

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

2 Reported within Revenues on the Condensed consolidated statement of income.

3 Reported within Interest expense on the Condensed consolidated statement of income.

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Credit risk related contingent features of derivative instruments

Derivatives often contain financial assurance provisions that may require us to provide collateral if a credit risk related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits.

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

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

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Other information

CONTROLS AND PROCEDURES

Management, including our President and CEO and our CFO, evaluated the effectiveness of our disclosure controls and procedures as at March 31, 2018, as required by the Canadian securities regulatory authorities and by the SEC, and concluded that our disclosure controls and procedures are effective at a reasonable assurance level.

There were no changes in first quarter 2018 that had or are likely to have a material impact on our internal control over financial reporting.

CRITICAL ACCOUNTING ESTIMATES AND ACCOUNTING POLICY CHANGES

When we prepare financial statements that conform with U.S. GAAP, we are required to make estimates and assumptions that affect the timing and amounts we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgement. We also regularly assess the assets and liabilities themselves. A summary of our critical accounting estimates is included in our 2017 Annual Report.

Our significant accounting policies have remained unchanged since December 31, 2017 other than described below. A summary of our significant accounting policies is included in our 2017 Annual Report.

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 our "performance obligations." The total consideration to which we expect to be entitled can include fixed and variable amounts. We have variable revenue that is subject to factors outside of our influence, such as market prices, actions of third parties and weather conditions. We consider this variable revenue to be "constrained" as it cannot be reliably estimated, and therefore recognize 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.

In the application of the new guidance, significant estimates and judgments are used to determine the following:

• pattern of revenue recognition, whether the performance obligation is satisfied at a point in time versus over time within a contract

• term of the contract

• amount of variable consideration associated with a contract and timing of the associated revenue recognition.

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.

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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 us 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 our 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 an intra-entity asset transfer when the transfer occurs. The new guidance was effective January 1, 2018, was applied using a modified retrospective approach, and did not have a material impact on our consolidated financial statements.

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 year and end of year 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 our 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 our 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 consolidated statement of income. This new guidance is effective January 1, 2019, with early adoption permitted. This new guidance, which we elected to adopt effective January 1, 2018, was applied prospectively and did not have a material impact on our consolidated financial statements.

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 lessor 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. Leases will be

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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.

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 the practical expedient consistently to all of its existing or expired land easements not previously accounted for as leases. We continue to monitor and analyze additional guidance and clarifications provided by the FASB.

The new guidance is effective January 1, 2019, with early adoption permitted. A modified retrospective transition approach is required for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are continuing to identify and analyze existing lease agreements to determine the effect of application of the new guidance on our consolidated financial statements. We have also selected a system solution and continue to assess process changes necessary to compile the information to meet the recognition and disclosure requirements of the new guidance.

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. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our 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 and will be applied prospectively, however, early adoption is permitted. We are currently evaluating the timing and impact of the adoption of this guidance.

Amortization on purchased callable debt securities

In March 2017, the FASB issued new guidance that shortens the amortization period for the premium on certain purchased callable debt securities by requiring entities to amortize the premium to the earliest call date. This new guidance is effective January 1, 2019 and will be applied using a modified retrospective approach. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Income Taxes

In February 2018, the FASB issued new guidance that allows a reclassification from AOCI to retained earnings for stranded tax effects resulting from the U.S. Tax Cuts and Jobs Act. This new guidance is effective January 1, 2019, however, early adoption is permitted. 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. We are currently evaluating this guidance.

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Reconciliation of non-GAAP measures

	three months ended March 31
(unaudited - millions of $)	2018		2017
Comparable EBITDA
Canadian Natural Gas Pipelines	494		504
U.S. Natural Gas Pipelines	804		720
Mexico Natural Gas Pipelines	160		140
Liquids Pipelines	431		312
Energy	184		305
Corporate	(2	)	(4	)
Comparable EBITDA	2,071		1,977
Depreciation and amortization	(535	)	(510	)
Comparable EBIT	1,536		1,467
Specific items:
Risk management activities1	(109	)	(56	)
Foreign exchange loss – inter-affiliate loan	(79	)	—
Integration and acquisition related costs – Columbia	—		(39	)
Loss on sales of U.S. Northeast power generation assets	—		(11	)
Keystone XL asset costs	—		(8	)
Segmented earnings	1,348		1,353

1	Risk management activities	three months ended March 31
	(unaudited - millions of $)	2018		2017
	Liquids marketing	(7	)	—
	Canadian Power	2		1
	U.S. Power	(101	)	(62	)
	Natural Gas Storage	(3	)	5
	Total unrealized losses from risk management activities	(109	)	(56	)

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Quarterly results

SELECTED QUARTERLY CONSOLIDATED FINANCIAL DATA

	2018		2017								2016
(unaudited - millions of $, except per share amounts)	First		Fourth		Third		Second		First		Fourth			Third			Second
Revenues	3,424		3,617		3,195		3,230		3,407		3,635			3,642			2,756
Net income/(loss) attributable to common shares	734		861		612		881		643		(358		)	(135		)	365
Comparable earnings	870		719		614		659		698		626			622			366
Per share statistics
Net income/(loss) per common share - basic and diluted		$0.83		$0.98		$0.70		$1.01		$0.74		($0.43	)		($0.17	)		$0.52
Comparable earnings per common share		$0.98		$0.82		$0.70		$0.76		$0.81		$0.75			$0.78			$0.52
Dividends declared per common share		$0.69		$0.625		$0.625		$0.625		$0.625		$0.565			$0.565			$0.565

FACTORS AFFECTING QUARTERLY FINANCIAL INFORMATION BY BUSINESS SEGMENT

Quarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments.

In our Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines segments, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:

• regulators' decisions

• negotiated settlements with shippers

• acquisitions and divestitures

• developments outside of the normal course of operations

• newly constructed assets being placed in service.

In Liquids Pipelines, annual revenues and net income are based on contracted and uncommitted spot transportation and liquids marketing activities. Quarter-over-quarter revenues and net income are affected by:

• regulatory decisions

• developments outside of the normal course of operations

• newly constructed assets being placed in service

• demand for uncontracted transportation services

• liquids marketing activities

• certain fair value adjustments.

In Energy, quarter-over-quarter revenues and net income are affected by:

• weather

• customer demand

• market prices for natural gas and power

• capacity prices and payments

• planned and unplanned plant outages

• acquisitions and divestitures

• certain fair value adjustments

• developments outside of the normal course of operations

• newly constructed assets being placed in service.

TRANSCANADA [44

FIRST QUARTER 2018

FACTORS AFFECTING FINANCIAL INFORMATION BY QUARTER

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.

Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain 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 part of our underlying operations.

In fourth quarter 2017, comparable earnings also excluded:

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

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

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

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

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

In third quarter 2017, comparable earnings also excluded:

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

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

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

In second quarter 2017, comparable earnings also excluded:

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

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

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

In first quarter 2017, comparable earnings also excluded:

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

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

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

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

TRANSCANADA [45

FIRST QUARTER 2018

In fourth quarter 2016, comparable earnings also excluded:

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

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

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

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

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

In third quarter 2016, comparable earnings also excluded:

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

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

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

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

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

In second quarter 2016, comparable earnings also excluded:

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

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

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