Management's discussion and analysis

February 14, 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 year ended December 31, 2017.

This MD&A should be read with our accompanying December 31, 2017 audited consolidated financial statements and notes for the same period, which have been prepared in accordance with U.S. generally accepted accounting principles (GAAP).

Contents

ABOUT THIS DOCUMENT		6
ABOUT OUR BUSINESS		10
	•  Three core businesses	11
	•  Our strategy	12
	•  Impact of U.S. Tax Reform	13
	•  2016 Acquisition of Columbia Pipeline Group, Inc.	14
	•  Capital program	15
	•  2017 Financial highlights	17
	•  Outlook	23
NATURAL GAS PIPELINES BUSINESS		24
CANADIAN NATURAL GAS PIPELINES		31
U.S. NATURAL GAS PIPELINES		35
MEXICO NATURAL GAS PIPELINES		40
NATURAL GAS PIPELINES BUSINESS RISKS		43
LIQUIDS PIPELINES		45
ENERGY		55
CORPORATE		65
FINANCIAL CONDITION		70
OTHER INFORMATION		83
	•  Risks and risk management	83
	•  Controls and procedures	90
	•  Critical accounting estimates	91
	•  Financial instruments	94
	•  Accounting changes	97
	•  Reconciliation of comparable EBITDA and comparable EBIT     to segmented earnings	100
	•  Quarterly results	101
GLOSSARY		108

TransCanada Management's discussion and analysis 2017 5

About this document

Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries. Abbreviations and acronyms that are not defined in the document are defined in the glossary on page 108. All information is as of February 14, 2018 and all amounts are in Canadian dollars, unless noted otherwise.

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 and 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

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

• expected capital expenditures and contractual obligations

• expected operating and financial results

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

• the expected impact of U.S. Tax Reform

• expected industry, market and economic conditions.

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.

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

Assumptions

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

• inflation rates and commodity prices

• nature and scope of hedging

• regulatory decisions and outcomes

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

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

• integrity and reliability of our assets

• access to capital markets

• anticipated construction costs, schedules and completion dates.

6  TransCanadaManagement's discussion and analysis 2017

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

• outcomes of legal proceedings, including arbitration and insurance claims

• performance and credit risk of our counterparties

• changes in market commodity prices

• changes in the political environment

• changes in environmental and other laws and regulations

• competitive factors in the pipeline and energy sectors

• construction and completion of capital projects

• costs for labour, equipment and materials

• access to capital markets

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

• weather

• cyber security

• technological developments

• economic conditions in North America as well as globally.

You can read more about these factors and others in reports we have filed with Canadian securities regulators and the SEC.

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

TransCanada Management's discussion and analysis 2017 7

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 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 and their equivalent GAAP measures.

Comparable measure	Original measure
comparable earnings	net income/(loss) attributable to common shares
comparable earnings per common share	net income/(loss) 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

Comparable earnings and comparable earnings per 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 the specific items. See the Financial highlights section for a reconciliation of net income/(loss) attributable to common shares and net income/(loss) per common share.

Comparable EBIT and comparable EBITDA

Comparable EBIT represents segmented earnings adjusted for the specific items described above. 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 Other information section for a reconciliation to segmented earnings.

8  TransCanadaManagement's discussion and analysis 2017

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

Comparable distributable cash flow and comparable distributable cash flow per 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. See the Financial condition section for a reconciliation to net cash provided by operations.

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. The majority of our U.S. natural gas pipelines can seek to recover maintenance capital expenditures through rates established in future rate cases or rate settlements. As such, these maintenance capital expenditures are effectively recovered in the same manner as expansion capital expenditures. Tolling arrangements in Liquids Pipelines provide for recovery of maintenance capital.

Effective December 31, 2017, we amended our presentation of comparable distributable cash flow and comparable distributable cash flow per share to illustrate the impact of excluding recoverable maintenance capital expenditures from their respective calculations. We have included comparable distributable cash flow and comparative distributable cash flow per share for 2016 and 2015 to reflect the amended presentation format which we believe provides better information for readers.

TransCanada Management's discussion and analysis 2017 9

About our business

With over 65 years of experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and natural gas storage facilities.

10  TransCanadaManagement's discussion and analysis 2017

THREE CORE BUSINESSES

We operate in three core businesses – Natural Gas Pipelines, Liquids Pipelines and Energy. In order to provide information that is aligned with how management decisions about our business are made and how performance of our business is assessed, our results are reflected in five operating segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. We also have a non-operational Corporate segment consisting of corporate and administrative functions that provide governance and other support to our operational business segments.

Year at a glance

at December 31
(millions of $)	2017	2016
Total assets
Canadian Natural Gas Pipelines	16,904	15,816
U.S. Natural Gas Pipelines	35,898	34,422
Mexico Natural Gas Pipelines	5,716	5,013
Liquids Pipelines	15,438	16,896
Energy1	8,503	13,169
Corporate	3,642	2,735
	86,101	88,051

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

year ended December 31
(millions of $)	2017	2016
Total revenues
Canadian Natural Gas Pipelines	3,693	3,682
U.S. Natural Gas Pipelines1	3,584	2,526
Mexico Natural Gas Pipelines	570	378
Liquids Pipelines	2,009	1,755
Energy2	3,593	4,206
	13,449	12,547

1 Includes Columbia effective July 2016.

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

year ended December 31
(millions of $)	2017		2016
Comparable EBITDA
Canadian Natural Gas Pipelines	2,144		2,182
U.S. Natural Gas Pipelines1	2,357		1,682
Mexico Natural Gas Pipelines	519		332
Liquids Pipelines	1,348		1,152
Energy2	1,030		1,281
Corporate	(21	)	18
	7,377		6,647

1 Includes Columbia effective July 2016.

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

TransCanada Management's discussion and analysis 2017 11

OUR STRATEGY

Our energy infrastructure business is made up of pipeline and power generation assets that gather, transport, produce, store or deliver natural gas, crude oil and other petroleum products and electricity to support businesses and communities in North America.

Our vision is to be the leading energy infrastructure company in North America, focusing on pipeline and power generation opportunities in regions where we have or can develop a significant competitive advantage.

Key components of our strategy at a glance

1	Maximize the full-life value of our infrastructure assets and commercial positions
	•  Long-life infrastructure assets and long-term commercial arrangements are the cornerstones of our low risk business model. •  Our pipeline assets include large-scale natural gas and crude oil pipelines that connect long-life supply basins with stable and growing markets, generating predictable and sustainable cash flow and earnings. •  In Energy, long-term power sale agreements are used to manage and optimize our portfolio and to manage price volatility.
2	Commercially develop and build new asset investment programs
	•  We are developing high quality, long-life assets under our current $47 billion capital program, comprised of $23 billion in near-term projects and $24 billion in commercially-supported medium to long-term projects. These will contribute incremental earnings and cash flow over the near, medium and long terms as our investments are placed in service. •  Our expertise in project development, managing construction risks and maximizing capital productivity ensures a disciplined approach to reliability, cost and schedule, resulting in superior service for our customers and returns to shareholders. •  As part of our growth strategy, we rely on this experience and our regulatory, commercial, financial, legal and operational expertise to successfully build and integrate new pipeline and other energy facilities. •  We are able to balance safety, profitability and social and environmental responsibility in our investing activities.
3	Cultivate a focused portfolio of high quality development and investment options
	•  We assess opportunities to develop and acquire energy infrastructure that complements our existing portfolio and diversifies access to attractive supply and market regions. •  We focus on pipeline and energy growth initiatives in core regions of North America and prudently manage development costs, minimizing capital-at-risk in early stages of projects. •  We will advance selected opportunities to full development and construction when market conditions are appropriate and project risks and returns are acceptable.
4	Maximize our competitive strengths
	•  We are continually refining core competencies in areas such as safety, operational excellence, supply chain management, project execution and stakeholder management to ensure we provide maximum shareholder value over the short, medium and long terms.

A competitive advantage

Years of experience in the energy infrastructure business and a disciplined approach to project management and capital

 investment give us our competitive edge.

• Strong leadership: scale, presence, operating capabilities and strategy development; expertise in regulatory, legal,

     commercial and financing support.

•  High quality portfolio: a low-risk and enduring business model that maximizes the full-life value of our long-life assets

     and commercial positions throughout all points in the business cycle.

•  Disciplined operations: highly skilled in designing, building and operating energy infrastructure with a focus on

     operational excellence and a commitment to health, safety and the environment which are paramount parts of our

     core values.

•  Financial positioning: consistently strong financial performance, long-term financial stability and profitability; disciplined

     approach to capital investment; ability to access sizable amounts of competitively priced capital to support our growth;

     simplicity and understandability of our business and corporate structure; ability to balance an increasing dividend on

     our common shares while preserving financial flexibility to fund our capital program in all market conditions.

•  Long-term relationships: long-term, transparent relationships with key customers and stakeholders; clear communication

     of our prospects to equity and fixed income investors – both the upside and the risks – to build trust and support.

12  TransCanadaManagement's discussion and analysis 2017

U.S. TAX REFORM

On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act (U.S. Tax Reform or the Act) 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, we have remeasured existing deferred income tax assets and deferred income tax liabilities related to our U.S. businesses to reflect the new lower income tax rate as at December 31, 2017.

For our businesses in the U.S. not subject to rate-regulated accounting (RRA), the reduction in enacted tax rates has been recorded as a decrease in net deferred income tax liabilities and income tax expense, resulting in an increase in net income attributable to common shares for the year ended December 31, 2017 in the amount of $816 million.

For our businesses in the U.S. subject to RRA, we expect the lower income tax rates to impact future rate setting processes and have therefore recognized a net regulatory liability with a corresponding reduction in net deferred income tax liabilities in the amount of $1,686 million. These regulatory liabilities will be amortized to earnings over time.

Net deferred income tax liabilities related to the cumulative remeasurements of employee post-retirement benefits included in accumulated other comprehensive income have also been adjusted with a corresponding increase in deferred income tax expense of $12 million.

Given the significance of the legislation, the SEC issued guidance which allows registrants to record provisional amounts which may be adjusted as information becomes available, prepared or analyzed during a measurement period not to exceed one year.

The SEC guidance summarizes a three-step process to be applied at each reporting period to identify: (1) where the accounting is complete; (2) provisional amounts where the accounting is not yet complete, but a reasonable estimate has been determined; and (3) where a reasonable estimate cannot yet be determined and therefore income taxes are reflected in accordance with tax laws in effect prior to the enactment of the Act.

At December 31, 2017, we consider all amounts recorded related to U.S. Tax Reform to be reasonable estimates. Amounts related to businesses subject to RRA are provisional as our interpretation, assessment and presentation of the impact of the tax law change 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, we will review the provisional amounts and adjust as appropriate.

As a result of the lower U.S. income tax rates included as part of the Act, we expect a modest increase to 2018 earnings. In addition to the reduction in statutory rates, longer-term there are several other provisions in the new legislation which may impact us prospectively, including changes to the expensing of depreciable property, limitations to interest deductions, the creation of Base Erosion Anti-Abuse Tax along with certain exemptions for rate-regulated businesses. We continue to evaluate the impact of these and other provisions of the Act.

TransCanada Management's discussion and analysis 2017 13

2016 ACQUISITION OF COLUMBIA PIPELINE GROUP, INC.

On July 1, 2016, we acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash. The acquisition was initially financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, following the closing of the acquisition, were exchanged into 96.6 million TransCanada common shares.

At the date of acquisition, Columbia operated approximately 24,500 km (15,200 miles) of regulated natural gas pipelines, 285 Bcf of natural gas storage facilities and related midstream assets. We acquired Columbia to expand our natural gas business in the U.S. market, positioning ourselves for additional long-term growth opportunities. The acquisition also included a large portfolio of new capital growth projects including seven significant pipeline expansions designed to transport growing supply from the Marcellus/Utica production basins to markets, as well as a scheduled program for modernization of existing infrastructure through 2020 to ensure the continuation of a safe, reliable and efficient system.

While Columbia Pipeline Group, Inc. was the overall corporate entity we acquired, we now make reference to specific businesses obtained through the acquisition including: Columbia Gas, Columbia Gulf, Millennium, Crossroads, Midstream and Columbia Storage.

As part of the financing plan for the Columbia acquisition, we announced the planned monetization of our U.S. Northeast power business, including our U.S. Northeast power marketing business. Subsequently, we issued additional common shares to support the permanent financing of the acquisition and announced an agreement to acquire all of the outstanding publicly held common units of Columbia Pipeline Partners LP (CPPL).

Common shares and subscription receipts issued under public offerings

On April 1, 2016, we issued 96.6 million subscription receipts entitling each holder to receive one common share upon closing of the Columbia acquisition to partially fund the Columbia acquisition at a price of $45.75 each for gross proceeds of $4.4 billion. Holders of subscription receipts received one common share in exchange for each subscription receipt on July 1, 2016 upon closing of the acquisition.

On November 16, 2016, we issued 60.2 million common shares at a price of $58.50 each for gross proceeds of approximately $3.5 billion. Proceeds from the offering were used to repay a portion of the US$6.9 billion acquisition bridge facilities which were drawn to partially finance the closing of the Columbia acquisition.

Columbia Pipeline Partners LP

In February 2017, we completed the acquisition, for cash, of all outstanding publicly held common units of CPPL for an aggregate transaction value of US$921 million. See the U.S. Natural Gas Pipelines Significant events section for further information.

Monetization of U.S. Northeast power business

In April 2017, we closed the sale of TC Hydro for US$1.07 billion, before post-closing adjustments, and in June 2017, we closed the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind for US$2.029 billion, before post-closing adjustments. Proceeds from these sales were used to fully retire the remaining bridge facilities that partially funded the acquisition of Columbia.

In December 2017, we entered into an agreement to sell our U.S. power retail contracts as part of the continued wind down of our U.S. power marketing operations. The transaction is expected to close in the first quarter of 2018 subject to regulatory and other approvals.

See the Energy Significant events section for further information.

14  TransCanadaManagement's discussion and analysis 2017

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 $23 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 December 31, 2017
(billions of $)
Canadian Natural Gas Pipelines
Canadian Mainline	2018 - 2021	0.2	—
NGTL System	2018	0.6	0.2
	2019	2.3	0.3
	2020	1.6	0.1
	2021	2.7	—
U.S. Natural Gas Pipelines
Columbia Gas
Leach XPress1	2018	US 1.6	US 1.5
WB XPress	2018	US 0.8	US 0.4
Mountaineer XPress	2018	US 2.6	US 0.5
Modernization II	2018 - 2020	US 1.1	US 0.1
Buckeye XPress	2020	US 0.2	—
Columbia Gulf
Cameron Access	2018	US 0.3	US 0.3
Gulf XPress	2018	US 0.6	US 0.2
Other2	2018 - 2020	US 0.3	—
Mexico Natural Gas Pipelines
Sur de Texas3	2018	US 1.3	US 1.0
Villa de Reyes	2018	US 0.8	US 0.5
Tula	2019	US 0.7	US 0.5
Liquids Pipelines
White Spruce	2019	0.2	—
Energy
Napanee	2018	1.3	0.9
Bruce Power– life extension4	up to 2020	0.9	0.3
		20.1	6.8
Foreign exchange impact on near-term projects5		2.6	1.3
Total near-term projects (billions of Cdn$)		22.7	8.1

1 Leach XPress was placed in service in January 2018.

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

3 Our proportionate share.

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

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

TransCanada Management's discussion and analysis 2017 15

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 applicable 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. Please refer to each business segment's Significant events section for further information on these projects.

	Segment	Estimated project cost	Carrying value at December 31, 2017
(billions of $)
Heartland and TC Terminals1	Liquids Pipelines	0.9	0.1
Grand Rapids Phase 22	Liquids Pipelines	0.7	—
Bruce Power – life extension2	Energy	5.3	—
Keystone projects
Keystone XL3	Liquids Pipelines	US 8.0	US 0.3
Keystone Hardisty Terminal1,3	Liquids Pipelines	0.3	0.1
BC west coast LNG-related projects
Coastal GasLink	Canadian Natural Gas Pipelines	4.8	0.4
NGTL System – Merrick	Canadian Natural Gas Pipelines	1.9	—
		21.9	0.9
Foreign exchange impact on medium to longer-term projects4		2.0	0.1
Total medium to longer-term projects (billions of Cdn$)		23.9	1.0

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

2 Our proportionate share.

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

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

16  TransCanadaManagement's discussion and analysis 2017

2017 FINANCIAL HIGHLIGHTS

We use certain financial measures that do not have a standardized meaning under GAAP because we believe they improve our ability to compare results between reporting periods and enhance understanding of our operating performance. Known as non-GAAP measures, they may not be similar to measures provided by other companies.

Comparable EBITDA (comparable earnings before interest, taxes, depreciation and amortization), comparable EBIT (comparable earnings before interest and taxes), 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 page 8 for more information about the non-GAAP measures we use and pages 72 and 100 for reconciliations to the GAAP equivalents.

year ended December 31
(millions of $, except per share amounts)	2017		2016		2015
Income
Revenues	13,449		12,547		11,353
Net income/(loss) attributable to common shares	2,997		124		(1,240		)
per common share – basic		$3.44		$0.16		($1.75	)
– diluted		$3.43		$0.16		($1.75	)
Comparable EBITDA	7,377		6,647		5,908
Comparable earnings	2,690		2,108		1,755
per common share		$3.09		$2.78		$2.48
Cash flows
Net cash provided by operations	5,230		5,069		4,384
Comparable funds generated from operations	5,641		5,171		4,815
Comparable distributable cash flow
– reflecting all maintenance capital expenditures	3,599		3,541		3,457
– reflecting only non-recoverable maintenance capital expenditures	4,963		4,482		4,243
Comparable distributable cash flow per common share
– reflecting all maintenance capital expenditures		$4.13		$4.67		$4.88
– reflecting only non-recoverable maintenance capital expenditures		$5.69		$5.91		$5.98
Capital spending1	9,210		6,067		4,922
Acquisitions, net of cash acquired	—		13,608		236
Proceeds from sales of assets, net of transaction costs	5,317		6		—
Balance sheet
Total assets	86,101		88,051		64,398
Long-term debt	34,741		40,150		31,456
Junior subordinated notes	7,007		3,931		2,409
Preferred shares	3,980		3,980		2,499
Non-controlling interests	1,852		1,726		1,717
Common shareholders' equity	21,059		20,277		13,939
Dividends declared2
per common share		$2.50		$2.26		$2.08
Basic common shares (millions)
– weighted average	872		759		709
– issued and outstanding	881		864		703

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

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

TransCanada Management's discussion and analysis 2017 17

Consolidated results

year ended December 31
(millions of $, except per share amounts)	2017			2016			2015
Segmented earnings/(losses)
Canadian Natural Gas Pipelines	1,236			1,307			1,367
U.S. Natural Gas Pipelines	1,760			1,190			597
Mexico Natural Gas Pipelines	426			287			169
Liquids Pipelines	(251		)	806			(2,661		)
Energy	1,552			(1,157		)	781
Corporate	(39		)	(120		)	(152		)
Total segmented earnings	4,684			2,313			101
Interest expense	(2,069		)	(1,998		)	(1,370		)
Allowance for funds used during construction	507			419			295
Interest income and other	184			103			(132		)
Income/(loss) before income taxes	3,306			837			(1,106		)
Income tax recovery/(expense)	89			(352		)	(34		)
Net income/(loss)	3,395			485			(1,140		)
Net income attributable to non-controlling interests	(238		)	(252		)	(6		)
Net income/(loss) attributable to controlling interests	3,157			233			(1,146		)
Preferred share dividends	(160		)	(109		)	(94		)
Net income/(loss) attributable to common shares	2,997			124			(1,240		)
Net income/(loss) per common share
–basic		$3.44			$0.16			($1.75	)
–diluted		$3.43			$0.16			($1.75	)

Net income attributable to common shares in 2017 was $2,997 million or $3.44 per share (2016 – $124 million or $0.16 per share; 2015 – loss of $1,240 million or $1.75 per share). Net income per common share increased by $3.28 per share in 2017 compared to 2016 due to the changes in net income described below, as well as the dilutive effect of issuing 161 million common shares in 2016 and common shares issued under our DRP and corporate ATM program in 2017.

The following specific items were recognized in net income/(loss) attributable to common shares and were excluded from comparable earnings in the relevant periods:

2017

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

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

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

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

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

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

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

18  TransCanadaManagement's discussion and analysis 2017

2016

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

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

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

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

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

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

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

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

2015

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

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

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

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

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

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

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

Net income in all periods included unrealized gains and losses from changes in risk management activities which we exclude, along with the above noted items, to arrive at comparable earnings. A reconciliation of net income/(loss) attributable to common shares to comparable earnings is shown in the following table.

Refer to the Results section in each business segment and the Financial condition section of this MD&A for further discussion of these highlights.

TransCanada Management's discussion and analysis 2017 19

Reconciliation of net income/(loss) to comparable earnings

year ended December 31
(millions of $, except per share amounts)	2017			2016			2015
Net income/(loss) attributable to common shares	2,997			124			(1,240		)
Specific items (net of tax):
U.S. Tax Reform adjustment	(804		)	—			—
Net (gain)/loss on sales of U.S. Northeast power assets	(307		)	873			—
Gain on sale of Ontario solar assets	(136		)	—			—
Energy East impairment charge	954			—			—
Integration and acquisition related costs – Columbia	69			273			—
Keystone XL asset costs	28			42			—
Keystone XL income tax recoveries	(7		)	(28		)	—
Ravenswood goodwill impairment	—			656			—
Alberta PPA terminations and settlement	—			244			—
Restructuring costs	—			16			74
TC Offshore loss on sale	—			3			86
Keystone XL impairment charge	—			—			2,891
Turbine equipment impairment charge	—			—			43
Alberta corporate income tax rate increase	—			—			34
Bruce Power merger – debt retirement charge	—			—			27
Non-controlling interests (TC PipeLines, LP – Great Lakes impairment)	—			—			(199		)
Risk management activities1	(104		)	(95		)	39
Comparable earnings	2,690			2,108			1,755
Net income/(loss) per common share		$3.44			$0.16			($1.75	)
Specific items (net of tax):
U.S. Tax Reform adjustment	(0.92		)	—			—
Net (gain)/loss on sales of U.S. Northeast power assets	(0.34		)	1.15			—
Gain on sale of Ontario solar assets	(0.16		)	—			—
Energy East impairment charge	1.09			—			—
Integration and acquisition related costs – Columbia	0.08			0.37			—
Keystone XL asset costs	0.03			0.06			—
Keystone XL income tax recoveries	(0.01		)	(0.04		)	—
Ravenswood goodwill impairment	—			0.86			—
Alberta PPA terminations and settlement	—			0.32			—
Restructuring costs	—			0.02			0.10
TC Offshore loss on sale	—			—			0.12
Keystone XL impairment charge	—			—			4.08
Turbine equipment impairment charge	—			—			0.06
Alberta corporate income tax rate increase	—			—			0.05
Bruce Power merger – debt retirement charge	—			—			0.04
Non-controlling interests (TC PipeLines, LP – Great Lakes impairment)	—			—			(0.28		)
Risk management activities	(0.12		)	(0.12		)	0.06
Comparable earnings per common share		$3.09			$2.78			$2.48

20  TransCanadaManagement's discussion and analysis 2017

1	year ended December 31
	(millions of $)	2017		2016		2015
	Canadian Power	11		4		(8	)
	U.S. Power	39		113		(30	)
	Liquids marketing	—		(2	)	—
	Natural Gas Storage	12		8		1
	Interest rate	(1	)	—		—
	Foreign exchange	88		26		(21	)
	Income taxes attributable to risk management activities	(45	)	(54	)	19
	Total unrealized gains/(losses) from risk management activities	104		95		(39	)

Comparable earnings

Comparable earnings per share in 2017 and 2016 were impacted by the dilutive effect of issuing 161 million common shares in 2016 and common shares issued under our DRP and corporate ATM program in 2017. See the Financial condition section of this MD&A for further information on common share issuances.

Comparable earnings in 2017 were $582 millionhigher than 2016, resulting in an increase of $0.31 per common share. The 2017increase in comparable earnings was primarily the net result of:

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

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

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

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

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

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

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

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

Comparable earnings in 2016 were $353 millionhigher than 2015, resulting in an increase of $0.30 per common share. The 2016increase in comparable earnings was primarily the net result of:

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

• higher interest expense from debt issuances and lower capitalized interest

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

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

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

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

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

TransCanada Management's discussion and analysis 2017 21

Cash flows

Net cash provided by operations of $5.2 billion and comparable funds generated from operations of $5.6 billion were three per cent and nine per cent higher, respectively, in 2017 compared to 2016, primarily due to higher comparable earnings, as described above. In addition, net cash provided by operations was affected by the amount and timing of working capital changes.

Comparable distributable cash flow, reflecting the impact of all maintenance capital expenditures, was $3.6 billion in 2017 compared to $3.5 billion in 2016, primarily due to higher comparable funds generated from operations partially offset by higher maintenance capital. Comparable distributable cash flow, reflecting only non-recoverable maintenance capital, was $5.0 billion in 2017 compared to $4.5 billion in 2016 due primarily to higher comparable funds generated from operations. Comparable distributable cash flow per common share was also impacted by common share issuances in 2016 and 2017. See the Financial condition section for more information on the calculation of comparable distributable cash flow.

Funds used in investing activities

Capital spending¹ 

year ended December 31
(millions of $)	2017	2016	2015
Canadian Natural Gas Pipelines	2,181	1,525	1,596
U.S. Natural Gas Pipelines	3,830	1,522	537
Mexico Natural Gas Pipelines	1,954	1,142	566
Liquids Pipelines	529	1,137	1,601
Energy	675	708	558
Corporate	41	33	64
	9,210	6,067	4,922

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

We invested $9.2 billion in capital projects in 2017 to optimize the value of our existing assets and develop new, complementary assets in high demand areas. Our total capital spending in 2017 included contributions of $1.7 billion to our equity investments primarily related to Sur de Texas, Bruce Power, Grand Rapids and Northern Border.

Proceeds from sales of assets

In 2017, we completed the sales of TC Hydro, Ravenswood, Ironwood, Kibby Wind and Ocean State Power for net proceeds of approximately US$3.1 billion, before post-closing adjustments. We also closed the sale of our Ontario solar assets for $541 million, before post-closing adjustments.

Balance sheet

We continue to maintain a solid financial position while growing our total assets by $21.7 billion since 2015. At December 31, 2017, common shareholders' equity represented 33 per cent (31 per cent in 2016) of our capital structure, while other subordinated capital, in the form of junior subordinated notes and preferred shares, represented an additional 16 per cent (12 per cent in 2016). See Financial condition for more information about our capital structure.

Dividends

We increased the quarterly dividend on our outstanding common shares by 10.4 per cent to $0.69 per common share for the quarter ending March 31, 2018 which equates to an annual dividend of $2.76 per common share. This is the 18th consecutive year we have increased the dividend on our common shares and reflects our commitment to growing our common dividend at an average annual rate at the upper end of eight to ten per cent through 2020 and an additional eight to ten per cent in 2021.

Dividend reinvestment plan

Under our DRP, eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. Under this program, common shares are issued from treasury at a discount of two per cent to market prices over a specified period rather than purchased on the open markets to satisfy participation in the DRP.

22  TransCanadaManagement's discussion and analysis 2017

Cash dividends paid

year ended December 31
(millions of $)	2017	2016	2015
Common shares	1,339	1,436	1,446
Preferred shares	155	100	92

OUTLOOK

Earnings

Our 2018 earnings, after excluding specific items, are expected to be higher than 2017 primarily due to the impact of the following:

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

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

• completion of the Napanee power plant in Ontario

• growth in the average investment base for the NGTL System

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

Partially offset by:

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

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

• discontinuation of AFUDC on Energy East and related projects

• decrease in Canadian Mainline average investment base.

See relevant business segment outlook for additional details.

Consolidated capital spending and equity investments

We expect to spend approximately $9 billion in 2018 on growth projects, maintenance capital and contributions to equity investments. The majority of the anticipated 2018 capital program will be focused on U.S., Canadian and Mexico natural gas pipeline growth projects and maintenance, with additional capital spend attributable to completing construction on Napanee and contributions to the Bruce Power life extension program and maintenance.

TransCanada Management's discussion and analysis 2017 23

NATURAL GAS PIPELINES BUSINESS

Our natural gas pipeline network transports natural gas from supply basins to local distribution companies, power generation and individual facilities, interconnecting pipelines and other businesses across Canada, the U.S. and Mexico. Our network of pipelines taps into virtually every major supply basin and transports over 25 per cent of continental daily natural gas needs through:

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

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

In addition to our interstate natural gas pipelines, we have regulated natural gas storage facilities in the U.S. with a total working gas capacity of 535 Bcf, making us one of the largest providers of natural gas storage and related services to key markets in North America. We also own and manage midstream services that provide specific natural gas producer services including gathering, treatment, conditioning, processing and liquids handling with a focus on the Appalachian Basin.

Our Natural Gas Pipelines business is split into three operating segments representing its geographic diversity: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines.

Strategy at a glance

Optimizing the value of our existing natural gas pipeline systems, while responding to the changing flow patterns of natural gas in North America, is a top priority.

We are also pursuing new pipeline opportunities to add incremental value to our business. Our key areas of focus include:

•   expansion and extension of our existing large North American natural gas pipeline footprint

•   connections to new and growing industrial, LDC, LNG export, interconnect and electric power generation markets

•  connections to growing Canadian and U.S. shale gas and other supplies

•   additional new pipeline developments within Mexico

•   greenfield development projects, such as infrastructure for LNG exports from the west coast of Canada and the Gulf of

       Mexico

Each of these areas plays a critical role in meeting the transportation requirements for supply and demand for natural gas in North America.

Highlights

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

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

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

• In July 2017, we were notified that Pacific Northwest (PNW) LNG would not be proceeding with their proposed LNG project and that Progress Energy would be terminating their agreement with us for development of the Prince Rupert Gas Transmission (PRGT) project. In accordance with the terms of the agreement, we received a payment of $0.6 billion from Progress Energy in October 2017 for full recovery of our costs plus carrying charges.

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

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

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

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

24  TransCanadaManagement's discussion and analysis 2017

UNDERSTANDING OUR NATURAL GAS PIPELINES BUSINESS

Natural gas pipelines move natural gas from major sources of supply to locations or markets that use natural gas to meet their energy needs.

Our natural gas pipelines business builds, owns and operates a network of natural gas pipelines across North America that connects gas production to interconnects and end use markets. The network includes underground pipelines that transport natural gas predominantly under high pressure, compressor stations that act like pumps to move the large volumes of natural gas along the pipeline, meter stations that record the amount of natural gas coming on the network at receipt locations and leaving the network at delivery locations, and natural gas storage facilities that provide services to customers and help maintain the overall balance of the pipeline systems.

Our Major Pipeline Systems

The Natural Gas Pipelines map on page 27 shows our extensive pipeline network in North America that connects major supply sources and markets. The highlights shown on the map include:

NGTL System: This is our natural gas gathering and transportation system for the WCSB, connecting most of the natural gas production in western Canada to domestic and export markets. We believe we are very well positioned to connect growing supply in northeast B.C. and northwest Alberta. It is these two supply areas, along with growing demand for firm transportation in the oil sands area and to our major export points at Empress and Alberta/B.C. delivery locations, that is driving our large capital program for new pipeline facilities. The NGTL System is also well positioned to connect WCSB supply to potential LNG export facilities on the Canadian west coast.

Canadian Mainline: This is a major pipeline that was originally designed as a long haul delivery system transporting supply from the WCSB across Canada to Ontario and Québec to deliver gas to downstream Canadian and U.S. markets. The Canadian Mainline continues this role and is also growing to accommodate additional supply connections closer to its markets.

Columbia Gas: This is our natural gas transportation system for the Appalachian Basin, which contains the Marcellus and Utica shale plays, two of the fastest growing natural gas shale plays in North America. Similar to our footprint in the WCSB, our Columbia assets are very well positioned to connect growing supply and market in this area. This system also interconnects with other pipelines that provide access to key markets in the U.S. Northeast and south to the Gulf of Mexico and its growing demand for natural gas to serve LNG exports. Access to markets from producers in the region is driving the large capital program for new pipeline facilities on this system.

ANR Pipeline System: ANR is our pipeline system that connects supply basins and markets throughout the U.S. Midwest, and south to the Gulf of Mexico. This includes connecting supply in Texas, Oklahoma, the Appalachian Basin and the Gulf of Mexico to markets in Wisconsin, Michigan, Illinois and Ohio. In addition, ANR has bi-directional capability on its Southeast Mainline and delivers gas produced from the Appalachian basin to customers throughout the Gulf Coast Region.

Columbia Gulf: This is our pipeline system originally designed as a long haul delivery system transporting supply from the Gulf of Mexico to major demand markets in the U.S. Northeast. The pipeline is now transitioning to a north-to-south flow and expanding to accommodate new supply in the Appalachian Basin and its interconnects with Columbia Gas and other pipelines to deliver gas to various Gulf Coast markets.

Mexico Pipeline Network: We also have a growing network of natural gas pipelines coupled with a large portfolio of projects under construction in Mexico, including Tula and Villa de Reyes and the 60 per cent-owned Sur de Texas pipeline project through our joint venture with IEnova.

Regulation of tolls and cost recovery

Our natural gas pipelines are generally regulated by the NEB in Canada, by the FERC in the U.S. and by the CRE in Mexico. The regulators approve construction of new pipeline facilities and ongoing operations of the infrastructure.

Regulators in Canada, the U.S. and Mexico allow us to recover costs to operate the network by collecting tolls for services. These tolls generally include a return on our capital invested in the assets or rate base, as well as the recovery of the rate base over time through depreciation. Other costs recovered include OM&A, income and property taxes and interest on debt. The regulator reviews our costs to ensure they are reasonable and prudently incurred and approves tolls that provide us a reasonable opportunity to recover those costs.

TransCanada Management's discussion and analysis 2017 25

Business environment and strategic priorities

The North American natural gas pipeline network has been developed to connect diverse supply regions to domestic markets and, increasingly, to meet demand from LNG export facilities. Use and growth of this infrastructure is affected by changes in the location and relative cost of natural gas supplies as well as changes in the location of markets and level of demand.

We have significant pipeline footprints that serve the two most prolific supply regions of North America, the WCSB and the Appalachian Basin. Our pipelines also source natural gas, to a lesser degree, from other significant basins including the Rockies, Williston, Haynesville, Fayetteville and Anadarko as well as the Gulf of Mexico. We expect continued growth in North American natural gas production to meet demand within growing domestic markets, particularly in the electric generation and industrial sectors which benefit from a relatively low natural gas price. In addition, North American supply is expected to benefit from access to international markets via LNG exports. We expect North American natural gas demand, including LNG exports, of approximately 105 Bcf/d by 2020, reflecting an increase of approximately 10 Bcf/d from 2017 levels.

This expected increased demand for natural gas, coupled with the annual decline rate of 15 per cent to 20 per cent for natural gas production, implies up to 25 Bcf/d of new production per year will be required, providing investment opportunities for pipeline infrastructure companies to build new facilities or increase utilization of the existing footprint.

Changing demand

The growing supply of natural gas has resulted in relatively low natural gas prices in North America, which has supported increased demand particularly in the following areas:

• natural gas-fired electric-power generation

• petrochemical and industrial facilities

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

• exports to Mexico to fuel power generation facilities.

Natural gas producers continue to progress opportunities to sell natural gas to global markets which involves connecting natural gas supplies to proposed LNG export terminals along the U.S. Gulf Coast and the west coast of Canada. The demand created by the addition of these new markets creates opportunities for us to build new pipeline infrastructure and to increase throughput on our existing pipelines.

Commodity prices

In general, the profitability of our natural gas pipelines business is not directly tied to commodity prices given we are a transporter of the commodity and the fixed transportation costs are not tied to the price of natural gas. However, the cyclical supply and demand nature of commodities and related pricing can have an indirect impact on our business where producers may choose to accelerate or delay exploration or, similarly on the demand side, projects requiring natural gas may be accelerated or delayed depending on market or price conditions. For example, lower natural gas prices have allowed this commodity to gain market share versus coal in serving power generation markets and to compete globally through LNG exports.

More competition

Changes in supply and demand levels and locations have resulted in increased competition for transportation services throughout North America. With our well-distributed footprint of natural gas pipelines, and particularly our new presence in the growing Appalachian region, we are well positioned to compete. Incumbent pipelines in an area benefit from owning existing right-of-way and infrastructure given the increasing challenges of siting and permitting for new pipeline construction and expansions. We have, and will continue to assess, further opportunities to restructure our tolls and service offerings to capture growing supply and North American demand that now includes access to world markets through LNG exports.

Strategic priorities

We are focused on capturing opportunities resulting from growing natural gas supply and connecting new markets while satisfying increasing demand for natural gas within existing markets. We are also focused on adapting our existing assets to the changing natural gas flow dynamics.

In 2018, one of our key focus areas will be the continued execution of our existing capital program that includes further expansion of the NGTL System as well as concluding several projects on the Columbia Gas and Gulf systems and in Mexico. Our goal is to place all of our projects in service on time and on budget while ensuring the safety of our staff, contractors, and all stakeholders impacted by the construction and operation of these facilities.

26  TransCanadaManagement's discussion and analysis 2017

TransCanada Management's discussion and analysis 2017 27

We are the operator of all of the following natural gas pipelines and regulated natural gas storage assets except for Iroquois.

		Length	Description	Effective ownership
Canadian pipelines
1	NGTL System	24,320 km (15,112 miles)	Receives, transports and delivers natural gas within Alberta and B.C., and connects with the Canadian Mainline, Foothills system and third-party pipelines.	100	%
2	Canadian Mainline	14,077 km (8,747 miles)	Transports natural gas from the Alberta/Saskatchewan border and the Ontario/U.S. border to serve eastern Canada and interconnects to the U.S.	100	%
3	Foothills	1,241 km (771 miles)	Transports natural gas from central Alberta to the U.S. border for export to the U.S. Midwest, Pacific Northwest, California and Nevada.	100	%
4	Trans Québec & Maritimes (TQM)	572 km (355 miles)	Connects with the Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montréal to Québec City corridor, and interconnects with the Portland pipeline system that serves the northeast U.S.	50	%
5	Ventures LP	161 km (100 miles)	Transports natural gas to the oil sands region near Fort McMurray, Alberta. It also includes a 27 km (17 mile) pipeline supplying natural gas to a petrochemical complex at Joffre, Alberta.	100	%
*	Great Lakes Canada	58 km (36 miles)	Transports natural gas from the Great Lakes system in the U.S. to Ontario, near Dawn, through a connection at the U.S. border underneath the St. Clair River.	100	%
U.S. pipelines
6	ANR	15,109 km (9,388 miles)	Transports natural gas from various supply basins to markets throughout the Midwest and Gulf Coast.	100	%
6a	ANR Storage	250 Bcf	Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key mid-western markets.
7	Bison	488 km (303 miles)	Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 25.7 per cent of the system through our interest in TC PipeLines, LP.	25.7	%
8	Columbia Gas	18,113 km (11,255 miles)	Transports natural gas from supply primarily in the Appalachian Basin to markets throughout the U.S. Northeast.	100	%
8a	Columbia Storage	285 Bcf	Provides regulated underground natural gas storage service from several facilities (not all shown) to customers in key eastern markets. We also own a 50 per cent interest in the 12 Bcf Hardy Storage facility.	100	%
*	Midstream	295 km (183 miles)	Provides infrastructure between the producer upstream well-head and the downstream (interstate pipeline and distribution) sector and includes a 47.5 per cent interest in Pennant Midstream.	100	%
9	Columbia Gulf	5,377 km (3,341 miles)	Transports natural gas to various markets and pipeline interconnects in the southern U.S. and Gulf Coast.	100	%
10	Crossroads	325 km (202 miles)	Interstate natural gas pipeline operating in Indiana and Ohio with multiple interconnects to other pipelines.	100	%
11	Gas Transmission Northwest (GTN)	2,216 km (1,377 miles)	Transports WCSB and Rockies natural gas to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 25.7 per cent of the system through our interest in TC PipeLines, LP.	25.7	%
12	Great Lakes	3,404 km (2,115 miles)	Connects with the Canadian Mainline near Emerson, Manitoba and to Great Lakes Canada near St Clair, Ontario, plus interconnects with ANR at Crystal Falls and Farwell in Michigan, to transport natural gas to eastern Canada and the U.S. Upper Midwest. We effectively own 65.5 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 25.7 per cent interest in TC PipeLines, LP.	65.5	%
13	Iroquois	669 km (416 miles)	Connects with the Canadian Mainline and serves markets in New York. We effectively own 13.4 per cent of the system through a 0.7 per cent direct ownership and our 25.7 per cent interest in TC PipeLines, LP.	13.4	%

28  TransCanadaManagement's discussion and analysis 2017

		Length	Description	Effective ownership
14	Millennium	407 km (253 miles)	Natural gas pipeline supplied by local production, storage fields and interconnecting upstream pipelines to serve markets along its route and to the U.S. Northeast.	47.5	%
15	North Baja	138 km (86 miles)	Transports natural gas between Arizona and California, and connects with a third-party pipeline on the California/Mexico border. We effectively own 25.7 per cent of the system through our interest in TC PipeLines, LP.	25.7	%
16	Northern Border	2,272 km (1,412 miles)	Transports WCSB, Bakken and Rockies natural gas from connections with Foothills and Bison to U.S. Midwest markets. We effectively own 12.9 per cent of the system through our 25.7 per cent interest in TC PipeLines, LP.	12.9	%
17	Portland (PNGTS)	475 km (295 miles)	Connects with TQM near East Hereford, Québec to deliver natural gas to customers in the U.S. Northeast. We effectively own 15.9 per cent of the system through our 25.7 per cent interest in TC PipeLines, LP.	15.9	%
18	Tuscarora	491 km (305 miles)	Transports natural gas from GTN at Malin, Oregon to markets in northeastern California and northwestern Nevada. We effectively own 25.7 per cent of the system through our interest in TC PipeLines, LP.	25.7	%
Mexican pipelines
19	Guadalajara	315 km (196 miles)	Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco.	100	%
20	Mazatlán	430 km (267 miles)	Transports natural gas from El Oro to Mazatlán, Sinaloa in Mexico. Connects to the Topolobampo Pipeline at El Oro.	100	%
21	Tamazunchale	375 km (233 miles)	Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potosi and on to El Sauz, Querétaro.	100	%
22	Topolobampo	560 km (348 miles)	Transports natural gas to Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico.	100	%
Under construction
Canadian pipelines
*	NGTL 2018 Facilities	68 km** (42 miles)	An expansion program on the NGTL System including pipeline and compression additions with expected in-service dates by November 2018.	100%
U.S. pipelines
23	Mountaineer XPress	275 km** (171 miles)	A Columbia Gas project designed to transport supply from the Marcellus and Utica shale plays to points along the system and to the Leach interconnect with Columbia Gulf.	100%
*	Leach XPress1	260 km** (160 miles)	A Columbia Gas project designed to transport supply from the Marcellus and Utica shale plays to points along the system and to an interconnect with Columbia Gulf.	100%
*	Cameron Access	55 km** (34 miles)	A Columbia Gulf project to deliver natural gas from points along the Columbia Gulf system to the Cameron LNG facility.	100%
*	WB XPress	47 km** (29 miles)	A Columbia Gas project designed to transport Marcellus supply both eastbound (to interconnects and mid-Atlantic markets) and westbound (to interconnect pipelines).	100%
*	Gulf XPress	N/A	A Columbia Gulf project associated with the Mountaineer XPress expansion and consisting of the addition of seven greenfield mid-point compressor stations along Columbia Gulf.	100%

TransCanada Management's discussion and analysis 2017 29

Under construction (continued)		Length	Description	Effective ownership
Mexican pipelines
24	Tula	300 km** (186 miles)	The pipeline will originate in Tuxpan in the state of Veracruz and extend through the states of Puebla and Hidalgo, supplying natural gas to CFE combined-cycle power generating facilities in each of those jurisdictions as well as to the central and western regions of Mexico.	100%
25	Villa de Reyes	420 km** (261 miles)	The pipeline will deliver natural gas from Tula, Hildago to Villa de Reyes, San Luis Potosi, connecting to the Tamazunchale and Tula pipelines.	100%
26	Sur de Texas	800 km** (497 miles)	The pipeline will begin offshore in the Gulf of Mexico at the border point near Brownsville, Texas and end in Tuxpan, in the state of Veracruz, connecting with the Tamazunchale and Tula pipelines.	60%
Permitting and pre-construction phase
Canadian pipelines
27	North Montney	206 km** (128 miles)	An extension of the NGTL System to receive natural gas from the North Montney gas producing region and connect to NGTL's existing Groundbirch Mainline.	100%
*	NGTL 2019 Facilities	138 km** (86 miles)	An expansion program on the NGTL System including multiple pipeline projects and compression additions with expected in-service dates by November 2019.	100%
*	NGTL 2020 Facilities	125 km** (78 miles)	An expansion program on the NGTL System including multiple pipeline projects and compression additions with expected in-service dates by November 2020.	100%
*	NGTL 2021 Facilities	401 km** (249 miles)	An expansion program on the NGTL System including multiple pipeline projects and compression additions with expected in-service dates by November 2021.	100%
U.S. pipelines
*	Buckeye XPress	103 km** (64 miles)	A Columbia Gas project designed to upgrade and replace existing pipeline and compression facilities in Ohio to transport incremental supply from the Marcellus and Utica shale plays to points along the system.	100%
*	Portland XPress	N/A	A PNGTS project to expand the system through the construction of compression and related facilities at existing compressor stations.	15.9%
In development
Canadian pipelines
28	Coastal GasLink	670 km** (416 miles)	To deliver natural gas from the Montney gas producing region at an expected interconnect with the NGTL System near Dawson Creek, B.C. to LNG Canada's proposed facility near Kitimat, B.C.	100%
29	Merrick Mainline	260 km** (161 miles)	To deliver natural gas from NGTL's existing Groundbirch Mainline near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C.	100%
1	Leach XPress was placed in service in January 2018.
* **	Facilities and some pipelines are not shown on the map. Final pipe lengths are subject to change during construction and/or final design considerations.

30  TransCanadaManagement's discussion and analysis 2017

Canadian Natural Gas Pipelines

UNDERSTANDING OUR CANADIAN NATURAL GAS PIPELINES SEGMENT

The Canadian natural gas business is subject to regulation by various federal and provincial governmental agencies. The NEB, however, has comprehensive jurisdiction over our Canadian natural gas business. The NEB approves tolls and services that are in the public interest and provides a reasonable opportunity for a pipeline to recover its costs to operate the pipeline. Included in the overall costs to operate the pipeline is a return on the investment the company has made in the assets, referred to as the return on equity. Equity is generally 40 per cent of the deemed capital structure with the remaining 60 per cent from debt. Typically tolls are based on the cost of providing service divided by a forecast of throughput volumes. Any variance in either costs or the actual volumes transported can result in an over-collection or under-collection of revenue that is normally trued up the following year in the calculation of the tolls for that period. The return on equity, however, would continue to be earned at the rate approved by the NEB.

We and our shippers can also establish settlement arrangements, subject to approval by the NEB, that may have elements that vary from the typical toll-setting process. Settlements can include longer terms and mechanisms such as incentive agreements that can have an impact on the actual return on equity achieved. Examples include fixing the OM&A component in determining revenue requirements, where variances are to the pipeline's account or shared in some fashion between the pipeline and shippers.

The NGTL System concluded its two-year settlement arrangement in 2017 and is currently working with interested parties for a new arrangement for 2018 and longer. The Mainline system is entering the fourth year of a six-year fixed toll settlement that includes an incentive arrangement where it has discretion to price certain of its short-term services, such as interruptible transportation service, at market prices. Settlements of this nature provide the pipeline an incentive to either decrease costs and/or increase revenues on the pipeline with a beneficial sharing mechanism to both the shippers and us.

SIGNIFICANT EVENTS

Canadian Regulated Pipelines

NGTL System

In February 2018, we announced a new NGTL System expansion totaling $2.4 billion, with in-service dates between 2019 and 2021. The new expansion program includes approximately 375 km (233 miles) of 16- to 48-inch pipeline, four compression units totaling 120 MW and associated meter stations and facilities. We anticipate incremental firm receipt contracts of 664 TJ/d (620 MMcf/d) and firm delivery contracts to our major border export and intra-basin delivery locations of 1.1 PJ/d (1.0 Bcf/d). 

In June 2017, we announced a new $2 billion expansion program on our NGTL System based on new contracted customer demand for approximately 3.2 PJ/d (3.0 Bcf/d) of incremental firm receipt and delivery services.

With the 2021 expansion program, NGTL now has a $7.2 billion capital program, excluding the $1.9 billion Merrick pipeline project.

In 2017, we placed approximately $1.7 billion of facilities in service and reduced remaining project estimates by $0.6 billion. 

Towerbirch Expansion

In March 2017, the Government of Canada approved the $0.4 billion Towerbirch Project. This project consists of a 55 km (34 mile), 36-inch pipeline loop and a 32 km (20 mile), 30-inch pipeline extension of the NGTL System in northwest Alberta and northeast B.C. The NEB approval included the continued use of the existing rolled-in tolling methodology for this project. The project was placed in service in November 2017.

North Montney

In March 2017, we filed an application with the NEB for a variance to the existing approvals for the North Montney Project on the NGTL System to remove the condition that the project could only proceed once a positive FID was made for the PNW LNG project. The North Montney project is now underpinned by restructured 20-year commercial contracts with shippers and is not dependent on the LNG project proceeding. A hearing on the matter began the week of January 22, 2018 and a decision from the NEB is anticipated in second quarter 2018.

TransCanada Management's discussion and analysis 2017 31

Sundre Crossover Project

On December 28, 2017, the NEB approved the Sundre Crossover Project on the NGTL System. The approximate $100 million, 21 km (13 mile), 42-inch pipeline project will increase delivery of 245 TJ/d (229 MMcf/d) to the Alberta / B.C. border to connect with TransCanada downstream pipelines. In-service is planned for April 1, 2018.

NGTL 2018 Revenue Requirement

NGTL's 2016-2017 Settlement, which established revenue requirements for the system, expired on December 31, 2017. We continue to work with interested parties towards a new revenue requirement arrangement for 2018 and longer. While these discussions are underway, NGTL is operating under interim tolls for 2018 that were approved by the NEB on November 24, 2017. 

Canadian Mainline

The Canadian Mainline currently has a near-term capital program of approximately $0.2 billion for completion to 2021. In 2017, we placed approximately $0.2 billion of facilities in service, consisting primarily of the Vaughan Loop in November.

Dawn Long-Term Fixed-Price Service

On November 1, 2017, we began offering the new Dawn LTFP service on the Canadian Mainline. This NEB-approved service enables WCSB producers to transport up to 1.5 PJ/d (1.4 Bcf/d) of natural gas at a simplified toll of $0.77/GJ from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The service is underpinned by ten-year contracts that have early termination rights after five-years. Any early termination will result in an increased toll for the last two years of the contract.

Canadian Mainline 2018-2020 Toll Review

Tolls for the Canadian Mainline were previously established for 2015 to 2017 in accordance with the terms of the 2015-2030 LDC Settlement. While the settlement specified tolls for 2015 to 2020, the NEB ordered a toll review halfway through the six-year period, to be filed by December 31, 2017. The 2018-2020 toll review must include costs, forecast volumes, contract levels, deferral balances and any other material changes. A Supplemental Agreement for the 2018 to 2020 period was executed between TransCanada and the Eastern LDCs on December 8, 2017 and filed for approval with the NEB on December 18, 2017. The Agreement, supported by a majority of Canadian Mainline stakeholders, proposes lower tolls, preserves an incentive arrangement that provides the opportunity for a 10.1 per cent or greater return on a 40 percent deemed equity and describes the revenue requirements and billing determinants for the 2018-2020 period. 

We anticipate the NEB will provide direction and process to adjudicate the application in first quarter 2018. Interim tolls for 2018, as established by the Supplemental Agreement, were filed and subsequently approved by the NEB on December 19, 2017.

Maple Compressor Expansion Project

In 2017, the Canadian Mainline received requests for expansion capacity to the southern Ontario market plus delivery to Atlantic Canada via the TQM and PNGTS systems. The requests for approximately 86 TJ/d (80 MMcf/d) of firm service underpin the need for new compression at the existing Maple compressor site. Customers have executed 15-year precedent agreements to proceed with the project which has an estimated cost of $110 million. An application to the NEB seeking project approval was filed November 2, 2017. We have requested a decision by the NEB to proceed with the project in the first quarter of 2018 to meet an anticipated in-service date of November 1, 2019.

Eastern Mainline Project

The $2 billion Eastern Mainline project that was conditioned on the approval and construction of the Energy East pipeline will not be proceeding. See the Liquids Pipelines Significant events section for further discussion on Energy East.

LNG Pipeline Projects

Prince Rupert Gas Transmission (PRGT)

In July 2017, we were notified that PNW LNG would not be proceeding with their proposed LNG project and that Progress Energy would be terminating their agreement with us for development of the PRGT pipeline. In accordance with the terms of the agreement, all project costs incurred to advance PRGT, including carrying charges, were fully recoverable upon termination and, as a result, we received a payment of $0.6 billion from Progress in October 2017.

32  TransCanadaManagement's discussion and analysis 2017

Coastal GasLink

The continuing delay in the FID for the LNG Canada project triggered a restructuring of provisions in the Coastal GasLink project agreement with LNG Canada that resulted in the payment of certain amounts to TransCanada with respect to carrying charges on costs incurred. In September 2017, an approximate $80 million payment was received related to costs incurred since inception of the project. Following a payment of $8 million in fourth quarter 2017, additional quarterly payments of approximately $7 million will be received until further notice. We continue to work with LNG Canada under the agreement towards an FID. Coastal GasLink filed an amendment to the Environmental Assessment Certificate in November 2017 for an alternate route on a portion of the pipeline. A decision from the B.C. Environmental Assessment Office is expected in 2018.

Coastal GasLink is a 670 km (416 mile) pipeline that will deliver natural gas from the Dawson Creek, B.C. area to LNG Canada’s proposed gas liquefaction facility near Kitimat, B.C. Should the project not proceed, our project costs, including carrying charges, are fully recoverable.

FINANCIAL RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). See page 8 for more information on non-GAAP measures we use. Certain costs previously reported in our Corporate segment are now being reported within the business segments to better align with how we measure our financial performance. 2016 and 2015 results have been adjusted to reflect this change.

year ended December 31
(millions of $)	2017		2016		2015
NGTL System	996		968		900
Canadian Mainline	1,043		1,105		1,193
Other Canadian pipelines1	110		116		131
Business development	(5	)	(7	)	(8	)
Comparable EBITDA	2,144		2,182		2,216
Depreciation and amortization	(908	)	(875	)	(849	)
Comparable EBIT and segmented earnings	1,236		1,307		1,367

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

Canadian Natural Gas Pipelines comparable EBIT and segmented earnings decreased by $71 million in 2017 compared to 2016 and by $60 million in 2016 compared to 2015.

Net income and comparable EBITDA for our rate-regulated Canadian Pipelines are primarily affected by our approved ROE, our investment base, the level of deemed common equity and incentive earnings. 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 revenue on a flow-through basis.

year ended December 31
(millions of $)	2017	2016	2015
Net income
NGTL System	352	318	269
Canadian Mainline	199	208	213
Average investment base
NGTL System	8,385	7,451	6,698
Canadian Mainline	4,184	4,441	4,784

TransCanada Management's discussion and analysis 2017 33

Net income for the NGTL System was $34 millionhigher in 2017 compared to 2016 mainly due to a higher average investment base, partially offset by higher carrying charges on regulatory deferrals. Net income in 2016 was $49 millionhigher than 2015 due to a higher average investment base and increased OM&A incentive earnings recorded in 2016. The two-year 2016-2017 Revenue Requirement Settlement included an ROE of 10.1 per cent on 40 per cent deemed equity and a mechanism for sharing variances above and below a fixed annual OM&A amount with flow-through treatment of all other costs. The 2015 NGTL Settlement included a 10.1 per cent ROE on deemed common equity of 40 per cent and a mechanism for sharing variances between actual and a fixed OM&A cost amount.

Canadian Mainline’s net income in 2017decreased by $9 million compared to 2016 mainly due to a lower average investment base and higher carrying charges to shippers on the 2017 net revenue surplus, partially offset by higher incentive earnings in 2017. Net income in 2016 was $5 million lower than 2015 mainly due to a lower average investment base and higher carrying charges to shippers on the 2016 net revenue surplus, partially offset by higher incentive earnings in 2016. The lower average investment base in 2017 and 2016 was mainly due to depreciation and the inclusion of the 2016 and 2015 net revenue surpluses in the investment base.

The Canadian Mainline operated under the NEB 2014 Decision throughout 2015 to 2017. The NEB 2014 Decision included an approved ROE of 10.1 per cent with a possible range of achieved ROE outcomes between 8.7 per cent and 11.5 per cent. This decision also included an incentive mechanism that has both upside and downside risk and a $20 million annual after-tax contribution from us. Toll stabilization is achieved through the continued use of deferral accounts to capture the surplus or shortfall between our revenues and cost of service for each year over a six-year fixed toll term from 2015 to 2020.

Depreciation and amortization

Depreciation and amortization was $33 millionhigher in 2017 compared to 2016, and $26 millionhigher in 2016 compared to 2015, primarily due to new NGTL System facilities that were placed in service in both 2017 and 2016.

OUTLOOK

Earnings

Net income for Canadian rate-regulated pipelines is affected by changes in investment base, ROE and regulated capital structure, as well as by the terms of toll settlements or other toll proposals approved by the NEB.