40-F

U.S. Securities and Exchange Commission

Washington, D.C. 20549

Form 40-F

¨	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
OR
x	ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2015           Commission File Number 1-8887

TRANSCANADA PIPELINES LIMITED

(Exact Name of Registrant as specified in its charter)

Canada

(Province or jurisdiction of incorporation or organization)

4922, 4923, 4924, 5172

(Primary Standard Industrial Classification Code Number (if applicable))

52 - 2179728

(I.R.S. Employer Identification Number (if applicable))

TransCanada Tower, 450 - 1 Street S.W.

Calgary, Alberta, Canada, T2P 5H1

(403) 920-2000

(Address and telephone number of Registrant's principal executive offices)

TransCanada PipeLine USA Ltd., 700 Louisiana Street, Suite 700

Houston, Texas, 77002-2700; (832) 320-5201

(Name, address (including zip code) and telephone number (including area code)

of agent for service in the United States

Securities registered or to be registered pursuant to Section 12(b) of the Act: None

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: Debt Securities

For annual reports, indicate by check mark the information filed with this Form:

¨ Annual information form x    Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report.

At December 31, 2015, 779,605,870 common shares,

which are all owned by TransCanada Corporation, were issued and outstanding.

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x    No ¨

Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit and post such files). Yes x    No ¨

The documents (or portions thereof) forming part of this Form 40-F are incorporated by reference into the following registration statements under the Securities Act of 1933, as amended:

Form	Registration No.
F-10	333-208588

EXPLANATORY NOTE

An amendment to this Form 40-F shall be filed to include the TransCanada PipeLines Limited ("TCPL") Annual information form for the year ended December 31, 2015. The amendment shall be filed no later than the date the Annual information form is required pursuant to home country requirements.

AUDITED CONSOLIDATED ANNUAL FINANCIAL STATEMENTS AND

MANAGEMENT'S DISCUSSION AND ANALYSIS

Except sections specifically referenced below which shall be deemed incorporated by reference herein and filed, no other portion of the TCPL 2015 Management's discussion and analysis and audited consolidated financial statements shall be deemed filed with the U.S. Securities and Exchange Commission (the "Commission") as part of this report under the Exchange Act.

A.    Audited Annual Financial Statements

For audited consolidated financial statements, including the auditors' report, see pages 111 through 173 of the TCPL 2015 Management's discussion and analysis and audited consolidated financial statements included herein.

B.    Management's Discussion and Analysis

For management's discussion and analysis, see pages 1 through 110 of the TCPL 2015 Management's discussion and analysis and audited consolidated financial statements included herein.

C.    Management's Report on Internal Control Over Financial Reporting

For management's report on internal control over financial reporting, see "Management's report on Internal Control over Financial Reporting" that accompanies the audited consolidated financial statements on page 111 of the TCPL 2015 Management's discussion and analysis and audited consolidated financial statements included herein.

UNDERTAKING

The Registrant undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the Commission staff, and to furnish promptly, when requested to do so by the Commission staff, information relating to: the securities registered pursuant to Form 40-F; the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

For information on disclosure controls and procedures and management's annual report on internal control over financial reporting, see "Other information - Controls and Procedures" in Management's discussion and analysis on page 92 of the TCPL 2015 Management's discussion and analysis and audited consolidated financial statements.

AUDIT COMMITTEE FINANCIAL EXPERT

The Registrant's board of directors has determined that it has at least one audit committee financial expert serving on its audit committee. Mr. Siim A. Vanaselja, Mr. Kevin E. Benson and Mr. John E. Lowe have been designated audit committee financial experts and are independent, as that term is defined by the New York Stock Exchange's listing standards applicable to the Registrant. The Commission has indicated that the designation of Mr. Vanaselja, Mr. Benson and Mr. Lowe as audit committee financial experts does not make Mr. Vanaselja, Mr. Benson or Mr. Lowe "experts" for any purpose, impose any duties, obligations or liability on Mr. Vanaselja, Mr. Benson or Mr. Lowe that are greater than those imposed on members of the Audit committee and Board of Directors who do not carry this designation or affect the duties, obligations or liability of any other member of the Audit committee.

CODE OF ETHICS

The Registrant has adopted a code of business ethics for its directors, officers, employees and contractors. The Registrant's code is available on its website at www.transcanada.com. No waivers have been granted from any provision of the code during the 2015 fiscal year.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Pre-Approval Policies and Procedures

TCPL’s Audit committee has adopted a pre-approval policy with respect to permitted non-audit services. Under the policy, the Audit committee has granted pre-approval for specified non-audit services. For engagements of up to $250,000, approval of the Audit committee Chair is required, and the Audit committee is to be informed of the engagement at the next scheduled Audit committee meeting. For all engagements of $250,000 or more, pre-approval of the Audit committee is required. In all cases, regardless of the dollar amount involved, where there is a potential for conflict of interest involving the external auditor to arise on an engagement, the Audit committee must pre-approve the assignment.

To date, non-audit services have been pre-approved by the Audit committee in accordance with the pre-approval policy described above.

External Auditor Service Fees

The following table provides information about the fees paid by the Company to KPMG LLP, the external auditor of the TransCanada group of companies, for professional services rendered for the 2015 and 2014 fiscal years.

($ millions)	2015	2014
Audit fees	$7.8	$6.4
audit of the annual consolidated financial statements
services related to statutory and regulatory filings or engagements
review of interim consolidated financial statements and information contained in various prospectuses and other securities offering documents
Audit‑related fees	0.2	0.2
services related to the audit of the financial statements of certain TransCanada post-retirement and post-employment plans
Tax fees	0.5	0.5
Canadian and international tax planning and tax compliance matters, including the review of income tax returns and other tax filings
All other fees	—	—
Total fees	$8.5	$7.1

OFF-BALANCE SHEET ARRANGEMENTS

The Registrant has no off-balance sheet arrangements, as defined in this Form, other than the guarantees and commitments described in Note 26 of the Notes to the audited consolidated financial statements attached to this Form 40-F and incorporated herein by reference.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

For information on tabular disclosure of contractual obligations, see "Contractual obligations" in Management's discussion and analysis on page 82 of the TCPL 2015 Management's discussion and analysis and audited consolidated financial statements.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Registrant has a separately-designated standing Audit committee. The members of the Audit committee are:

Chair: Members: S.A. Vanaselja K.E. Benson D.H. Burney J.E. Lowe M.P. Salomone D.M.G. Stewart

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 document may include information about the following, among other things:

• anticipated business prospects

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

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

• expected regulatory processes and outcomes

• expected common share purchases under our normal course issuer bid

• expected impact of regulatory 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

• 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 document.

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

Assumptions

• inflation rates, commodity prices and capacity prices

• timing of financings and hedging

• regulatory decisions and outcomes

• foreign exchange rates

• interest rates

• tax rates

• 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

• acquisitions and divestitures.

Risks and uncertainties

• our ability to successfully implement our strategic initiatives

• whether our strategic initiatives 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 we receive 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

• weather

• cybersecurity

• 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 U.S. Securities and Exchange Commission (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.

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized, in the City of Calgary, Province of Alberta, Canada.

TRANSCANADA PIPELINES LIMITED
Per:	/s/ DONALD R. MARCHAND
	DONALD R. MARCHAND Executive Vice-President, Corporate Development and Chief Financial Officer
	Date: February 11, 2016

DOCUMENTS FILED AS PART OF THIS REPORT

EXHIBITS
13.1	Management's discussion and analysis (included on pages 1 through 110 of the TCPL 2015 Management's discussion and analysis and audited financial statements).
13.2	2015 Audited consolidated financial statements (included on pages 111 through 173 of the TCPL 2015 Management's discussion and analysis and audited financial statements)), including the auditors' report thereon.
23.1	Consent of KPMG LLP, Independent Registered Public Accounting Firm.
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.
32.2	Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF	XBRL Taxonomy Definition Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

EX-13.1

EXHIBIT 13.1

Management's discussion and analysis

February 10, 2016

This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada PipeLines Limited. It discusses our business, operations, financial position, risks and other factors for the year ended December 31, 2015.

This MD&A should be read with our accompanying December 31, 2015 audited comparative 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		2
ABOUT OUR BUSINESS		6
	•  Three core businesses	6
	•  Our strategy	9
	•  Capital program	10
	•  2015 financial highlights	12
	•  Outlook	19
NATURAL GAS PIPELINES		21
LIQUIDS PIPELINES		39
ENERGY		49
CORPORATE		70
FINANCIAL CONDITION		74
OTHER INFORMATION		86
	•  Risks and risk management	86
	•  Controls and procedures	92
	•  Critical accounting estimates	93
	•  Financial instruments	96
	•  Accounting changes	98
	•  Reconciliation of non-GAAP measures	100
	•  Quarterly results	103
GLOSSARY		110

TCPL Management's discussion and analysis 2015 1

About this document

Throughout this MD&A, the terms, we, us, our and TCPL mean TransCanada PipeLines Limited and its subsidiaries.

Abbreviations and acronyms that are not defined in the document are defined in the glossary on page 110. All information is as of February 10, 2016 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 may include information about the following, among other things:

• anticipated business prospects

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

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

• expected regulatory processes and outcomes

• expected impact of regulatory 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

• 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

• inflation rates, commodity prices and capacity prices

• timing of financings and hedging

• regulatory decisions and outcomes

• foreign exchange rates

• interest rates

• tax rates

• 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

• acquisitions and divestitures.

2  TCPL Management's discussion and analysis 2015

Risks and uncertainties

• our ability to successfully implement our strategic initiatives

• whether our strategic initiatives 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 we receive 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

• 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 U.S. Securities and Exchange Commission (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 find more information about TCPL in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).

TCPL Management's discussion and analysis 2015 3

NON-GAAP MEASURES

We use the following non-GAAP measures:

• EBITDA

• EBIT

• funds generated from operations

• distributable cash flow

• comparable earnings

• comparable EBITDA

• comparable EBIT

• comparable distributable cash flow

• comparable income from equity investments

• comparable depreciation and amortization

• comparable interest expense

• comparable interest income and other

• comparable income tax expense

• comparable income attributable to non-controlling interests.

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

EBITDA and EBIT

We use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings.

Funds generated from operations

Funds generated from operations includes 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. See the Financial condition section for a reconciliation to net cash provided by operations.

Distributable cash flow

Distributable cash flow is defined as funds generated from operations plus distributions in excess of equity earnings less preferred share dividends, distributions to non-controlling interests and maintenance capital expenditures. Maintenance capital expenditures represent costs which are necessary to preserve the operating ability of our assets and investments. We believe it is a useful supplemental measure of performance that defines cash available to common shareholder before capital allocation. See the Financial condition section for a reconciliation to net cash provided by operations.

4  TCPL Management's discussion and analysis 2015

Comparable measures

We calculate the 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. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.

Comparable measure	Original measure
comparable earnings	net income attributable to common shares
comparable EBITDA	EBITDA
comparable EBIT	segmented earnings
comparable distributable cash flow	distributable cash flow
comparable income from equity investments	income from equity investments
comparable depreciation and amortization	depreciation and amortization
comparable interest expense	interest expense
comparable interest income and other	interest income and other
comparable income tax expense	income tax expense
comparable net income attributable to non-controlling interests	net income attributable to non-controlling interests

 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

• gains or losses on sales of assets

• legal, contractual and bankruptcy settlements

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

• restructuring costs

• impairment of assets and investments.

In calculating comparable earnings and other comparable measures we 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 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 unrealized changes in fair value do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.

TCPL Management's discussion and analysis 2015 5

About our business

With over 65 years of experience, TCPL 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. We are a wholly-owned subsidiary of TransCanada Corporation (TransCanada).

THREE CORE BUSINESSES

We operate our business in three segments – Natural Gas Pipelines, Liquids Pipelines and Energy. We also have a non-operational Corporate segment consisting of corporate and administrative functions that provide support and governance to our operational business segments.

Our $67 billion portfolio of energy infrastructure assets meets the needs of people who rely on us to deliver their energy safely and reliably every day. We operate in seven Canadian provinces, 36 U.S. states and Mexico.

6  TCPL Management's discussion and analysis 2015

TCPL Management's discussion and analysis 2015 7

Year at a glance

at December 31
(millions of $)	2015	2014
Total assets
Natural Gas Pipelines	31,072	27,103
Liquids Pipelines	16,046	16,116
Energy	15,558	14,197
Corporate	4,253	3,999
	66,929	61,415

year ended December 31
(millions of $)	2015	2014
Total revenues
Natural Gas Pipelines	5,383	4,913
Liquids Pipelines	1,879	1,547
Energy	4,038	3,725
	11,300	10,185

year ended December 31
(millions of $)	2015		2014
Comparable EBIT
Natural Gas Pipelines	2,345		2,178
Liquids Pipelines	1,056		843
Energy	944		1,039
Corporate	(202	)	(150	)
	4,143		3,910

Common shares outstanding – average
(millions)
2015	779
2014	775
2013	749

as at February 5, 2016	issued and outstanding
Common shares
	779	million

8  TCPL Management's discussion and analysis 2015

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 and shorter-term power sales to wholesale and load customers 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 $58 billion capital program, comprised of $13 billion in near-term projects and $45 billion in medium to long-term projects. These will contribute incremental earnings over the near, medium and long terms as our investments are placed in service. • Our expertise in 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 shareholder. • 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 energy and pipeline facilities. • Our growing investment in natural gas, nuclear, wind, hydro and solar generating facilities demonstrates our commitment to clean, sustainable energy.
3	Cultivate a focused portfolio of high quality development and investment options
	• We assess opportunities to acquire and develop energy infrastructure that complements our existing portfolio and diversifies access to attractive supply and market regions. • We focus on pipelines 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 developing core competencies in areas such as 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 and operational 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 business cycles.

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

   excellence; and a commitment to health, safety and the environment are paramount parts of our core values.

• Financial positioning: excellent reputation for consistent financial performance and long-term financial stability and

   profitability; disciplined approach to capital investment; ability to access sizable amounts of competitively priced capital to

   support our growth; ability to balance an increasing dividend on our common shares while preserving financial flexibility

   to fund our industry-leading capital program in all market conditions.

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

   of our value to equity and debt investors – both the upside and the risks – to build trust and support.

TCPL Management's discussion and analysis 2015 9

CAPITAL PROGRAM

We are developing quality projects under our long-term 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 $13 billion of near-term projects and $45 billion of commercially secured medium and longer-term projects. Amounts presented exclude the impact of foreign exchange, 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.

at December 31, 2015	Estimated project cost	Carrying value
(billions of $)
Summary
Near-term	13.4	3.9
Medium to longer-term	45.2	2.1
Total capital program	58.6	6.0
Foreign exchange impact on Capital Program1	4.5	0.8

¹ Reflects U.S. foreign exchange rate of $1.38 at December 31, 2015.

Near-term projects

at December 31, 2015	Segment	Expected in-service date	Estimated project cost	Carrying value
(billions of $)
Ironwood Acquisition	Energy	2016	US 0.7	—
Houston Lateral and Terminal	Liquids Pipelines	2016	US 0.6	US 0.5
Topolobampo	Natural Gas Pipelines	2016	US 1.0	US 0.9
Mazatlan	Natural Gas Pipelines	2016	US 0.4	US 0.3
Grand Rapids Phase 11	Liquids Pipelines	2017	0.9	0.5
Northern Courier	Liquids Pipelines	2017	1.0	0.6
Tuxpan-Tula	Natural Gas Pipelines	2017	US 0.5	—
Canadian Mainline – Other	Natural Gas Pipelines	2016–2017	0.7	0.1
NGTL System – North Montney	Natural Gas Pipelines	2017	1.7	0.3
– 2016/17 Facilities	Natural Gas Pipelines	2016–2018	2.7	0.3
– 2018 Facilities	Natural Gas Pipelines	2018	0.6	—
– Other	Natural Gas Pipelines	2016–2017	0.4	0.1
Napanee	Energy	2017 or 2018	1.0	0.3
Bruce Power – life extension1	Energy	2016–2020	1.2	—
Total near-term projects			13.4	3.9

¹   Our proportionate share.

10  TCPL Management's discussion and analysis 2015

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 2019 and beyond, and costs provided in the schedule below reflect the most recent costs for each project as filed with the various regulatory authorities or otherwise disclosed. These projects have all been commercially secured but are subject to approvals that include sponsor FID and/or complex regulatory processes. Please refer to the Significant events section in each Business Segment for further information on each of these projects.

at December 31, 2015	Segment	Estimated project cost	Carrying value
(billions of $)
Heartland and TC Terminals	Liquids Pipelines	0.9	0.1
Upland	Liquids Pipelines	US 0.6	—
Grand Rapids Phase 21	Liquids Pipelines	0.7	—
Bruce Power – life extension1	Energy	5.3	—
Keystone projects
Keystone XL2	Liquids Pipelines	US 8.0	US 0.4
Keystone Hardisty Terminal2	Liquids Pipelines	0.3	0.1
Energy East projects
Energy East3	Liquids Pipelines	15.7	0.7
Eastern Mainline Project	Natural Gas Pipelines	2.0	0.1
BC west coast LNG-related projects
Coastal GasLink	Natural Gas Pipelines	4.8	0.3
Prince Rupert Gas Transmission	Natural Gas Pipelines	5.0	0.4
NGTL System – Merrick	Natural Gas Pipelines	1.9	—
Total medium to longer-term projects		45.2	2.1

¹  Our proportionate share.

²  Carrying value reflects amount remaining after impairment charge.

³  Excludes transfer of Canadian Mainline natural gas assets.

TCPL Management's discussion and analysis 2015 11

2015 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, funds generated from operations and comparable distributable cash flow are all non-GAAP measures. See page 4 for more information about the non-GAAP measures we use and pages 76 and 100 for a reconciliation to their GAAP equivalents.

year ended December 31
(millions of $)	2015		2014		2013
Income
Revenues	11,300		10,185		8,797
Net (loss)/income attributable to common shares	(1,146	)	1,841		1,769
Comparable EBITDA	5,908		5,521		4,859
Comparable earnings	1,849		1,813		1,641
Cash flows
Funds generated from operations	4,513		4,267		3,977
Increase in working capital	(359	)	(189	)	(334	)
Net cash provided by operations	4,154		4,078		3,643
Comparable distributable cash flow	3,638		3,499		3,280
Capital spending – capital expenditures	3,918		3,489		4,264
Capital spending – projects in development	511		848		488
Contributions to equity investments	493		256		163
Acquisitions, net of cash acquired	236		241		216
Proceeds from sale of assets, net of transaction costs	—		196		—
Balance sheet
Total assets	66,929		61,415		56,626
Long-term debt	31,584		24,757		22,865
Junior subordinated notes	2,422		1,160		1,063
Preferred shares	—		—		194
Non-controlling interests	1,717		1,583		1,417
Common shareholder equity	18,580		21,095		19,827

12  TCPL Management's discussion and analysis 2015

Consolidated results

year ended December 31
(millions of $)	2015		2014		2013
Segmented earnings/(losses)
Natural Gas Pipelines	2,220		2,187		1,881
Liquids Pipelines	(2,630	)	843		603
Energy	812		1,051		1,113
Corporate	(301	)	(150	)	(124	)
Total segmented earnings	101		3,931		3,473
Interest expense	(1,398	)	(1,235	)	(1,046	)
Interest income and other	192		128		72
(Loss)/income before income taxes	(1,105	)	2,824		2,499
Income tax expense	(35	)	(830	)	(605	)
Net (loss)/income	(1,140	)	1,994		1,894
Net income attributable to non-controlling interests	(6	)	(151	)	(105	)
Net (loss)/income attributable to controlling interests	(1,146	)	1,843		1,789
Preferred share dividends	—		(2	)	(20	)
Net (loss)/income attributable to common shares	(1,146	)	1,841		1,769

Net (loss)/income attributable to common shares

Net (loss)/income attributable to common shares in 2015 was a loss of $1,146 million (2014 – income of $1,841 million; 2013 –income of $1,769 million). The following specific items were recognized in net (loss)/income attributable to common shares in 2013 to 2015 and were excluded from comparable earnings for the relevant periods:

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 expected to close in early 2016

• a net charge of $74 million after tax for restructuring charges 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 form 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 on 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

TCPL Management's discussion and analysis 2015 13

• 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.

2014

• a gain of $99 million after tax on the sale of Cancarb Limited and its related power generation business

• a net loss of $32 million after tax resulting from a termination payment to Niska Gas Storage for contract restructuring

• a gain of $8 million after tax on the sale of our 30 per cent interest in Gas Pacifico/INNERGY.

2013

• net income of $84 million recorded in 2013 related to 2012 from the NEB 2013 decision on the Canadian Restructuring Proposal (NEB 2013 Decision)

• a favourable tax adjustment of $25 million due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax.

Certain unrealized fair value adjustments relating to risk management activities are also excluded from comparable earnings. The remainder of net (loss)/income is equivalent to comparable earnings. A reconciliation of net (loss)/income 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.

14  TCPL Management's discussion and analysis 2015

Reconciliation of net (loss)/income to comparable earnings

year ended December 31
(millions of $, except per share amounts)	2015		2014		2013
Net (loss)/income attributable to common shares	(1,146	)	1,841		1,769
Specific items (net of tax):
Keystone XL impairment charge	2,891		—		—
TC Offshore loss on sale	86		—		—
Restructuring costs	74		—		—
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	)	—		—
Cancarb gain on sale	—		(99	)	—
Niska contract termination	—		32		—
Gas Pacifico/ INNERGY gain on sale	—		(8	)	—
NEB 2013 Decision – 2012	—		—		(84	)
Part VI.I income tax adjustment	—		—		(25	)
Risk management activities1	39		47		(19	)
Comparable earnings	1,849		1,813		1,641

1	year ended December 31
	(millions of $)	2015		2014		2013
	Canadian Power	(8	)	(11	)	(4	)
	U.S. Power	(30	)	(55	)	50
	Natural Gas Storage	1		13		(2	)
	Foreign exchange	(21	)	(21	)	(9	)
	Income tax attributable to risk management activities	19		27		(16	)
	Total (losses)/gains from risk management activities	(39	)	(47	)	19

TCPL Management's discussion and analysis 2015 15

Comparable earnings

Comparable earnings in 2015 were $36 millionhigher than in 2014.

The increase in comparable earnings was primarily the net result of:

• higher earnings from Liquids Pipelines due to higher volumes on the Keystone Pipeline System

• lower earnings from Western Power as a result of lower realized power prices and lower PPA volumes

• higher interest expense as a result of long term debt issuances net of maturities

• higher interest income and other as a result of increased AFUDC related to our rate-regulated pipeline projects including Energy East Pipeline and our Mexico pipelines

• higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower capacity revenue in New York and lower realized prices at our northeastern U.S. Power facilities

• higher earnings from U.S. Natural Gas Pipelines due to higher ANR, Great Lakes and GTN transportation revenues

• higher earnings from Eastern Power primarily due to four solar facilities acquired in 2014

• higher earnings from the Tamazunchale Extension which was placed in service in 2014.

The stronger U.S. dollar in 2015 compared to 2014 positively impacted the translated results in our U.S. businesses, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our exposure.

Comparable earnings in 2014 were $172 millionhigher than 2013.

The increase in comparable earnings was primarily the net result of:

• incremental earnings from the Gulf Coast extension of the Keystone Pipeline System which was placed in service in January 2014

• higher interest expense from debt issuances, lower capitalized interest due to projects placed in service and lower interest expense on amounts due to TransCanada

• lower earnings from Western Power as a result of lower realized power prices

• higher earnings from the Tamazunchale Extension which was placed in service in 2014

• higher earnings from U.S. Natural Gas Pipelines due to higher transportation revenues at Great Lakes reflecting colder winter weather and increased demand, partially offset by lower contributions from GTN and Bison following the reductions in our effective ownership in July 2013 (GTN and Bison) and October 2014 (Bison)

• higher earnings from U.S. Power mainly because of higher realized capacity prices in New York and higher realized power prices at our New York and New England facilities

• higher earnings from the Canadian Mainline due to higher incentive earnings

• incremental earnings from Eastern Power primarily due to solar facilities acquired in 2013 and 2014

• lower dividends due to redemption of Series Y preferred shares in March 2014.

16  TCPL Management's discussion and analysis 2015

Cash flows

Funds generated from operations

Funds generated from operations were six per centhigher in 2015 compared to 2014 primarily due to higher comparable earnings, as described above.

Comparable distributable cash flow

Comparable distributable cash flow increased in 2015 compared to 2014 primarily due to higher comparable earnings, as described above. See the Financial condition section for more information on the calculation of comparable distributable cash flow.

TCPL Management's discussion and analysis 2015 17

Funds used in investing activities

Capital spending¹ 

year ended December 31
(millions of $)	2015	2014	2013
Natural Gas Pipelines	2,699	2,136	2,021
Liquids Pipelines	1,290	1,949	2,529
Energy	376	206	152
Corporate	64	46	50
	4,429	4,337	4,752

¹Capital spending includes capital expenditures, maintenance capital expenditures and capital projects in development.

Capital spending

We invested $4.4 billion in capital projects in 2015 as part of our ongoing growth program which is a key part of our strategy to optimize the value of our existing assets and develop new, complementary assets in high demand areas that are expected to generate stable, predictable earnings and cash flow and to maximize returns to shareholder for years to come.

Contributions to equity investments and acquisitions

In 2015, we made contributions of $493 million to our equity investments primarily related to the construction of Grand Rapids and we spent $236 million to increase our ownership in Bruce Power.

Balance sheet

We continue to maintain a solid balance sheet while growing our total assets by $10.3 billion since 2013. At December 31, 2015, common equity represented 39 per cent (44 per cent in 2014) of our capital structure, after giving effect to the various 2015 specific items outlined on pages 13 and 14. See page 75 for more information about our capital structure.

Quarterly dividend on our common shares

The dividend declared for the quarter ending March 31, 2016 is equal to the quarterly dividend to be paid on TransCanada's issued and outstanding common shares at the close of business on March 31, 2016.

Cash dividends

year ended December 31
(millions of $)	2015	2014	2013
Common shares	1,446	1,345	1,285
Preferred shares	—	4	22

18  TCPL Management's discussion and analysis 2015

OUTLOOK

Earnings

We anticipate our 2016 earnings, after excluding specific items, to be higher than 2015 mainly due to the following:

• Expected earnings from Topolobampo and Mazatlan Pipeline projects coming into service

• Positive impact of a stronger U.S. dollar on U.S. denominated earnings

• Increase in the average investment base for the NGTL System

• Higher earnings associated with incremental contracts from ANR

• Cost savings achieved as a result of corporate restructuring

• Consistent earnings in Energy with higher earnings in U.S. Power, relatively consistent earnings in Western Power and Bruce Power and slightly lower earnings in Eastern Power.

Partially offset by:

• Reduced capitalized interest due to the Keystone XL Pipeline project Presidential permit denial

• Lower anticipated earnings from the Keystone Pipeline System based on expiring short-term contracts for Cushing Marketlink.

Natural Gas Pipelines

Earnings from the Natural Gas Pipelines segment are affected by regulatory decisions and the timing of these decisions. Earnings are also impacted by market conditions, which drive the level of demand and the rates we secure for our services.

Canadian Mainline earnings are anticipated to be lower in 2016 due to a declining investment base. These lower earnings are expected to be largely offset by growth in the NGTL System investment base as we continue to invest in connecting new natural gas supply and respond to growing demand in the northeastern B.C. and Alberta markets.

U.S. and International Gas Pipelines earnings in 2016 are expected to be higher than 2015 as we pursue opportunities for continued growth in end use markets for natural gas and evaluate our commercial and operational positions in ANR and Great Lakes in response to positive developments in supply fundamentals in those market areas. On January 29th, 2016, ANR filed a Section 4 Rate Case with the FERC to increase its base rates. We anticipate that the proposed rates, which are subject to customer refund and pending final FERC approval, will take effect in third quarter 2016.

Mexico Pipeline earnings are expected to be higher in 2016 as the Topolobampo and Mazatlan Pipeline projects come into service in late 2016.

Liquids Pipelines

With the exception of the Keystone XL impairment impact, our 2016 earnings are expected to be slightly lower than our 2015 earnings due to short term contract expiration and market conditions related to the lower crude oil price environment.

Energy

Earnings in the Energy segment are generally maximized by maintaining and optimizing the operations of our power plants and through various marketing activities. Although a significant portion of Energy’s output is sold under long-term contracts, output that is sold under shorter-term arrangements or at spot prices will continue to be affected by fluctuations in commodity prices. Overall we expect Energy earnings in 2016 to be consistent with 2015.

Western Power earnings in 2016 are anticipated to be consistent with 2015 as a result of a well-supplied Alberta power market, slower demand growth and lower natural gas prices. Negative pressure on earnings in 2016 is expected due to the increase in the government imposed emissions reductions targets and higher per tonne GHG emissions costs.

Eastern Power earnings in 2016 are expected to be slightly lower as a result of the lower contractual earnings at Bécancour and reduced earnings from the sale of unused natural gas transportation.

Bruce Power equity income in 2016 is expected to be consistent with 2015 results. The net impact of the additional ownership interest obtained in Bruce Power in 2015 is anticipated to be largely offset by the increased planned maintenance activity in 2016.

U.S. Power results in 2016 are expected to be higher than 2015 due to the net impact of the additional earnings from the acquisition of the Ironwood natural gas fired, combined cycle power plant and lower marketing margins reflecting the return to normalized levels of costs and decreased volatility of forward natural gas and power prices in the New England market.

Natural Gas Storage earnings are expected to be higher as a modest recovery of seasonal spreads is expected to occur in 2016.

TCPL Management's discussion and analysis 2015 19

Consolidated capital spending, equity investments and acquisition

We expect to spend approximately $6 billion in 2016 on new and existing capital projects. Capital spending includes capital expenditures on growth projects, maintenance capital expenditures and contributions to equity investments. The 2016 capital spending relates to Natural Gas Pipelines projects including NGTL System expansion, the Canadian Mainline, Tuxpan-Tula and Topolobampo; Liquids Pipelines projects including Grand Rapids, Northern Courier and Energy East; and Energy projects including Bruce Power and Napanee. Additionally, on February 1, 2016 we acquired Ironwood Power Plant for approximately US$657 million before post closing adjustments.

20  TCPL Management's discussion and analysis 2015

Natural Gas Pipelines

Our natural gas pipeline network transports natural gas to local distribution companies, power generation facilities and other businesses across Canada, the U.S. and Mexico. We serve more than 80 per cent of the Canadian demand and approximately 15 per cent of the U.S. demand on a daily basis by connecting major natural gas supply basins and markets through:

• wholly-owned natural gas pipelines – 56,600 km (35,200 miles)

• partially-owned natural gas pipelines – 10,700 km (6,700 miles).

We also have regulated natural gas storage facilities in Michigan with a total capacity of 250 Bcf, making us one of the largest providers of natural gas storage and related services in North America.

Strategy at a glance

Optimizing the value of our existing natural gas pipelines 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:

•  greenfield development projects, such as infrastructure for liquefied natural gas (LNG) exports from the west coast of Canada and the Gulf of Mexico

•  additional new pipeline developments within Mexico

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

•  connections to new and growing markets

all of which play a critical role in meeting the transportation requirements for supply and demand for natural gas in North America.

Highlights from 2015

• We were awarded the contract to build, own and operate the36-inch diameter Tuxpan-Tula pipeline in Mexico which is approximately 250 km (155 miles) long and has a contracted capacity of 866 MMcf/d. The pipeline is expected to begin construction in 2016 and be in-service in fourth quarter 2017.

• The NEB approved the NGTL System’s $1.7 billion North Montney Mainline Project on June 11, 2015. Construction remains subject to a positive FID on the proposed Pacific Northwest LNG Project.

• The NEB approved the Canadian Mainline's compliance filing on the NEB 2014 Decision as applied for. The approval was the last step in getting the NEB 2014 Decision implemented and allowing the Canadian Mainline to recognize incentive earnings. 

• The NEB approved the Kings North Connection project on the Canadian Mainline which will increase gas transmission capacity into the greater Toronto area and provide shippers with the flexibility to source growing supplies of Marcellus gas from the U.S. Northeast.

• An agreement was reached with eastern LDCs that resolves their issues with Energy East and the Eastern Mainline Project. The agreement honours our previously stated commitment to ensure that Energy East and the Canadian Mainline's Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs.

• We continued the drop down of U.S. natural gas pipeline assets into TC PipeLines, LP, with the sale of the remaining 30% of GTN in April 2015 and 49.9% of PNGTS on January 1, 2016.

• NGTL signed contracts for an additional 2.7 Bcf/d of new firm natural gas transportation service that will require a further $600 million expansion of the System for its 2018 Facilities program.

TCPL Management's discussion and analysis 2015 21

22  TCPL Management's discussion and analysis 2015

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	24,544 km (15,251 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	14,114 km (8,770 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 Canadian Mainline near the Ontario/Québec border to transport natural gas to the Montréal to Québec City corridor, and connects with the Portland pipeline system that serves the northeast U.S.	50	%
	U.S. pipelines
5	ANR Pipeline	15,109 km (9,388 miles)	Transports natural gas from supply basins to markets throughout the mid-west and south to the Gulf of Mexico.	100	%
5a	ANR Storage	250 Bcf	Provides regulated underground natural gas storage service from facilities located in Michigan
6	Bison	488 km (303 miles)	Transports natural gas from the Powder River Basin in Wyoming to Northern Border in North Dakota. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP	28	%
7	Gas Transmission Northwest (GTN)	2,216 km (1,377 miles)	Transports natural gas from the WCSB and the Rocky Mountains to Washington, Oregon and California. Connects with Tuscarora and Foothills. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP	28	%
8	Great Lakes	3,404 km (2,115 miles)	Connects with the Canadian Mainline near Emerson, Manitoba and 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 66.6 per cent of the system through the combination of our 53.6 per cent direct ownership interest and our 28 per cent interest in TC PipeLines, LP	66.6	%
9	Iroquois	669 km (416 miles)	Connects with Canadian Mainline near Waddington, New York to deliver natural gas to customers in the U.S. northeast	44.5	%
10	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 28 per cent of the system through our interest in TC PipeLines, LP	28	%
11	Northern Border	2,264 km (1,407 miles)	Transports WCSB and Rockies natural gas with connections to Foothills and Bison to U.S. Midwest markets. We effectively own 14 per cent of the system through our 28 per cent interest in TC PipeLines, LP	14	%
12	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 25.8 per cent of the system through the combination of 11.8 per cent direct ownership and our 28 per cent interest in TC PipeLines, LP. Prior to January 1, 2016 we had direct ownership of 61.7 per cent.	25.8	%
13	Tuscarora	491 km (305 miles)	Transports natural gas from GTN at Malin, Oregon to markets in northeastern California and northwestern Nevada. We effectively own 28 per cent of the system through our interest in TC PipeLines, LP	28	%

TCPL Management's discussion and analysis 2015 23

		length	description	effective ownership
	U.S. pipelines
14	TC Offshore1	958 km (595 miles)	Gathers and transports natural gas within the Gulf of Mexico with subsea pipeline and seven offshore platforms to connect in Louisiana with our ANR Pipeline system.	100%
	Mexican pipelines
15	Guadalajara	315 km (196 miles)	Transports natural gas from Manzanillo, Colima to Guadalajara, Jalisco	100	%
16	Tamazunchale	365 km (227 miles)	Transports natural gas from Naranjos, Veracruz in east central Mexico to Tamazunchale, San Luis Potosi and on to El Sauz, Queretaro	100	%
	Under construction
17	Mazatlan Pipeline	413 km* (257 miles)	To deliver natural gas from El Oro to Mazatlan, Sinaloa in Mexico. Will connect to the Topolobampo Pipeline at El Oro	100	%
18	Topolobampo Pipeline	530 km* (329 miles)	To deliver natural gas to Topolobampo, Sinaloa, from interconnects with third-party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico	100	%
19	Tuxpan-Tula Pipeline	250 km* (155 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	%
	NGTL 2016/17 Facilities**	540 km* (336 miles)	An expansion program comprised of 21 integrated projects of pipes, compression and metering to meet new incremental firm service requests received in 2014 on the NGTL System and expected to be completed between 2016 and 2018.	100	%
	In development
20	Coastal GasLink	670 km* (416 miles)	To deliver natural gas from the Montney gas producing region at an expected interconnect on NGTL near Dawson Creek, B.C. to LNG Canada's proposed LNG facility near Kitimat, B.C.	100%
21	Prince Rupert Gas Transmission	900 km* (559 miles)	To deliver natural gas from the North Montney gas producing region at an expected interconnect on NGTL near Fort St. John, B.C. to the proposed Pacific Northwest LNG facility near Prince Rupert, B.C.	100%
22	North Montney Mainline	301 km* (187 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 and the proposed Prince Rupert Gas Transmission project	100%
23	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%
24	Eastern Mainline Project	279 km* (173 miles)	Pipeline and compression facilities expected to be added in the Eastern Triangle of the Canadian Mainline to meet the requirements of the existing shippers as well as new firm service requirements following the conversion of components of the Mainline to facilitate the Energy East project.	100%
	NGTL 2018 Facilities**	88 km* (55 miles)	An expansion program comprised of multiple projects of 20- to 48-inch diameter pipelines, one new compressor unit and multiple meter stations to meet new incremental firm service requests received in 2015 on the NGTL System and expected to be completed in 2018.	100%
* **	Final pipe lengths are subject to changes during construction and/or final design considerations. Facilities are not shown on the map

¹  As at December 31, 2015, TC Offshore was classified as Assets held for sale. See Significant Events for further information.

24  TCPL Management's discussion and analysis 2015

RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Comparable depreciation and amortization is also a non-GAAP measure. See page 4 for more information on non-GAAP measures we use and page 100 for reconciliation to its GAAP equivalent.

year ended December 31
(millions of $)	2015		2014		2013
Comparable EBITDA	3,477		3,241		2,852
Comparable depreciation and amortization	(1,132	)	(1,063	)	(1,013	)
Comparable EBIT	2,345		2,178		1,839
Specific items:
TC Offshore loss on sale	(125	)	—		—
Gas Pacifico/INNERGY gain on sale	—		9		—
NEB 2013 Decision – 2012	—		—		42
Segmented earnings	2,220		2,187		1,881

Natural Gas Pipelines segmented earnings in 2015increased by $33 million compared to 2014 and included a $125 million before tax loss provision ($86 million after tax) as a result of a December 2015 agreement to sell TC Offshore, which is expected to close in early 2016. See Significant Events for more information. Segmented earnings in 2014 included $9 million related to the gain on sale of Gas Pacifico/INNERGY in November 2014 and, in 2013, included $42 million related to the 2012 impact of the NEB 2013 Decision. These amounts have been excluded from our calculation of comparable EBIT. Comparable EBIT and comparable EBITDA are discussed below.

TCPL Management's discussion and analysis 2015 25

year ended December 31
(millions of $)	2015		2014		2013
Canadian Pipelines
Canadian Mainline	1,230		1,334		1,121
NGTL System	934		856		846
Foothills	107		106		114
Other Canadian pipelines1	27		22		26
Canadian Pipelines – comparable EBITDA	2,298		2,318		2,107
Comparable depreciation and amortization	(845	)	(821	)	(790	)
Canadian Pipelines – comparable EBIT	1,453		1,497		1,317
U.S. and International Pipelines (US$)
ANR	232		189		188
TC PipeLines, LP1,2	106		88		72
Great Lakes3	63		49		34
Other U.S. pipelines (Bison4, GTN5, Iroquois1, Portland6)	84		132		183
Mexico (Guadalajara, Tamazunchale)	181		160		100
International and other1,7	4		(10	)	(4	)
Non-controlling interests8	292		241		186
U.S. and International Pipelines – comparable EBITDA	962		849		759
Comparable depreciation and amortization	(224	)	(219	)	(217	)
U.S. and International Pipelines – comparable EBIT	738		630		542
Foreign exchange impact	206		68		15
U.S. and International Pipelines – comparable EBIT (Cdn$)	944		698		557
Business Development comparable EBITDA and comparable EBIT	(52	)	(17	)	(35	)
Natural Gas Pipelines – comparable EBIT	2,345		2,178		1,839
Summary
Natural Gas Pipelines – comparable EBITDA	3,477		3,241		2,852
Comparable depreciation and amortization	(1,132	)	(1,063	)	(1,013	)
Natural Gas Pipelines – comparable EBIT	2,345		2,178		1,839

¹  Results from TQM, Northern Border, Iroquois, TransGas and Gas Pacifico/INNERGY reflect our share of equity income from these investments. In November 2014, we sold our interest in Gas Pacifico/INNERGY.

²  Beginning in August 2014, TC PipeLines, LP began its at-the-market equity issuance program which, when utilized, decreases our ownership interest in TC PipeLines, LP. On October 1, 2014, we sold our remaining 30 per cent direct interest in Bison to TC PipeLines, LP. On April 1, 2015, we sold our remaining 30 per cent direct interest in GTN to TC PipeLines, LP. Effective May 22, 2013 our ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent. On July 1, 2013, we sold 45 per cent of GTN and Bison to TC PipeLines, LP.The following shows our ownership interest in TC PipeLines, LP and our effective ownership interest of GTN, Bison and Great Lakes through our ownership interest in TC PipeLines, LP for the periods presented.

	Ownership percentage as of
	December 31, 2015	April 1,  2015	October 1, 2014	January 1, 2014	July 1, 2013	May 22, 2013
TC PipeLines, LP	28.0	28.3	28.3	28.9	28.9	28.9
Effective ownership through TC PipeLines, LP:
Bison	28.0	28.3	28.3	20.2	20.2	7.2
GTN	28.0	28.3	19.8	20.2	20.2	7.2
Great Lakes	13.0	13.1	13.1	13.4	13.4	13.4

³  Represents our 53.6 per cent direct ownership interest. The remaining 46.4 per cent is held by TC PipeLines, LP.

⁴  Effective October 1, 2014 we have no direct ownership in Bison. Prior to that our direct ownership interest was 30 per cent effective July 1, 2013.

⁵  Effective April 1, 2015 we have no direct ownership in GTN. Prior to that our direct ownership was 30 per cent effective July 1, 2013.

⁶  Represents our 61.7 per cent ownership interest.

26  TCPL Management's discussion and analysis 2015

⁷  Includes our share of the equity income from TransGas and Gas Pacifico/INNERGY as well as general and administration costs relating to our U.S. and International Pipelines. In November 2014, we sold our interest in Gas Pacifico/INNERGY.

⁸  Comparable EBITDA for the portions of TC PipeLines, LP and Portland we do not own.

Canadian Pipelines

year ended December 31
(millions of $)	2015	2014	2013
Net income
Canadian Mainline – net income	213	300	361
Canadian Mainline – comparable earnings	213	300	277
NGTL System	269	241	243
Average investment base
Canadian Mainline	4,784	5,690	5,841
NGTL System	6,698	6,236	5,938

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.

In 2014, the Canadian Mainline operated under the NEB 2013 Decision for the years 2013-2017, which included an approved ROE of 11.5 per cent on deemed common equity of 40 per cent and an incentive mechanism based on total net revenues.

In 2015, the Canadian Mainline began operating under the NEB 2014 Decision which was approved by the NEB in November 2014 and superseded the NEB 2013 Decision. 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 to 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 the six-year fixed toll term.

Canadian Mainline’s comparable earnings in 2015 decreased by $87 million compared to 2014 mainly due to a lower approved ROE on a lower average investment base, lower incentive earnings and a $20 million after-tax contribution from us resulting in a lower realized ROE of 11.15 per cent compared to the realized ROE of 13.18 per cent in 2014. The lower average investment base in 2015 was mainly due to the deferral of the 2014 net revenue surplus in the 2015 investment base.

Comparable earnings in 2014 were $23 million higher than 2013 because of higher incentive earnings partially offset by a lower average investment base. Net income of $361 million recorded in 2013 included $84 million related to the 2012 impact of the NEB 2013 Decision, which was excluded from comparable earnings.

Net income for the NGTL System was $28 million higher in 2015 compared to 2014 mainly due to a higher average investment base and OM&A incentive losses realized in 2014. Net income in 2014 was $2 million lower than 2013 due to the 2014 OM&A incentive losses realized partially offset by a higher average investment base. The 2015 NGTL Settlement included an ROE of 10.1 per cent on deemed common equity of 40 per cent and an annual cost-sharing mechanism for cost variances between actual and fixed OM&A costs. The 2013-2014 NGTL Settlement included an ROE of 10.1 per cent on deemed common equity of 40 per cent and fixed annual OM&A costs with any variance between actual and fixed OM&A accruing to us.

Comparable EBITDA and EBIT for the Canadian pipelines reflect the variances discussed above as well as variances in depreciation, financial charges and income tax which are substantially recovered in revenue on a flow-through basis and, therefore, do not have a significant impact on net income.

TCPL Management's discussion and analysis 2015 27

U.S. and International Pipelines

EBITDA for our U.S. operations is affected by contracted volume levels, actual volumes delivered and the rates charged, and the total cost of providing services.

ANR earnings are also affected by the level of contracting and the determination of rates driven by the market value of its storage capacity, storage related transportation services, and incidental commodity sales. ANR's pipeline and storage volumes and revenues are generally higher in the winter months because of the seasonal nature of its business.

Comparable EBITDA for the U.S. and International Pipelines was US$113 million higher in 2015 than 2014. This was due to the net effect of:

• higher ANR Southeast Mainline transportation revenue, incidental commodity sales and ANR's first quarter 2015 settlement with an owner of adjacent facilities for commercial interruption of ANR's service, partially offset by increased spending on ANR pipeline integrity work

• higher earnings from the Tamazunchale Extension which was placed in service in 2014

• lower contributions from other U.S. Pipelines due to ownership interests in GTN and Bison sold to TC PipeLines, LP in April 2015 and October 2014, respectively. These drop downs increased EBITDA from TC PipeLines, LP and also increased the partially offsetting non-controlling interests

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

Comparable EBITDA for the U.S. and International Pipelines was US$90 million higher in 2014 than 2013. This was due to the net effect of:

• higher earnings from the Tamazunchale Extension which was placed in service in 2014

• higher transportation revenue at Great Lakes mainly due to colder winter weather and increased demand

• lower contributions from GTN and Bison following the reductions in our effective ownership in each pipeline in July 2013 (GTN and Bison) and October 2014 (Bison)

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

Comparable depreciation and amortization

Comparable depreciation and amortization was $69 millionhigher in 2015 compared to 2014 mainly because of a higher investment base for the NGTL System, depreciation for the completed Tamazunchale Extension and the effect of a stronger U.S. dollar. Depreciation and amortization was $50 million higher in 2014 than in 2013 mainly because of a higher investment base for the NGTL System, as well as the impact of the Mainline NEB 2013 Decision.

Business development

In 2015, business development expenses were $35 millionhigher than 2014 primarily due to increased business development activity related to our Mexico projects. Also in third quarter 2014, we recovered amounts from partners for 2013 Alaska Gasline Inducement Act costs. Business development expenses were $18 million lower in 2014 compared to 2013 mainly due to a change in scope on the Alaska project as well as the recovery discussed above. See page 36 for further discussion on Alaska.

28  TCPL Management's discussion and analysis 2015

OUTLOOK

Earnings

Canadian Pipelines

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

In 2016, the Canadian Mainline will continue to operate under the terms of the NEB 2014 Decision. We expect Canadian Mainline 2016 earnings to be slightly lower than 2015 due to a declining investment base. 

We expect the NGTL System investment base to continue to grow as we connect new natural gas supply in northeastern B.C. and western Alberta and respond to continued growth in market demand and that this will continue to have a positive impact on NGTL System earnings in 2016. The terms of the recently negotiated NGTL 2016-2017 Revenue Requirement Settlement generally include a continuation of the ROE, depreciation rates and incentive sharing mechanism as those established in the 2015 Revenue Requirement Settlement.

We also anticipate a modest level of investment in our other Canadian rate-regulated natural gas pipelines, but expect the average investment bases of these pipelines to continue to decline as annual depreciation outpaces capital investment, reducing their year-over-year earnings.

Under the current regulatory model, earnings from Canadian rate-regulated natural gas pipelines are not materially affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contracted capacity levels.

U.S. Pipelines

U.S. Pipeline earnings are affected by the level of contracted capacity and the rates charged to customers. Our ability to recontract or sell capacity at favourable rates is influenced by prevailing market conditions and competitive factors, including alternatives available to end use customers in the form of competing natural gas pipelines and supply sources, in addition to broader conditions that might impact demand from certain customers or market segments. Earnings are also affected by the level of OM&A and other costs, which includes the impact of safety, environmental and other regulators' decisions.

Many of our U.S. natural gas pipelines are backed by long-term take-or-pay contracts that are expected to deliver stable and consistent financial performance.

ANR has secured new long term contracts and extended terms at maximum recourse rates for significant volumes originating from the Utica/Marcellus shale plays with contract start dates through late 2015 that resulted in increased revenues. On January 29th, 2016, ANR submitted a filing with the FERC under Section 4 of the Natural Gas Act seeking to increase its base rates. We anticipate that the proposed rates will take effect in third quarter 2016. These rates are subject to customer refund as a result of the rates ultimately approved by FERC, which is based on the outcome of the regulatory process or settlement negotiations with ANR's customers.

Also, Great Lakes, Northern Border and GTN have benefited from recent market conditions that increased the value of their

services. We continue to seek opportunities to expand upon this success along with those opportunities associated with continued

growth in end use markets for natural gas as we examine commercial, regulatory and operational changes to continue to optimize

our pipelines' positions in response to positive developments in supply fundamentals.

Mexican Pipelines

Overall earnings from our Mexican pipelines are expected to increase in 2016 due to the addition of two new pipelines, Topolobampo and Mazatlan, which are expected to be placed in service in fourth quarter 2016. The 2016 earnings for our current operating assets in Mexico are expected to be consistent with 2015 earnings due to the nature of the long-term contracts underpinning our Mexican pipeline systems.

Capital spending

We spent a total of $2.7 billion in 2015 for our natural gas pipelines in Canada, the U.S. and Mexico, and expect to spend approximately $4 billion in 2016 primarily on the NGTL System expansion projects, ANR maintenance capital, the Tuxpan-Tula and Topolobampo pipelines in Mexico and Canadian Mainline capacity projects.

TCPL Management's discussion and analysis 2015 29

UNDERSTANDING THE 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 pipeline business builds, owns and operates a network of natural gas pipelines in North America that connects gas production to end use markets. The network includes pipelines that are buried underground and transport natural gas under high pressure, compressor stations that act like pumps to move the large volumes of natural gas along the pipeline and meter stations that record the amount of natural gas coming on the network at receipt locations and leaving the network at delivery locations.

Our Major Pipeline Systems

The Natural Gas Pipelines map on page 22 shows our extensive pipeline network in North America that connects major supply sources and markets. Three major pipeline systems account for approximately 80 per cent of the total owned and operated pipe length. These systems are:

NGTL System: This is the major 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 and it is these two supply areas, along with growing demand for firm transportation in the oil sands area, that is driving our large capital program for new pipeline facilities on the NGTL System. The NGTL System is also very 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 basin across Canada to Ontario and Québec to deliver gas to downstream Canadian and U.S. markets. The Canadian Mainline continues this role, but is also transitioning to accommodate additional supply connections that are closer to the market served by this pipeline.

ANR System: This is the largest US-based gas pipeline asset we own and operate and is comparable in length to the Canadian Mainline. This pipeline system was originally designed predominantly to transport natural gas supply from the Gulf Coast and northern Texas areas northward to serve markets in the U.S. Midwest. With the large increase of supply from the U.S. Northeast region, the southeast leg of ANR is transitioning from a predominantly south to north system to a bi-directional system with more gas moving north to south.

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, or payments, for services. Costs of operating the systems 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 costs, 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 them.

Within their respective jurisdictions, the FERC and CRE approve maximum transportation rates. These rates are cost based and are designed to recover the pipeline's investment, operating expenses and a reasonable return for our investors. As the pipeline operator within these jurisdictions, we may negotiate lower rates with shippers.

Sometimes we enter into agreements or settlements with our shippers for tolls and cost recovery, which may include mutually beneficial performance incentives. The regulator must approve a settlement, including any performance incentives, for it to be put into effect.

Generally, Canadian natural gas pipelines request the NEB to approve the pipeline's cost of service and tolls once a year and recover or refund the variance between actual and expected revenues and costs in future years. The Canadian Mainline, however, operates under a fixed toll arrangement for its longer-term firm transportation services and has the flexibility to price its shorter-term and interruptible services in order to maximize its revenue. In addition, the NGTL System has recently reached a two-year revenue requirement settlement for 2016 and 2017 that remains subject to NEB approval.

The FERC does not require U.S. interstate pipelines to calculate rates annually, nor do they allow for the collection or refund of the variance between actual and expected revenue and costs into future years. This difference in U.S. regulation puts our U.S. pipelines

30  TCPL Management's discussion and analysis 2015

at risk for the difference in expected and actual costs and revenues between rate cases. If revenues no longer provide a reasonable opportunity to recover costs, we can file with the FERC for a new determination of rates, subject to any moratorium in effect. Similarly, the FERC may institute proceedings to lower tolls if they consider the return on the capital invested to be too high.

Our Mexican pipelines have approved tariffs, services and related rates. However, most of the contracts underpinning the construction and operation of the facilities in Mexico are long-term, fixed-rate contracts designed to recover the cost of our service.

Business environment and strategic priorities

The North American natural gas pipeline network has developed to connect supply to market. 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 a significant pipeline footprint in the WCSB and transport approximately 75 per cent of total WCSB production to markets within and outside of the basin. Our pipelines also source natural gas, to a lesser degree, from the other major basins including the Appalachian (Utica and Marcellus), Rockies, Williston, Haynesville, Fayetteville and Anadarko as well as the Gulf of Mexico.

North American Natural Gas Basins

Increasing supply

The WCSB spans almost all of Alberta and extends into B.C., Saskatchewan, Yukon and Northwest Territories and is Canada's primary source of natural gas supply. The WCSB is currently estimated to have 150 trillion cubic feet of remaining conventional resources and a technically accessible unconventional resource base of over 700 trillion cubic feet. The total recoverable WCSB resource base has recently more than quadrupled with the advent of technology that can economically access unconventional gas areas in the basin. After decreasing every year since 2007, production from the WCSB increased slightly in 2014 and 2015 to 14.7 Bcf/d. The Montney and Horn River shale play formations and the Liard basin in northeastern B.C. are part of the WCSB and have recently become a significant source of natural gas. We expect production from the Montney play that is currently 3 Bcf/d to grow to approximately 6 Bcf/d by 2020, depending on the economics of exploration and production compared to other, mainly U.S., sources and the progress of proposed B.C. west coast LNG exports.

TCPL Management's discussion and analysis 2015 31

The primary sources of natural gas in the U.S. are the U.S. shale areas, Gulf of Mexico and the Rockies. The U.S. shales are the biggest area of growth which we estimate will meet almost 50 per cent of the overall North American gas demand by 2020. The largest shale developments for natural gas are the Utica/Marcellus basins in the northeast U.S. These basins have grown from essentially no production prior to 2008 to over 18 Bcf/d at the end of 2015. They are forecast to grow to 25 Bcf/d by 2020. Other natural gas supply from shale in the U.S. includes the Haynesville, Barnett, Eagle Ford and Fayetteville plays.

The overall supply of natural gas in North America is forecast to increase significantly over the next decade (by almost 20 Bcf/d or 22 per cent by 2020) and is expected to continue to increase over the long term for several reasons:

• continued technological progress with horizontal drilling and multi-stage hydraulic fracturing or fracking. This is increasing the technically accessible resource base of existing basins and emerging regions, such as the Marcellus and Utica in the U.S. northeast and the Montney and Horn River areas in northeastern B.C.

• these technologies are also being applied to existing oil fields where further recovery of the resource is now possible. There is often associated gas discovered in the exploration and production of liquids-rich hydrocarbon basins (for example, the Bakken oil fields) which also contributes to an increase in the overall gas supply for North America.

The development of shale gas basins that are located close to existing markets, particularly in the northeast U.S., has led to an increase in the number of supply choices and is changing historical gas pipeline flow patterns, generally from long-haul to shorter haul pipelines. Along with our competitors, we have and continue to assess further opportunities to restructure our tolls and service offerings to capture this growing northeast supply and North American demand.

Growing northeast supply has had a positive impact for both the Mainline, with new proposed facilities in eastern Canada, and our ANR pipeline assets, with significant new long-term contracts for service. The increase in supply in northeastern B.C. and northwest Alberta has created opportunities for us to plan and build, subject to regulatory approval and positive final investment decisions (FID), new large pipeline infrastructure on the NGTL System to move the natural gas to markets, including proposed LNG exports and growing Alberta market demand.

Changing demand

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

• natural gas-fired power generation

• petrochemical and industrial facilities

• the production of Alberta oil sands, although new greenfield projects that have not begun construction may be delayed in the current low oil price environment

• exports to Mexico to fuel new power generation facilities.

Natural gas producers continue to progress opportunities to sell natural gas to global markets, which involves connecting natural gas supplies to new LNG export terminals which are proposed primarily along the west coast of B.C. and the U.S. Gulf of Mexico. Assuming the receipt of all necessary regulatory and other approvals, the proposed facilities along the west coast of B.C. are expected to become operational later this decade. The U.S. Gulf Coast also has several LNG export facilities in various stages of development or construction. LNG exports are expected to ramp up from this area, including one facility being commissioned to accommodate full deliveries in early 2016. 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 gas pipelines business is not directly tied to commodity prices given we are a transporter of the commodity and the 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 our shippers may choose to accelerate or delay certain projects. This can impact the timing for the demand of transportation services and/or new gas pipeline infrastructure. There is also a relationship between other fuel sources and their prices, including LNG export contracts which have historically been tied to the price of oil. In this current low oil price environment, the ability of gas producers to advance LNG projects that are tied to oil prices will be more challenging. On the other hand, low natural gas prices compete extremely well with coal-fired electric generation. In 2015, we have seen record levels of power generation with natural gas as the fuel source, particularly in the U.S.

32  TCPL Management's discussion and analysis 2015

More competition

Changes in supply and demand levels and locations have resulted in increased competition for transportation services throughout North America. Development of technology for shale gas supply basins that are closer to markets historically served by long-haul pipelines has resulted in changes to flow patterns of existing natural gas pipeline infrastructure that includes reversing direction of flow and different distances of haul, particularly with the large development of U.S. northeast supply. Along with other pipelines, we have and continue to assess further opportunities to restructure our tolls and service offerings to capture this growing northeast supply and North American demand.

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 gas flow dynamics.

In 2016, we will continue to advance the planned conversion of portions of the Canadian Mainline from natural gas service to crude oil service. The Energy East Pipeline is a planned project, subject to regulatory approval, to convert approximately 3,000 km (1,864 miles) of the Canadian Mainline from the Alberta border to a point in eastern Ontario, southeast of Ottawa, to crude oil service. We announced in August 2015 that we had reached an agreement with eastern LDCs that ensures the net result of the pipeline asset transfer to Energy East and Eastern Mainline Project will provide gas consumers in Eastern Canada with sufficient natural gas transmission capacity and reduced natural gas transmission costs. We are also advancing new facilities in Eastern Canada to enable more supply into our system from sources that are closer to the end market.

We will continue to advance the previously announced 2016/2017 Facilities project on our NGTL System that is driven by contracts for approximately 4 Bcf/d of new firm service transportation requests as well as our new 2018 program that is underpinned by an additional 2.7 Bcf/d of new firm transportation service on the System.

Our ANR Pipeline has operated under the existing rate settlement for nearly 20 years. As a result of changes to traditional supply sources and markets, necessary operational changes, needed infrastructure updates, and evolving regulatory requirements that are driving required investment in facility maintenance, reliability and system integrity, along with an increase in operating costs, we are seeking to restate our transportation rates to appropriately recover our cost of providing service. Our preferred process to restate our rates is to reach a mutually beneficial outcome with our shippers through a settlement negotiation and that will be a focus area for us in 2016. In parallel to the settlement process, on January 29, 2016 ANR filed a Section 4 rate case with FERC.

We will also continue to pursue further connections to growth in supply and markets for our U.S. assets.

The drop down of our remaining U.S. natural gas pipeline assets into TC PipeLines, LP remains an important financing lever for us as we execute our capital growth program, subject to actual funding needs, market conditions, the relative attractiveness of alternate capital sources and the approvals of TC PipeLines LP’s board and our board.

Our focus in Mexico in 2016 is to complete construction and bring into service the Mazatlan and Topolobampo pipelines and to begin permitting and construction of our recently awarded Tuxpan-Tula pipeline. We also remain focused on continuing to operate our existing facilities safely and reliably. We continue to be very interested in the further development of natural gas infrastructure in Mexico and will work to secure future projects that align with our strategic priorities.

TCPL Management's discussion and analysis 2015 33

SIGNIFICANT EVENTS

Canadian Regulated Pipelines

NGTL System

In 2015, we placed approximately $350 million of facilities in service. For 2016,the NGTL System continues to develop a further approximately $7.3 billion of new supply and demand facilities. We have approximately $2.3 billion of facilities that have received regulatory approval with approximately $450 million currently under construction. We have filed for approval for a further approximately $2.0 billion of facilities which are currently under regulatory review. Applications for approval to construct and operate an additional $3.0 billion of facilities have yet to be filed.

Included in our capital program described above is the recently announced 2018 expansion of a further $600 million of facilities required on the NGTL System. The 2018 expansion includes multiple projects totaling approximately 88 km (55 miles) of 20- to 48-inch diameter pipeline, one new compressor, approximately 35 new and expanded meter stations and other associated facilities. Applications to construct and operate the various components of the 2018 expansion program will be filed with the NEB between second quarter and fourth quarter 2016. Subject to regulatory approvals, construction is expected to start in 2017, with all facilities expected to be in service in 2018.

North Montney Mainline

The North Montney Mainline is a pipeline project that will provide substantial new capacity on the NGTL System to meet the transportation requirements associated with rapidly increasing development of natural gas resources in the Montney supply basin in northeastern B.C. The project will connect Montney and other WCSB supply to both existing and new natural gas markets, including LNG markets.

The North Montney Mainline project will consist of two large diameter 42-inch pipeline sections, Aitken Creek and Kahta, totaling approximately 301 km (187 miles) in length, and associated metering facilities, valve sites and compression facilities. The project will also include an interconnection with our proposed Prince Rupert Gas Transmission Project (PRGT) to provide natural gas supply to the proposed Pacific NorthWest (PNW) LNG liquefaction and export facility near Prince Rupert, B.C. We expect to have the Aitken Creek and Kahta sections in service in 2017.

The NEB approved the $1.7 billion project in June 2015 subject to certain terms and conditions. Under one of these conditions, construction on the North Montney Mainline project can only begin after a positive FID has been made on the proposed PNW LNG project.

Merrick Mainline

The proposed Merrick Mainline pipeline project that will transport natural gas sourced through the NGTL System to the inlet of the proposed Pacific Trail Pipeline terminating at the Kitimat LNG Terminal near Kitimat, B.C. has been delayed. In late 2015, the Kitimat LNG partners advised us that they are re-phasing the pace of Kitimat LNG facility development. Since the Merrick Mainline is dependent upon the construction of the downstream infrastructure, the in-service date of the Merrick Mainline will be no earlier than 2021.

The Merrick Mainline is a $1.9 billion project that will consist of approximately 260 kilometres (161 miles) of 48-inch diameter pipe.

Canadian Mainline

Energy East and the Eastern Mainline Project

In October 2014, an application was filed with the NEB for the Energy East project and to transfer a portion of the Canadian Mainline from natural gas service to crude oil service. An application was also filed for the Eastern Mainline Project, consisting of new gas facilities in southeastern Ontario required as a result of the proposed transfer of Canadian Mainline assets to crude oil service for the Energy East project.

Application amendments were filed in December 2015 that reflect the agreement we announced in August 2015 with eastern LDCs resolving their issues with Energy East and the Eastern Mainline Project. The agreement provides gas consumers in eastern Canada with sufficient natural gas transmission capacity and provides for reduced natural gas transmission costs. 

The Eastern Mainline Project capital cost is now estimated to be $2.0 billion with the increase in the cost estimate due to the revised project scope resulting from the LDC agreement and updated cost estimates.

34  TCPL Management's discussion and analysis 2015

The Eastern Mainline Project is conditioned on the approval and construction of the Energy East pipeline. On January 27, 2016, the Canadian federal government announced interim measures for its review of the Energy East pipeline project. The government announced it will undertake additional consultations with aboriginal groups, help facilitate expanded public input into the NEB, and assess upstream GHG emissions associated with the project. The government will seek a six month extension to the NEB’s legislative review and a three month extension to the legislative time limit for the government’s decision. We are reviewing these changes and will assess the impacts to the Eastern Mainline Project.

Other Canadian Mainline Expansions

In addition to the Eastern Mainline Project, new facilities investments totaling approximately $700 million over the 2016 to 2017 period in the Eastern Triangle portion of the Canadian Mainline are required to meet contractual commitments from shippers.

U.S. Pipelines

ANR Section 4 Rate Case

ANR Pipeline filed a Section 4 Rate Case on January 29, 2016 that requests an increase to ANR's maximum transportation rates. Shifts in ANR’s traditional supply sources and markets, necessary operational changes, needed infrastructure updates, and evolving regulatory requirements are driving required investment in facility maintenance, reliability and system integrity as well as an increase in operating costs that have resulted in the current tariff rates not providing a reasonable return on our investment. We will also pursue a collaborative process to find a mutually beneficial outcome with our customers through settlement negotiations.  ANR's last rate case filing was more than 20 years ago. 

Sale of GTN and PNGTS to TC PipeLines, LP

In April 2015, we closed the sale of our remaining 30 per cent interest in GTN to TC PipeLines, LP, for an aggregate purchase price of US$457 million. Proceeds were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TC PipeLines, LP.

On January 1, 2016, we closed the sale of a 49.9 per cent interest of our total 61.7 per cent interest in PNGTS to TC PipeLines, LP for US$223 million including the assumption of US$35 million of proportional PNGTS debt.

TC Offshore

On December 18, 2015, we entered into an agreement to sell TC Offshore to a third party and expect the sale to close in early 2016. As a result, at December 31, 2015, the related assets and liabilities were classified as held for sale and were recorded at their fair values less costs to sell. This resulted in a pre-tax loss provision of $125 million recorded in 2015.

Mexican Pipelines

Topolobampo and Mazatlan Pipelines

The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver gas to Topolobampo, Sinaloa from interconnects with third party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico. The Mazatlan project is a 413 km (257 miles), 24-inch pipeline running from El Oro to Mazatlan within the state of Sinaloa with a capacity of 200 MMcf/d and an estimated cost of US$400 million. Both projects are supported by 25-year contracts with the CFE and are in their final construction stages with expected in-service dates in late 2016.

Tuxpan-Tula Pipeline

In November 2015, we were awarded the contract to build, own and operate the US$500 million, 36 inch, 250 km (155 mile) Tuxpan-Tula pipeline with a contracted capacity of 886 MMcf/d for 25 years with the CFE. The pipeline will originate in Tuxpan in the state of Veracruz and extend through the states of Puebla and Hidalgo, supplying natural gas to each of those jurisdictions as well as the central region of Mexico. The pipeline will serve new power generating facilities as well as existing power plants that plan to switch from fuel oil to natural gas as their base fuel. Physical construction is expected to begin in 2016 with a planned in-service date in fourth quarter 2017. 

TCPL Management's discussion and analysis 2015 35

LNG Pipeline Projects

Prince Rupert Gas Transmission

In June 2015, PNW LNG announced a positive FID for its proposed liquefaction and export facility, subject to two conditions. The first condition, approval by the Legislative Assembly of B.C. of a Project Development Agreement between PNW LNG and the Province of B.C., was satisfied in July 2015. The second condition is a positive regulatory decision on PNW LNG’s environmental assessment by the Government of Canada, which has not yet been received.

In third quarter 2015, we received all remaining permits from the B.C. Oil and Gas Commission (BC OGC) which completes the eleven permits required to build and operate PRGT. Environmental permits for the project were received in November 2014 from the B.C. Environmental Assessment Office (BC EAO). With these permits, PRGT has all of the primary regulatory permits required for the project.

We remain on target to begin construction following confirmation of a FID by PNW LNG. The in-service date for PRGT is estimated to be 2020 but will be aligned with PNW LNG’s liquefaction facility timeline.

We are continuing our engagement with Aboriginal groups and have now signed project agreements with ten First Nation groups along the pipeline route. Project agreements outline financial and other benefits and commitments that will be provided to each First Nation for as long as the project is in service.

PRGT is a 900 km (559 mile) natural gas pipeline that will deliver gas from the Montney producing region at an expected interconnect on the NGTL System near Fort St. John, B.C. to PNW LNG's proposed LNG facility near Prince Rupert, B.C. Should the project not proceed, our project costs (including carrying charges) are fully recoverable.

Coastal GasLink

We are continuing our engagement with Aboriginal groups along our pipeline route and have now announced long-term project agreements with eleven First Nations. These project agreements outline financial and other benefits and commitments that will be provided to each First Nation for as long as the pipeline remains in service.

We also continue to engage with stakeholders along the pipeline route and are progressing detailed engineering and construction planning work to refine the capital cost estimate. In response to feedback received, we have applied for a minor route amendment to the BC EAO in order to provide an option in the area of concern. It is anticipated that approval for this route amendment will be received in first quarter 2016. We have received eight of ten pipeline and facilities permits from the BC OGC and anticipate receiving the remaining two permits in first quarter 2016. With these permits, Coastal GasLink will hold all of the required primary regulatory permits for the project.

Pending the receipt of regulatory approvals and a positive FID from the LNG Canada joint venture participants in 2016, we will begin construction. Our pipeline in-service date will be scheduled to coincide with the operational requirements of the LNG Canada facility to be built in Kitimat, B.C. Should the project not proceed, our project costs (including carrying charges) are fully recoverable.

Coastal GasLink is a 670 km (416 mile) pipeline that will deliver natural gas from the Dawson Creek, BC area, to the LNG Canada's proposed gas liquefaction facility near Kitimat, BC.

Alaska LNG Project

On November 24, 2015, we sold our interest in the Alaska LNG project to the State of Alaska. The proceeds of US$65 million from this sale provide a full recovery of costs incurred to advance the project since January 1, 2014 including a carrying charge. With this sale, our involvement in developing a pipeline system for commercializing Alaska North Slope natural gas ceases.

36  TCPL Management's discussion and analysis 2015

BUSINESS RISKS

The following are risks specific to our natural gas pipelines business. See page 86 for information about general risks that affect the company as a whole, including other operational risks, health, safety and environment (HSE) risks and financial risks.

WCSB supply for downstream connecting pipelines

Many of our North American natural gas pipelines and transmission infrastructure assets depend largely on supply from the WCSB. We continue to monitor any changes in our customer’s gas production plans and how these changes may impact our existing assets and new project schedules. There is competition for this supply from several pipelines within the basin. An overall decrease in production and/or competing demand for supply could impact throughput on WCSB connected pipelines that, in turn, could impact overall revenues generated. The WCSB has considerable reserves, but the amount actually produced depends on many variables, including the price of natural gas, basin-on-basin competition, downstream pipeline tolls, demand within the basin and the overall value of the reserves, including liquids content.

Market access

We compete for market share with other natural gas pipelines. New supply basins being developed closer to markets we have historically served may reduce the throughput and/or distance of haul on our existing pipelines and impact revenue. The long-term competitiveness of our pipeline systems and the avoidance of bypass pipelines will depend on our ability to adapt to changing flow patterns by offering alternative transportation services at prices that are acceptable to the market.

Competition for greenfield expansion

We face competition from other pipeline companies seeking opportunities to invest in greenfield natural gas pipeline development opportunities. This competition could result in fewer projects being available that meet our investment hurdles or projects that proceed with lower overall financial returns.

Demand for pipeline capacity

Demand for pipeline capacity is ultimately the key driver that enables pipeline transportation services to be sold. Demand for pipeline capacity is created by supply and market competition, variations in economic activity, weather variability, natural gas pipeline and storage competition and pricing of alternative fuels. Renewal of expiring contracts and the opportunity to charge and collect a toll that the market accepts depends on the overall demand for transportation service. A change in the level of demand for our pipeline transportation services could impact revenues.

Commodity Prices

The cyclical supply and demand nature of commodities and related pricing can have a secondary impact on our business where our shippers may choose to accelerate or delay certain projects. This can impact the timing for the demand of transportation services and/or new gas pipeline infrastructure. As well, sustained low gas prices could impact our shippers' financial situation and their ability to meet their transportation service cost obligations.

TCPL Management's discussion and analysis 2015 37

Regulatory risk

Decisions by regulators can have an impact on the approval, timing, construction, operation and financial performance of our natural gas pipelines. There is a risk that decisions are delayed or are not favourable and therefore could impact revenues and the opportunity to further invest capital in our systems. There is also risk of a regulator disallowing a portion of our prudently incurred costs, now or at some point in the future.

The regulatory approval process for larger infrastructure projects, including the time it takes to receive a decision, could be slowed or unfavorable due to the influence from the evolving role of activists and their impact on public opinion and government policy related to natural gas pipeline infrastructure development.

Increased scrutiny of operating processes by the regulator or other enforcing agencies has the potential to increase operating costs. There is a risk of an impact to income if these costs are not fully recoverable.

We continuously monitor regulatory developments and decisions to determine the possible impact on our gas pipelines business. We also work closely with our stakeholders in the development of rate, facility and tariff applications and negotiated settlements, where possible.

Construction and Operations

Constructing and operating our pipelines to ensure transportation services are provided safely and reliably is essential to the success of our business. Interruptions in our pipeline operations impacting our throughput capacity and may result in reduced revenue and can affect corporate reputation as well as customer and public confidence in our operations. We manage this by investing in a highly skilled workforce, hiring third party inspectors during construction, operating prudently, using risk-based preventive maintenance programs and making effective capital investments. We use pipeline inspection equipment to regularly check the integrity of our pipelines, and repair or replace sections whenever necessary. We also calibrate the meters regularly to ensure accuracy, and continuously maintain compression equipment to ensure safe and reliable operation.

38  TCPL Management's discussion and analysis 2015

Liquids Pipelines

Our existing liquids pipeline infrastructure connects Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas, as well as connecting U.S. crude oil supplies from the Cushing, Oklahoma hub to refining markets in the U.S Gulf Coast. Our proposed future pipeline infrastructure would also connect Canadian and U.S. crude oil supplies to refining markets in eastern Canada and overseas export markets, and expand capacity for Canadian and U.S. crude oil to access U.S. markets. We will also pursue enhancing our transportation service offerings to other areas of the liquids pipelines business value chain.

Strategy at a glance

Our focus is on accessing and delivering growing North American liquids supply to key markets by expanding our liquids pipelines infrastructure to deliver directly from supply regions seamlessly along a contiguous path to the market.

Although crude oil production growth is currently slowing as a result of slow demand growth, we are focused on maximizing the value from our current operating assets, securing organic growth around these assets, identifying acquisition opportunities in the current lower crude oil price environment and positioning our business development activities to capture opportunities when the environment recovers.

We are also expanding transportation service offerings to other areas of the liquids pipelines business value chain such as condensate transportation or ancillary services such as short and long term storage of liquids and liquids marketing, which complement our pipeline transportation infrastructure.

Continued development and construction of our proposed infrastructure projects will provide North America with a crucial liquids transportation network to transport growing supply directly to key markets and provide opportunities for us to further expand our liquids pipelines business.

Highlights from 2015

• Increased average throughput on Keystone Pipeline by 30,000 Bbl/d and increased long term contracts to 545,000 Bbl/d

• Finalized definitive agreements with Magellan Midstream Partners L.P. (Magellan), to jointly develop a connection between our Houston Tank Terminal and the Magellan delivery system enhancing our crude oil infrastructure connectivity to Houston and Texas City area refineries and terminals

• Finalized definitive agreements between Keyera Corp. and our Grand Rapids pipeline to enable Alberta oil sands producers to gain access to a reliable and cost effective source of diluent

• Created a liquids marketing business to expand our service offerings to other areas of the liquids pipelines business value chain. Marketing transactions will commence in 2016

• Throughout 2015, the Keystone XL cross border permit application experienced multiple delays from the DOS and was ultimately denied. We have launched legal and NAFTA challenges in response to the denial. We remain supportive of Keystone XL and are reviewing our options which include filing a new U.S. Presidential permit application

• Achieved significant construction progress on our regional Alberta projects, the Grand Rapids and Northern Courier pipeline systems

• Filed an amendment to Energy East’s existing application with the NEB that adjusts the proposed route, scope and capital cost of the Energy East pipeline project based on extensive landowner, environmental, community and customer input

TCPL Management's discussion and analysis 2015 39

40  TCPL Management's discussion and analysis 2015

We are the operator of all of the following pipelines and properties.

		length	description	ownership
	Liquids pipelines
25	Keystone Pipeline System	4,247 km (2,639 miles)	Transports crude oil from Hardisty, Alberta, to U.S. markets at Wood River and Patoka Illinois, Cushing, Oklahoma, and Port Arthur, Texas	100	%
26	Cushing Marketlink and Terminal		Terminal and pipeline facilities to transport crude oil from the market hub at Cushing, Oklahoma to the Port Arthur, Texas refining market on facilities that form part of the Keystone Pipeline System	100	%
	Under construction
27 28	Houston Lateral and Houston Terminal	77 km (48 miles)	To extend the Keystone Pipeline System to the Houston, Texas refining market	100	%
29	Grand Rapids Pipeline	460 km (287 miles)	To transport crude oil and diluent between the producing area northwest of Fort McMurray, Alberta and the Edmonton/Heartland, Alberta market region	50	%
30	Northern Courier Pipeline	90 km (56 miles)	To transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta	100	%
	In development
31	Bakken Marketlink		To transport crude oil from the Williston Basin producing region in North Dakota and Montana to Cushing, Oklahoma on facilities that form part of Keystone XL	100	%
32	Keystone Hardisty Terminal		Crude oil terminal located at Hardisty, Alberta, providing western Canadian producers with crude oil batch accumulation tankage and access to the Keystone Pipeline System	100	%
33	Keystone XL	1,897 km (1,179 miles)	To transport crude oil from Hardisty, Alberta to Steele City, Nebraska to expand capacity of the Keystone Pipeline System	100	%
34 35	Heartland Pipeline and TC Terminals	200 km (125 miles)	Terminal and pipeline facilities to transport crude oil from the Edmonton/Heartland, Alberta region to facilities in Hardisty, Alberta	100	%
36	Energy East Pipeline	4,600 km (2,850 miles)	To transport crude oil from western Canada to eastern Canadian refineries and export markets	100	%
37	Upland Pipeline	460 km (285 miles)	To transport crude oil from, and between, multiple points in North Dakota and interconnect with the Energy East Pipeline at Moosomin, Saskatchewan	100	%

TCPL Management's discussion and analysis 2015 41

RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Comparable depreciation and amortization is also a non-GAAP measure. See page 4 for more information on non-GAAP measures we use and page 100 for reconciliation to its GAAP equivalent.

year ended December 31
(millions of $)	2015		2014		2013
Comparable EBITDA	1,322		1,059		752
Comparable depreciation and amortization	(266	)	(216	)	(149	)
Comparable EBIT	1,056		843		603
Specific item:
Keystone XL impairment charge	(3,686	)	—		—
Segmented (loss)/earnings	(2,630	)	843		603

Liquids Pipelines segmented earnings decreased by $3,473 million to a segmented loss of $2,630 million in 2015 compared to 2014. The segmented loss included a $3,686 million pre-tax impairment charge related to Keystone XL and related projects. See Significant Events on page 46 and Critical accounting estimates on page 93 for more information. This amount has been excluded from our calculation of comparable EBIT. The remainder of the Liquids Pipelines segmented earnings are equivalent to comparable EBIT, which, along with comparable EBITDA, are discussed below.

year ended December 31
(millions of $)	2015		2014		2013
Keystone Pipeline System	1,345		1,073		766
Liquids Pipelines Business Development	(23	)	(14	)	(14	)
Liquids Pipelines – comparable EBITDA	1,322		1,059		752
Comparable depreciation and amortization	(266	)	(216	)	(149	)
Liquids Pipelines – comparable EBIT	1,056		843		603
Comparable EBIT denominated as follows:
Canadian dollars	236		215		201
U.S. dollars	640		570		389
Foreign exchange impact	180		58		13
Liquids Pipelines – comparable EBIT	1,056		843		603

Comparable EBITDA

Comparable EBITDA for the Keystone Pipeline System was $272 millionhigher this year than in 2014. This increase was primarily due to:

• higher volumes

• incremental earnings from the Keystone Gulf Coast extension which was placed in service in January 2014

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

from our U.S. operations.

Comparable EBITDA for the Keystone Pipeline System was $307 millionhigher in 2014 than in 2013. This increase was primarily due to:

• incremental earnings from the Keystone Gulf Coast extension which was placed in service in January 2014

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

from our U.S. operations.

42  TCPL Management's discussion and analysis 2015

Comparable depreciation and amortization

Comparable depreciation and amortization was $50 millionhigher in 2015 than in 2014 mainly due to the effect of a stronger U.S. dollar. Comparable depreciation and amortization was $67 million higher in 2014 than in 2013 mainly due to the Keystone Gulf Coast extension being placed in service.

OUTLOOK

Earnings

Excluding specified items, our 2016 earnings are expected to be slightly lower than our 2015 earnings due to short-term contracts expiring on Cushing Marketlink and weakened market conditions related to the lower crude oil price environment. Following our Keystone XL impairment charge, future expenditures on the project will be expensed pending further advancement of this project and we have ceased capitalizing interest on the project effective November 6, 2015, the date of the Presidential permit denial.

Over time, we expect Liquids Pipelines' earnings to increase as projects currently under construction and in development are placed in service.

Capital spending

We spent a total of $1.3 billion in 2015 on capital spending in Liquids Pipelines. We expect to spend approximately $1.2 billion on capital spending and equity investments in 2016, primarily on Grand Rapids Phase 1, Northern Courier and Energy East.

UNDERSTANDING THE LIQUIDS PIPELINES BUSINESS

Our liquids business currently consists of pipelines which efficiently move crude oil from major supply sources to markets where crude oil can be refined into various petroleum products and ancillary services such as short and long term storage of liquids. We have established a liquids marketing business to expand into other areas of the liquids business value chain. The Keystone Pipeline System, our largest liquids pipelines asset, moves approximately 20 per cent of western Canadian crude oil exports to key refining markets in the U.S. Mid-West and the Gulf Coast and has transported over 1.1 billion barrels of crude oil since operations began in 2010.

We generate earnings from our liquids business mainly by providing pipeline capacity to shippers supported by long term contracts with fixed monthly payments that are not linked to actual throughput volumes or to the price of the commodity. Uncontracted capacity is offered to the market on a spot basis which provides opportunities to generate incremental earnings.

The terms of service and fixed monthly payments are determined by transportation service arrangements negotiated with shippers. These long term arrangements provide for the recovery of costs we incur to construct and operate the system.

Business environment and strategic priorities

Over the past decade, North American crude oil production has increased significantly. However, slowing global demand combined with OPEC's market share strategy of increased production has resulted in a current global oversupply situation, which continues to put downward pressure on crude oil prices. Supply from high cost producers is expected to decrease in this lower price environment throughout the course of the year while supply and demand are expected to evolve to a more balanced position towards the end of the year.

Our liquids pipelines business is well positioned to endure the impact of short term commodity price fluctuations and supply adjustments. Our existing operations and development projects are supported by long term contracts where we have agreed to provide pipeline capacity to our customers in exchange for fixed monthly payments. The cyclical supply and demand nature of commodities and their price movements can have a secondary impact on our business where our shippers may choose to accelerate or delay certain new projects. This can impact the timing for the demand of transportation services and/or new liquids infrastructure.

We continue to advance a number of growth opportunities in the near term and will closely monitor the market place for strategic asset acquisition opportunities. Commodity price fluctuations are a normal part of the business cycle. Longer-term, we expect global demand for crude oil will continue to grow, ultimately resulting in continued growth in North American crude oil supply production and demand for new pipeline infrastructure. Our growing position in the liquids transportation business is creating a significant platform to capture these future growth opportunities.

TCPL Management's discussion and analysis 2015 43

Supply outlook

Canada

Alberta produces the majority of the crude oil in the WCSB which is the primary source of crude oil supply for the Keystone Pipeline System. In its 2015 Crude Oil Forecast, Markets and Transportation report, the Canadian Association of Petroleum Producers (CAPP) estimates 2016 WCSB crude oil production will reach 1.3 million Bbl/d of conventional crude oil and condensate and 2.5 million Bbl/d of oil sands crude oil, for a total of approximately 3.8 million Bbl/d. The report forecasts WCSB crude oil production will increase to 4.4 million Bbl/d by 2020 and to 5.2 million Bbl/d by 2030. Even in the current challenging price environment, CAPP estimates current projects that are either in advanced stages of development or construction will add nearly 720,000 Bbl/d of WCSB supply between 2016 and 2020.

According to the May 2015 Alberta’s Energy Reserves 2014 and Supply/Demand Outlook 2015-2024, the Alberta Energy Regulator (AER) estimates there is approximately 166 billion barrels of economically and technically recoverable conventional and oil sands reserves in Alberta. Oil sands projects have a long reserve life. In its 2014 Responsible Canadian Energy report, CAPP estimates a typical oil sands mine has a 25 to 50 year lifespan, while an in-situ operation will run 10 to 15 years on average. This longevity aligns with the producer's desire to secure long term connectivity of their reserves to market. The Keystone Pipeline System, as well as projects under development such as the proposed Energy East Pipeline, are underpinned by long term contracts.

In November 2015, the Alberta Government developed a Climate Leadership Plan which includes phasing out of coal-generated electricity, implementing a new carbon price on GHG emissions, capping oil sands emissions at a maximum of 100 Megatonnes per year and reducing methane emissions. While details on this plan are forthcoming, it is anticipated that this plan would still allow for significant oil sands supply growth and would support future development of pipeline infrastructure to connect WCSB crude oil supply to markets.

U.S.

The U.S. Energy Information Administration (EIA) forecasts over 1.0 million Bbl/d of U.S. production growth from 2015 to 2020, peaking at 10.6 million Bbl/d by 2020. Higher production volumes result mainly from technological advancements in the development of shale oil production. EIA forecasts shale oil production peaking at approximately 5.6 million Bbl/d by 2020 and declining after 2022.

North American Liquids Basins

44  TCPL Management's discussion and analysis 2015

U.S. shale oil supply growth originates primarily from the Williston basin in North Dakota and Montana, the Permian basin in south Texas and Woodford shale area of the Arkoma basin in Oklahoma. These shale production areas also represent some of the sources of crude oil supply for our Cushing Marketlink system.

The growth in U.S. production has contributed to increased crude oil supply at the Cushing, Oklahoma market hub and has resulted in increased demand for additional pipeline capacity between Cushing, Oklahoma and the U.S. Gulf Coast refining market. Our Cushing Marketlink system, with connectivity to Houston and Port Arthur, Texas and Lake Charles, Louisiana refining markets, is well positioned to transport this growing supply.

Even with growth in U.S. crude oil production, which displaced foreign light imports from countries such as Nigeria and Saudi Arabia, the EIA report predicts the U.S. will remain a net importer of crude oil, importing 7.6 million Bbl/d into 2040. U.S. Gulf Coast refineries are mainly configured to process heavy and medium crude oil and cannot easily switch to processing light shale oil in large quantities without significant capital investments. U.S. Gulf Coast refineries currently require approximately 3.2 million Bbl/d of heavy and medium crude oil, and the level of demand is not expected to change significantly in the near or longer term. The Keystone Pipeline System is well positioned to deliver Canadian crude oil to this significant market.

The U.S. government recently lifted the 40 year ban on crude oil exports in December 2015 which removed the Federal Government restrictions on the export of crude oil. The decision is expected to help draw the supply from U.S. producing regions, including Cushing, Oklahoma, to tidewater and we anticipate seeing an increase in demand for coastal storage and export terminal facilities. Our Houston Lateral and Terminal is well positioned to capture the growing demand in this market.

Strategic priorities

We are focused on advancing our current portfolio of commercially secured projects to connect growing Canadian and U.S. crude oil supply to key markets, maximizing the value from our current operating assets, identifying acquisition opportunities and expanding across our liquids pipelines business value chain.

We continue to extend our Keystone Pipeline System’s access in the U.S. Gulf Coast market to over 4.5 million Bbl/d of regional refinery centres in Houston and Port Arthur, Texas and Lake Charles, Louisiana. Expanding the Keystone Pipeline System’s market access reach is expected to enhance both short and long haul volumes. Our joint venture with Magellan Midstream Partners, a connection between our Houston Lateral and Terminal and Magellan's Houston and Texas City, Texas delivery system, will enhance our crude oil connectivity in the Houston area. In 2015, we agreed to build a lateral to the CITGO Petroleum (CITGO) Sour Lake, Texas terminal which supplies the Lake Charles, Louisiana marketplace.

Securing regulatory approval for our $15.7 billion Energy East pipeline remains a key priority. In late 2015, we filed an amendment to the existing project application with the NEB that adjusts the proposed route, scope and capital cost of the project reflecting refinements and scope changes including the removal of the port in Québec. The project will continue to serve the three eastern Canadian refineries along the route in Montréal and Québec City, Québec and Saint John, New Brunswick.

Within Alberta, we are leveraging our extensive natural gas pipeline footprint and experience to develop a regional liquids pipelines business. Growth in oil sands production is driving the need for new intra-Alberta pipelines, like our 50 per cent interest in the Grand Rapids Pipeline, that can move crude oil production from the source to market hubs at Edmonton/Heartland and Hardisty, Alberta as well as diluent from Edmonton/Heartland region to the production area in northern Alberta. Our joint venture with Keyera Corp. will enhance our ability to access a reliable and cost effective source of diluent for the Grand Rapids Pipeline. In addition, our Northern Courier Pipeline will facilitate movements from new oil sands mine supply to market. When supported by market conditions, the Heartland Pipeline and TC Terminals and Keystone Hardisty Terminal projects will support these market hubs which will allow shippers to connect with the Keystone Pipeline System, Energy East Pipeline and other pipelines that transport crude oil outside of Alberta and ultimately provide our customers with a contiguous seamless path from production to market.

We have created a liquids marketing business which will provide incremental revenue by entering into short- or long-term pipeline or storage terminal capacity contracts, primarily on our assets, increasing the utilization of those assets and earning the market value of the capacity.

In this challenging crude oil price environment, we will closely monitor the market place for strategic asset acquisitions to enhance our system connectivity or expand our footprint within North America. We remain disciplined in our approach and will position our business development activities strategically to capture the opportunities as the business environment recovers.

TCPL Management's discussion and analysis 2015 45

SIGNIFICANT EVENTS

Keystone Pipeline System

In fourth quarter 2015, we secured additional long term contracts bringing our total contract position up to 545,000 Bbl/d. By the end of 2015, the Keystone Pipeline System had delivered more than 1.1 billion barrels of crude oil to U.S. markets since it began operating in 2010.

CITGO Sour Lake Pipeline

In 2015, we entered into an agreement with CITGO to construct a US$65 million pipeline connection between the Keystone Pipeline System to provide access to CITGO’s Sour Lake, Texas terminal, which supplies their 425,000 Bbl/d Lake Charles, Louisiana refinery. The connection is targeted to be operational in fourth quarter 2016.

Houston Lateral and Terminal

Construction continues on the Houston Lateral pipeline and tank terminal which will extend the Keystone Pipeline System to Houston, Texas. The terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are expected to be completed in second quarter 2016.

On January 13, 2016, we entered into an agreement with Magellan to connect our Houston Terminal to Magellan's Houston and Texas City, Texas delivery system. We will own 50 per cent of this US$50 million pipeline project which will enhance connections for our Keystone Pipeline System to the Houston market. The pipeline is expected to be operational during the first half of 2017, subject to the receipt of all necessary rights-of-way, permits and regulatory approvals.

Keystone XL

The decision on the Keystone XL permit application was delayed throughout 2015 by the DOS and was ultimately denied in November 2015.

At December 31, 2015, as a result of the denial of the Presidential permit, we evaluated our investment in Keystone XL and related projects, including Keystone Hardisty Terminal, for impairment. As a result of our analysis, we determined that the carrying amount of these assets was no longer recoverable, and recognized a total non-cash impairment charge of $3.7 billion ($2.9 billion after-tax). The impairment charge was based on the excess of the carrying value of $4.3 billion over the fair value of $621 million, which includes $93 million fair value for Keystone Hardisty Terminal. The Keystone Hardisty Terminal remains on hold with an estimated in-service date to be driven by market need. The calculation of this impairment is discussed further in the Critical accounting estimates section on page 93.

In November 2015, we withdrew our application to the Nebraska Public Service Commission for approval of the route for Keystone XL in the state. The application was initially filed in October 2015. The withdrawal was made without prejudice to potentially refile if we elect to pursue the project.

On January 5, 2016, the South Dakota Public Utility Commission accepted Keystone’s certification that it continues to comply with the conditions in its existing 2010 permit authority in the state.

On January 6, 2016, we filed a Notice of Intent to initiate a claim under Chapter 11 of the NAFTA in response to the U.S. Administration’s decision to deny a Presidential permit for the Keystone XL Pipeline on the basis that the denial was arbitrary and unjustified. Through the NAFTA claim, we are seeking to recover more than US$15 billion in costs and damages that we estimated to have suffered as a result of the U.S. Administration’s breach of its NAFTA obligations. This litigation is in a preliminary stage and the likelihood of success and resulting impact on our financial position or results of operation is unknown at this time.

On the same day, we filed a lawsuit in the U.S. Federal Court in Houston, Texas, asserting that the U.S. President’s decision to deny construction of Keystone XL exceeded his power under the U.S. Constitution. The federal court lawsuit does not seek damages, but rather a declaration that the permit denial is without legal merit and that no further Presidential action is required before construction of the pipeline can proceed.

We remain supportive of Keystone XL and continue to review our options, including filing a new application for a cross-border permit.

46  TCPL Management's discussion and analysis 2015

Energy East Pipeline

In April 2015, we announced that the proposed marine terminal and associated tank terminal in Cacouna, Québec will not be built as a result of the recommended reclassification of the beluga whale, indigenous to the site, as an endangered species. Following consultation of stakeholders and shippers, we announced in November 2015 the intention to amend the Energy East application to remove a port in Québec and proceed with a single marine terminal in Saint John, New Brunswick. On December 17, 2015, we filed an amendment to the existing project application with the NEB that adjusted the proposed route, scope and capital cost of the project reflecting refinement and scope change including the removal of the port in Québec. The project will continue to serve the three eastern Canadian refineries along the route in Montréal and Québec City, Québec and Saint John, New Brunswick.

Changes to the project schedule and scope, as reflected in the amendment, have contributed to a new project capital cost of $15.7 billion, excluding the transfer of Canadian Mainline natural gas assets. Of the total long-term shipping commitments for the project of 995,000 bbl/d, with an average term of 19 years, 725,000 bbl/d designate the Québec refineries or Saint John, New Brunswick as delivery points. A total of 270,000 bbl/d remains under contract for delivery to the Québec market, including a Québec based marine terminal, and without a Saint John, New Brunswick delivery point. Discussions are ongoing with those shippers to remove the Québec marine terminal from the terms of their shipping contracts.

Subject to regulatory approvals, the pipeline is anticipated to commence deliveries by the end of 2020. However, on January 27, 2016, the Canadian federal government announced interim measures for pipeline reviews, including of the Energy East project. The government announced it will undertake additional consultations with aboriginal groups, help facilitate expanded public input into the NEB and assess Energy East's impact on upstream GHG emissions. The government will seek a six month extension to the NEB’s legislative review and a three month extension to the legislative time limit for the government’s decision which will extend the total review time to 27 months. We are reviewing these changes and will assess the impact to the project.

Northern Courier Pipeline

Construction continues on the pipeline system to transport bitumen and diluent between the Fort Hills mine site and Suncor Energy’s terminal located north of Fort McMurray, Alberta. The project is fully underpinned by long term contracts with the Fort Hills partnership. We expect the pipeline system to be ready for service in 2017.

Heartland Pipeline and TC Terminals

The Heartland Pipeline is a crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta. TC Terminals is a terminal facility in the Heartland industrial area north of Edmonton, Alberta located at the start of the Heartland Pipeline. Construction has been delayed and the in-service date for the projects will be determined and aligned with industry and our customer's requirements.

Grand Rapids Pipeline

Grand Rapids Pipeline is a dual 36-inch/20-inch crude oil and diluent pipeline system connecting producing areas northwest of Fort McMurray, Alberta to terminals in the Edmonton/Heartland, Alberta region. We have a joint partnership with Brion Energy to develop the Grand Rapids Pipeline with each owning 50 per cent of the pipeline project. We are constructing the project and will operate Grand Rapids once complete.

Construction is progressing on phase one, which includes a 20-inch pipeline from northern Alberta to Edmonton, Alberta and a 36-inch pipeline between Edmonton and Fort Saskatchewan, Alberta. We anticipate phase one to begin crude oil transportation service in 2017. The construction of phase two, the larger 36-inch pipeline, is currently delayed and the in-service date will be subject to sufficient market demand.

In August 2015, we announced a joint venture between Grand Rapids and Keyera Corp. for provision of diluent transportation service on the 20-inch pipeline between Edmonton and Fort Saskatchewan, Alberta, which is anticipated to be in service in the second half of 2017. The joint venture will be incorporated into phase one of Grand Rapids and it will provide enhanced diluent supply alternatives to our shippers.

Upland Pipeline

In April 2015, we filed an application to obtain a U.S. Presidential permit for the Upland Pipeline. The pipeline will provide crude oil transportation from and between multiple points in North Dakota and interconnect with the Energy East Pipeline System at Moosomin, Saskatchewan. Subject to regulatory approvals, we anticipate the Upland Pipeline to be in service in 2020. The commercial contracts we have executed for Upland Pipeline are conditioned on the Energy East project proceeding. We are reviewing the Canadian federal government's interim measures for pipeline reviews and will assess the impact to Upland Pipeline.

TCPL Management's discussion and analysis 2015 47

BUSINESS RISKS

The following are risks specific to our liquids pipelines business. See page 86 for information about general risks that affect the company as a whole, including other operational risks, health, safety and environment (HSE) risks, and financial risks.

Operational

Optimizing and maintaining availability of our liquids pipelines is essential to the success of our Liquids Pipelines business. Interruptions in our pipeline operations impact our throughput capacity and may result in reduced fixed payment revenues and spot volume opportunities. We manage this by investing in a highly skilled workforce, operating prudently, using risk-based preventive maintenance programs and making effective capital investments. We use internal inspection equipment to check our pipelines regularly and repair them whenever necessary.

While the majority of the power costs to operate the Keystone Pipeline System are passed through to our shippers, a portion of our volume is moved under an all-in fixed toll structure where we are exposed to changing power costs which may impact our earnings.

Regulatory and Government

Decisions by Canadian and U.S. regulators can have a significant impact on the approval, construction, operation and financial performance of our liquids pipelines. Public opinion about crude oil development and production may also have an adverse impact on the regulatory process. In conjunction with this, there are some individuals and interest groups that are expressing their opposition to crude oil production by lobbying against the construction of liquids pipelines. Lastly, changing environmental requirements or revisions to current regulatory process may impact the timing to obtain permit approvals for our liquids pipelines. We manage these risks by continuously monitoring regulatory and government developments and decisions to determine their possible impact on our liquids pipelines business and by working closely with our stakeholders in the development and operation of the assets.

Execution, capital costs and permitting

We make substantial capital commitments in large infrastructure projects based on the assumption that the new assets will offer an attractive return on investment in the future. Under some contracts, we share the cost of these risks with customers and while we carefully consider the expected cost of our capital projects, under some contracts we bear greater capital cost risk which may impact our return on these projects. Our capital projects are also subject to permitting risk which may result in construction delays, increased capital cost and, potentially, reduced investment returns.

Crude oil supply and demand for pipeline capacity

A decrease in demand for refined crude oil products could adversely impact the price that crude oil producers receive for their product. Lower crude oil prices could mean producers may curtail their investment in the further development of crude oil supplies. Depending on the severity, these factors would negatively impact opportunities to expand our liquids pipelines infrastructure and, in the longer term, to re-contract with shippers as current agreements expire.

Competition

As we continue to develop a competitive position in the North American liquids transportation market to transport growing crude oil and condensate supplies between key North American producing regions and refining and export markets, we face competition from other midstream companies which also seek to transport these crude oil and condensate supplies to the same markets. Our success is dependent on our ability to offer and contract transportation services on terms that are market competitive.

Liquids marketing

The liquids marketing business will generate revenue by capitalizing on asset utilization opportunities by entering into short-term or long-term pipeline or storage terminal capacity contracts.

Volatility in commodity prices and changing market conditions could impact the value of those capacity contracts. Availability of alternative pipeline systems that can deliver into the same areas can also impact contract value. The liquids marketing business complies with our risk management polices which are described in Other information - Risks and risk management.

48  TCPL Management's discussion and analysis 2015

Energy

Our Energy business includes a portfolio of power generation assets in Canada and the U.S., and unregulated natural gas storage assets in Alberta.

We own, control or are developing approximately 13,100 MW of generation capacity powered by natural gas, nuclear, coal, hydro, wind and solar. Our power business in Canada is mainly located in Alberta, Ontario and Québec. Our power business in the U.S. is located in New York, New England, Pennsylvania and Arizona. The assets are largely supported by long-term contracts and some represent low-cost baseload generation, while others are essential to providing capacity to the area in which they are located.

We conduct wholesale and retail electricity marketing and trading throughout North America from our offices in Alberta, Ontario and Massachusetts to actively manage our commodity exposure and provide higher returns.

We own and operate approximately 118 Bcf of unregulated natural gas storage capacity in Alberta and hold a contract with a third party for additional storage, in total accounting for approximately one-third of all storage capacity in the province. When combined with the regulated natural gas storage in Michigan (part of the Natural Gas Pipelines segment), we provide over 350 Bcf of natural gas storage and related services.

Strategy at a glance

Build upon our diverse portfolio of contracted and low cost power generation assets located in core North American markets, while maximizing the value of our existing investments through safe and reliable operations

•

 Leverage our experience building, operating and investing in a diverse set of generation technologies, fuel types and commercial structures to replace aging infrastructure and participate in the shift from higher carbon emitting electricity sources to natural gas-fired, renewables and non-emitting resources

•

 Pursue organic growth and repowering opportunities at our existing sites to capture more value from our current investments

•

 Maximize the value of our existing unregulated Alberta natural gas storage assets. Natural gas storage's role in balancing and providing flexibility to the natural gas system is expected to grow as the market expands and becomes more dynamic as a result of the electric grid’s increased reliance on natural gas-fired capacity and from the addition of LNG export terminals

Highlights from 2015

• Organic growth at Bruce Power: executed agreement with the IESO to extend the operating life of the Bruce Power facility to 2064 and acquired an additional ownership interest in this facility, a primary source of emission-less generation for Ontario underpinned by a long-term contract

• Acquisition of Ironwood power plant: strategically located natural gas-fired investment in proximity to the Marcellus shale gas play with energy and capacity revenues in the PJM power market, North America’s largest and most liquid energy region. Facility is well positioned in a market that is transitioning away from coal-fired to natural gas generation and complements our existing wholesale marketing business

• Amendment to Bécancour contract: executed agreement with Hydro Québec allowing for dispatch of up to 570 MW of firm peak winter capacity for a term of 20 years beginning December 2016. Annual payments are incremental to existing capacity payments

• Began construction of the Napanee 900 MW natural gas-fired power plant

TCPL Management's discussion and analysis 2015 49

50  TCPL Management's discussion and analysis 2015

We are the operator of all of our Energy assets, except for the Sheerness, Sundance A and Sundance B PPAs, Cartier Wind, Bruce and Portlands Energy.

	generating                       capacity (MW)		type of fuel	description	location	ownership
	Canadian Power 8,571 MW of power generation capacity (including facilities under construction)
	Western Power 2,609 MW of power supply in Alberta and the western U.S.
38	Bear Creek	80	natural gas	Cogeneration plant	Grande Prairie, Alberta	100	%
39	Carseland	80	natural gas	Cogeneration plant	Carseland, Alberta	100	%
40	Coolidge	575	natural gas	Simple-cycle peaking facility	Coolidge, Arizona	100	%
41	Mackay River	165	natural gas	Cogeneration plant	Fort McMurray, Alberta	100	%
42	Redwater	40	natural gas	Cogeneration plant	Redwater, Alberta	100	%
43	Sheerness PPA	756	coal	Output contracted under PPA	Hanna, Alberta	100	%
44	Sundance A PPA	560	coal	Output contracted under PPA	Wabamun, Alberta	100	%
44	Sundance B PPA (Owned by ASTC Power Partnership1)	3532	coal	Output contracted under PPA	Wabamun, Alberta	50	%
	Eastern Power 2,939 MW of power generation capacity (including facilities under construction)
45	Bécancour	550	natural gas	Cogeneration plant	Trois-Rivières, Québec	100	%
46	Cartier Wind	3652	wind	Five wind power projects	Gaspésie, Québec	62	%
47	Grandview	90	natural gas	Cogeneration plant	Saint John, New Brunswick	100	%
48	Halton Hills	683	natural gas	Combined-cycle plant	Halton Hills, Ontario	100	%
49	Portlands Energy	2752	natural gas	Combined-cycle plant	Toronto, Ontario	50	%
50	Ontario Solar	76	solar	Eight solar facilities	Southern Ontario and New Liskeard, Ontario	100	%
	Bruce Power 3,023 MW of power generation capacity
51	Bruce Power	3,0232	nuclear	Eight operating reactors	Tiverton, Ontario	48.5	%

TCPL Management's discussion and analysis 2015 51

	generating                  capacity (MW)		type of fuel	description	location	ownership
	U.S. Power 4,533 MW of power generation capacity
52	Kibby Wind	132	wind	Wind farm	Kibby and Skinner Townships, Maine	100	%
53	Ocean State Power	560	natural gas	Combined-cycle plant	Burrillville, Rhode Island	100	%
54	Ravenswood	2,480	natural gas and oil	Multiple-unit generating facility using dual fuel-capable steam turbine, combined-cycle and combustion turbine technology	Queens, New York	100	%
55	TC Hydro	583	hydro	13 hydroelectric facilities, including stations and associated dams and reservoirs	New Hampshire, Vermont and Massachusetts (on the Connecticut and Deerfield rivers)	100	%
56	Ironwood3	778	natural gas	Combined-cycle plant	Lebanon, Pennsylvania	100	%
	Unregulated natural gas storage 118 Bcf of non-regulated natural gas storage capacity
57	CrossAlta	68 Bcf		Underground facility connected to the NGTL System	Crossfield, Alberta	100	%
58	Edson	50 Bcf		Underground facility connected to the NGTL System	Edson, Alberta	100	%
	Under construction
59	Napanee	900	natural gas	Combined-cycle plant	Greater Napanee, Ontario	100	%

¹  We have a 50 per cent interest in ASTC Power Partnership, which has a PPA for production from the Sundance B power generating facilities.

²  Our share of power generation capacity.

³  Acquired February 1, 2016.

52  TCPL Management's discussion and analysis 2015

RESULTS

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure). Comparable depreciation and amortization is also a non-GAAP measure. See page 4 for more information on non-GAAP measures we use and page 100 for reconciliation to its GAAP equivalent.

year ended December 31
(millions of $)	2015		2014		2013
Comparable EBITDA	1,280		1,348		1,363
Comparable depreciation and amortization	(336	)	(309	)	(294	)
Comparable EBIT	944		1,039		1,069
Specific items (pre-tax):
Turbine equipment impairment charge	(59	)	—		—
Bruce Power merger – debt retirement charge	(36	)	—		—
Cancarb gain on sale	—		108		—
Niska contract termination	—		(43	)	—
Risk management activities	(37	)	(53	)	44
Segmented earnings	812		1,051		1,113

Energy segmented earnings were $239 millionlower in 2015 than in 2014 and $62 millionlower in 2014 than in 2013 and included the following specific items that have been excluded from comparable EBIT:

• a $59 million pre-tax charge relating to an impairment in value on turbine equipment previously purchased for a new power development project that did not proceed. Various other projects have recently been evaluated for possible use of this equipment and those evaluations support the impairment of the carrying value. See Critical accounting estimates on page 93 for further information

• a $36 million pre-tax charge related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

• a gain in 2014 of $108 million on the sale of Cancarb Limited and its related power generation business, which closed in April 2014

• a net loss in 2014 of $43 million resulting from the contract termination payment to Niska Gas Storage effective April 30, 2014

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

Risk management activities
(millions of $, pre-tax)	2015		2014		2013
Canadian Power	(8	)	(11	)	(4	)
U.S. Power	(30	)	(55	)	50
Natural Gas Storage	1		13		(2	)
Total (losses)/gains from risk management activities	(37	)	(53	)	44

The year-over-year 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 particular 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 impact of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them representative of our underlying operations.

The specific items noted above have been excluded in our calculation of comparable EBIT. The remainder of the Energy segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.

TCPL Management's discussion and analysis 2015 53

year ended December 31
(millions of $)	2015		2014		2013
Canadian Power
Western Power	72		252		355
Eastern Power1	394		350		322
Bruce Power	285		314		310
Canadian Power – comparable EBITDA2	751		916		987
Comparable depreciation and amortization	(190	)	(179	)	(172	)
Canadian Power – comparable EBIT2	561		737		815
U.S. Power (US$)
U.S. Power – comparable EBITDA	418		376		323
Comparable depreciation and amortization	(105	)	(107	)	(107	)
U.S. Power – comparable EBIT	313		269		216
Foreign exchange impact	87		27		7
U.S. Power – comparable EBIT (Cdn$)	400		296		223
Natural Gas Storage and other
Natural Gas Storage and other – comparable EBITDA	15		44		63
Comparable depreciation and amortization	(12	)	(12	)	(12	)
Natural Gas Storage and other – comparable EBIT	3		32		51
Business Development comparable EBITDA and EBIT	(20	)	(26	)	(20	)
Energy – comparable EBIT2	944		1,039		1,069
Summary
Energy – comparable EBITDA2	1,280		1,348		1,363
Comparable depreciation and amortization	(336	)	(309	)	(294	)
Energy – comparable EBIT2	944		1,039		1,069

¹  Includes four solar facilities acquired between June and December 2013, three solar facilities acquired in September 2014 and one solar facility acquired in December 2014.

²  Includes our share of equity income from our investments in ASTC Power Partnership and Portlands Energy, and our share of comparable income from equity investments from Bruce Power.

Comparable EBITDA for Energy was $68 millionlower in 2015 than in 2014. The decrease was the net effect of:

• lower earnings from Western Power as a result of lower realized prices and lower PPA volumes

• higher earnings from U.S. Power due to increased margins and sales volumes to wholesale, commercial and industrial customers, partially offset by lower capacity revenue in New York and lower realized prices at our northeastern U.S. Power facilities

• higher earnings from Eastern Power primarily due to four solar facilities acquired in 2014

• lower earnings from Bruce Power due to higher operating expenses mostly offset by fewer unplanned outage days at Bruce A, as well as higher operating expenses and lower gains from contracting activities, partially offset by lower lease expense at Bruce B

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

• a stronger U.S. dollar and its positive effect on the foreign exchange impact.

Comparable EBITDA for Energy was $15 millionlower in 2014 compared to 2013. This decrease was the net effect of:

• lower earnings from Western Power due to lower realized prices

• higher earnings from U.S. Power mainly because of higher realized capacity prices in New York and higher realized power prices at our New York and New England facilities

• incremental earnings from Eastern Power primarily due to four solar facilities acquired in each of 2013 and 2014

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

54  TCPL Management's discussion and analysis 2015

OUTLOOK

Earnings

We expect 2016 earnings from the Energy segment to be similar to 2015, assuming the net effect of the following expectations:

• acquisition of the Ironwood power plant in Pennsylvania

• increased ownership interest in Bruce Power

• increased planned maintenance activity at Bruce Power

• lower U.S. Power marketing contribution

• lower realized capacity prices in New York

• lower contributions from our power operations in Eastern Canada

• lower North American energy commodity prices

• higher GHG emissions costs in Alberta.

Although a significant portion of Energy's output is sold under long-term contracts, revenue from power that is sold under shorter-term forward arrangements or at spot prices will continue to be impacted by fluctuations in commodity prices and changes in seasonal natural gas storage price spreads will impact Natural Gas Storage earnings.

Weather, unplanned outages and unforeseen regulatory changes can play a role in spot markets and can drive fluctuations in our Energy results.

Western Power

Western Power earnings in 2016 are expected to be consistent with 2015. A well-supplied Alberta power market with slower demand growth and low natural gas prices is anticipated in 2016. Low average spot power prices are expected to continue in the near term, with average spot power prices in 2016 remaining similar to 2015 prices. Average spot market power prices in 2015 ($33/MWh) were materially lower than in 2014 ($50/MWh) primarily due to increased supply and low natural gas prices.

In 2015, the Alberta government renewed and initiated certain GHG policies that impact the electricity sector. GHG compliance costs associated with our PPAs are expected to increase in 2016. The Alberta government’s renewal and change to the SGER increases the emissions reduction target to 15% and increases the carbon levy to $20 per tonne in 2016, up from 12% and $15 per tonne in 2015. See the Significant events section for more information.

A new climate change policy was announced by the Alberta government in the fall of 2015 that positions the provincial economy to be less carbon intensive. According to this plan, Alberta will have an economy-wide carbon tax beginning in 2017, retire coal facilities by 2030 and add significant renewable electricity sources. The future Alberta electricity sector supply mix will feature significant levels of renewables and gas-fired capacity. We have expertise in building, operating and investing in a diverse set of generation technologies and are well positioned to participate in the Alberta electric supply transformation.

Eastern Power

All of our energy assets in eastern Canada are fully contracted. The Ontario assets are contracted with the IESO and are largely sheltered from spot market pricing. Eastern Power earnings in 2016 are expected to be slightly lower as a result of lower contractual earnings at Bécancour and reduced earnings from the sale of unused natural gas transportation. Beginning in December 2016, the Eastern Power earnings will be positively impacted from an agreement executed with Hydro Québec (HQ) to amend Bécancour’s electricity supply contract allowing HQ to dispatch up to 570 MW of firm peak winter capacity from the Bécancour facility.

Bruce Power

We expect 2016 equity income from Bruce Power to be consistent with 2015 results. The positive impact from the additional ownership interest acquired in Bruce Power effective December 3, 2015 is expected to be offset by increased planned maintenance activity in 2016.

During second quarter 2016, Bruce units 1 to 4 are expected to be removed from service for approximately one month to facilitate a station containment outage. This work program inspects and maintains key safety systems including containment structures, and is required to be completed approximately once every decade. Additional planned maintenance is scheduled for first and fourth quarters of 2016. The overall average plant availability percentages in 2016 are expected to be in the low 80s.

TCPL Management's discussion and analysis 2015 55

Bruce Power’s new agreement with the IESO to extend the operating life of the Bruce Power facility to 2064 along with our acquisition of an additional ownership interest in the facility is expected to provide long-term growth in earnings. See Significant events for more information.

U.S. Power

U.S. Power results are expected to be higher in 2016 compared to 2015 due to our acquisition of the Ironwood power plant in Lebanon, Pennsylvania on February 1, 2016, partially offset by lower marketing margins and lower commodity prices.

U.S. northeast power markets are currently well supplied and we expect prices to remain at lower levels in 2016 along with more normalized levels of volatility.

In recent years, gas pipeline constraints in New England resulted in significant winter price volatility contributing to increased seasonal margins earned by our power marketing business in 2015. The market's response to this increased volatility and the implementation of winter reliability programs has mitigated the impact of constrained gas supply reducing power price volatility. This reduced price volatility also contributes to lower expected earnings in 2016.

Our northeastern U.S. power facilities, particularly Ravenswood in New York, also earn significant revenues through participation in regional capacity markets. New York Spot capacity prices are on average expected to be lower in 2016 than 2015 primarily due to a reduction to the locational requirement used in the capacity pricing structure.

Natural Gas Storage

A modest recovery of seasonal spreads is expected to occur in 2016. Additionally, the resolution of Alberta natural gas pipeline outages that occurred in 2015 is expected to have a positive impact on revenue in 2016. As a result, the 2016 segment contribution is expected to be slightly higher compared to 2015 results.

Capital spending

We spent a total of $0.4 billion in 2015 and expect to spend approximately $0.6 billion on capital projects in Energy in 2016.

Equity investments and acquisitions

In 2015, we acquired an additional 14.89 per cent ownership interest in Bruce B for $236 million and invested $0.2 billion in Bruce Power for capital projects. We expect to invest approximately $0.3 billion in Bruce Power in 2016.

Our acquisition of the Ironwood power plant in Lebanon, Pennsylvania closed on February 1, 2016 for US$657 million before post closing adjustments.

56  TCPL Management's discussion and analysis 2015

UNDERSTANDING THE ENERGY BUSINESS

Our Energy business is made up of three groups:

• Canadian Power

• U.S. Power

• Natural Gas Storage

Energy comparable EBIT – contribution by group, excluding business development expenses

year ended December 31, 2015

Power generation capacity – contribution by group

year ended December 31, 2015 (includes facilities in development/acquired)

Canadian Power

Western Power

We own or have the rights to approximately 2,600 MW of power supply in Alberta and Arizona through three long-term PPAs, four natural gas-fired cogeneration facilities, and through Coolidge, a simple-cycle, natural gas peaking facility in Arizona.

Power purchased under long-term contracts is as follows:

	Type of contract	With	Expires
Sheerness PPA	Power purchased under a 20-year PPA	ATCO Power and TransAlta Utilities Corporation	2020
Sundance A PPA	Power purchased under a 20-year PPA	TransAlta Utilities Corporation	2017
Sundance B PPA	Power purchased under a 20-year PPA (own 50 per cent through the ASTC Power Partnership)	TransAlta Utilities Corporation	2020

Power sold under long-term contracts is as follows:

	Type of contract	With	Expires
Coolidge	Power sold under a 20-year PPA	Salt River Project Agricultural Improvements & Power District	2031

Earnings in our Western Power business are maximized by maintaining and optimizing the operations of our power plants, and through various marketing activities.

TCPL Management's discussion and analysis 2015 57

A disciplined operational strategy is critical to maximizing output and revenue at our cogeneration facilities and maximizing Coolidge earnings, where revenue is based on plant availability, and is not a function of market price.

The marketing function is critical for optimizing returns and managing risk through direct sales to medium and large industrial and commercial companies and other market participants. Our marketing group sells power sourced through the PPAs, markets uncommitted volumes from the cogeneration plants, and buys and sells power and natural gas to maximize earnings from our assets. To reduce exposure associated with uncontracted volumes, we sell a portion of our power in forward sales markets when acceptable contract terms are available.

A portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements. This ensures we have adequate power supply to fulfill our sales obligations if we have unexpected plant outages and provides the opportunity to increase earnings in periods of high spot prices.

The amount sold forward will vary depending on market conditions and market liquidity and has historically ranged between 25 to 75 per cent of expected future production with a higher proportion being hedged in the near term periods. Such forward sales may be completed with medium to large industrial and commercial companies as well as other market participants and will affect our average realized price (versus spot price) in future periods.

Eastern Power

We own or are developing approximately 3,000 MW of power generation capacity in eastern Canada. All of the power produced by these assets is sold under long-term contracts.

Disciplined maintenance of plant operations is critical to the results of our Eastern Power assets, where earnings are based on plant availability and performance.

Assets currently operating under long-term contracts are as follows:

	Type of contract	With	Expires
Bécancour1,2	20-year PPA and tolling agreement Steam sold to an industrial customer	Hydro-Québec	2036
Cartier Wind	20-year PPA	Hydro-Québec	2026–2032
Grandview	20-year tolling agreement to buy 100 per cent of heat and electricity output	Irving Oil	2024
Halton Hills	20-year Clean Energy Supply contract	IESO	2030
Portlands Energy	20-year Clean Energy Supply contract	IESO	2029
Ontario Solar3	20-year Feed-in Tariff (FIT) contracts	IESO	2032–2034

¹  Power generation has been suspended since 2008. We continue to receive capacity payments while generation is suspended.

²  In August 2015, we executed an agreement with HQ to amend Bécancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Bécancour facility for a term of 20 years commencing in December 2016. Annual tolling payments received for this new service will be incremental to existing capacity payments earned under the agreement and will expire in 2036. The existing capacity payments terminate in 2026.

³  We acquired four facilities in 2013 and an additional four facilities in 2014.

Assets currently under construction are as follows:

	Type of contract	With	Expires
Napanee1	20-year Clean Energy Supply contract	IESO	20 years from in-service date

¹  Expected in-service date is between late 2017 and early 2018

58  TCPL Management's discussion and analysis 2015

Western and Eastern Power results

Comparable EBITDA and comparable EBIT are non-GAAP measures. See page 4 for more information.

year ended December 31
(millions of $)	2015		2014		2013
Revenue1
Western Power	534		736		605
Eastern Power2	455		428		400
Other3	62		85		108
	1,051		1,249		1,113
Income from equity investments4	8		45		141
Commodity purchases resold	(353	)	(404	)	(283	)
Plant operating costs and other	(248	)	(299	)	(298	)
Exclude risk management activities1	8		11		4
Comparable EBITDA	466		602		677
Comparable depreciation and amortization	(190	)	(179	)	(172	)
Comparable EBIT	276		423		505
Breakdown of comparable EBITDA
Western Power	72		252		355
Eastern Power	394		350		322
Comparable EBITDA	466		602		677

¹  The realized and unrealized gains and losses from financial derivatives used to manage Canadian Power’s assets are presented on a net basis in Western and Eastern Power revenues. The unrealized gains and losses from financial derivatives included in Revenue are excluded to arrive at Comparable EBITDA.

²  Includes four solar facilities acquired between June and December 2013, three solar facilities acquired in September 2014 and one solar facility acquired in December 2014.

³  Includes Revenue from the sale of unused natural gas transportation, sale of excess natural gas purchased for generation and Cancarb sales of thermal carbon black up to April 15, 2014 when it was sold.

⁴  Includes our share of equity income from our investments in ASTC Power Partnership, which holds the Sundance B PPA, and Portlands Energy. Equity income does not include any earnings related to our risk management activities.

TCPL Management's discussion and analysis 2015 59

Sales volumes and plant availability

Includes our share of volumes from our equity investments.

year ended December 31	2015		2014		2013
Sales volumes (GWh)
Supply
Generation
Western Power	2,519		2,517		2,728
Eastern Power1	3,911		3,080		3,822
Purchased
Sundance A & B and Sheerness PPAs and other2	10,617		11,472		8,223
Other purchases	154		16		13
	17,201		17,085		14,786
Sales
Contracted
Western Power	7,707		10,484		7,864
Eastern Power1	3,911		3,080		3,822
Spot
Western Power	5,583		3,521		3,100
	17,201		17,085		14,786
Plant availability3
Western Power4	97	%	96	%	95	%
Eastern Power1,5	97	%	91	%	90	%

¹  Includes four solar facilities acquired between June and December 2013, three solar facilities acquired in September 2014, and one solar facility acquired in December 2014.

²  Includes our 50 per cent ownership interest of Sundance B volumes through the ASTC Power Partnership. Sundance A Unit 1 returned to service in September 2013 and Unit 2 returned to service in October 2013 after extended outages.

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

⁴  Does not include facilities that provide power to us under PPAs.

⁵  Does not include Bécancour because power generation has been suspended since 2008.

Western Power

Western Power's comparable EBITDA in 2015 was $180 millionlower than in 2014. The decrease was due to lower realized power prices and lower PPA volumes.

Average spot market power prices in Alberta decreased by 34 per cent from approximately $50/MWh in 2014 to approximately $33/MWh in 2015. The addition of new natural gas-fired and wind plants over the last year-and-a-half have contributed to a well supplied market and very few higher priced hours were observed. While we manage spot market power price volatility through the use of forward contracts, this significant decrease in spot market prices also reduced our realized power prices in 2015 compared to 2014.

The decrease in equity earnings of $37 million in 2015 compared to 2014 was primarily due to the impact of lower Alberta spot market prices on earnings from the ASTC Power Partnership which holds our 50 per cent ownership interest in the Sundance B PPA. Equity earnings does not include the impact of related contracting activities.

In 2014, Western Power’s comparable EBITDA was $103 millionlower than 2013, due to the net effect of:

• lower realized power prices

• incremental earnings from the return to service of the Sundance A PPA Unit 1 in September 2013 and Unit 2 in October 2013 which also resulted in increased volume purchases

• sale of Cancarb in April 2014.

60  TCPL Management's discussion and analysis 2015

Average spot market power prices in Alberta decreased by 38 per cent from approximately $80/MWh in 2013 to approximately $50/MWh in 2014.

Realized power prices on power sales can be higher or lower than spot market power prices in any given period as a result of contracting activities. Approximately 58 per cent of Western Power sales volumes were sold under contract in 2015 compared to 75 per cent in 2014 and 72 per cent in 2013.

Eastern Power

Eastern Power’s comparable EBITDA in 2015 was $44 millionhigher than 2014 due to the net effect of incremental earnings from solar facilities acquired in 2014, higher contractual earnings at Bécancour and lower earnings on the sale of unused natural gas transportation.

In 2014, Eastern Power's comparable EBITDA was $28 millionhigher than 2013 due to the net effect of incremental earnings from the four solar facilities acquired in 2013, the additional four facilities acquired in late 2014 and higher contractual earnings at Bécancour.

Bruce Power

Bruce Power is a nuclear power generation facility located near Tiverton, Ontario and is comprised of eight nuclear units with a combined capacity of approximately 6,300 MW. Bruce Power leases the eight nuclear facilities from Ontario Power Generation (OPG).

Results from Bruce Power fluctuate primarily due to the frequency, scope and duration of planned and unplanned outages.

On December 3, 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the Bruce Power facility to 2064. This new agreement represents an extension and material amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site.

The amended agreement, which took economic effect on January 1, 2016, allows Bruce Power to immediately invest in life extension activities for Units 3 through 8 to support the long-term refurbishment program. This early investment in the Asset Management program will result in near-term life extension, allowing later investment in the Major Component Replacement work that is expected to begin in 2020.

As part of the life extension and refurbishment agreement, Bruce Power began receiving a uniform price of $65.73 per MWh for all units in January 2016. Over time, the price will be subject to adjustments for the return of and on capital invested under the Asset Management and Major Component Replacement capital programs, along with various other pricing adjustments that allow for a better matching of revenues and costs over the long term.

Our estimated share of investment related to the Asset Management program to be completed over the life of the agreement is approximately $2.5 billion (2014 dollars). Our estimated share of investment in the Major Component Replacement work for Units 3 through 8 over the 2020 to 2033 timeframe is approximately a further $4 billion (2014 dollars).

Under certain conditions, Bruce Power and the IESO can elect to not proceed with the remaining Major Component Replacement investments should the cost exceed certain thresholds or prove to not provide sufficient economic benefits. The agreement has been structured to account for changing cost inputs over time, including ongoing operating costs and larger capital investments.

On December 3, 2015, we exercised our option to acquire an additional 14.89 per cent ownership interest in Bruce B for $236 million from the Ontario Municipal Employees Retirement System (OMERS). On December 4, 2015, Bruce B and Bruce A were merged to form a single partnership structure through Bruce Power LP with us now owning a 48.5 per cent ownership interest. Prior to the acquisition of additional Bruce B ownership and the merger, we owned 48.9 per cent of Bruce A and 31.6 per cent of Bruce B.

TCPL Management's discussion and analysis 2015 61

Prior to the amended agreement with the IESO, all of the output from Bruce A Units 1 to 4 was sold at a fixed price/MWh which was adjusted annually on April 1 for inflation and other provisions under the contract. Bruce A also recovered fuel costs from the IESO.

Bruce A fixed price	Per MWh
April 1, 2015 – December 31, 2015		$73.42
April 1, 2014 – March 31, 2015		$71.70
April 1, 2013 – March 31, 2014		$70.99

Prior to the amended agreement with the IESO, all output from Bruce B Units 5 to 8 was subject to a floor price adjusted annually for inflation on April 1.

Bruce B floor price	Per MWh
April 1, 2015 – December 31, 2015		$54.13
April 1, 2014 – March 31, 2015		$52.86
April 1, 2013 – March 31, 2014		$52.34

Amounts received under the Bruce B Units 5 to 8 floor price mechanism within a calendar year were subject to repayment if the average spot price in a month exceeded the floor price. The average spot power price in each month of 2015 was less than the floor price and therefore no amounts received under the floor price mechanism in 2015 are subject to repayment. Amounts received above the floor price in first quarter 2014 were repaid to the IESO in January 2015.

Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.

The contract also provides for payment if the IESO reduces Bruce Power’s generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered “deemed generation”, for which Bruce Power is paid the contract price.

62  TCPL Management's discussion and analysis 2015

Bruce Power results

Results reflect our proportionate share. Beginning in 2016, results from Bruce Power will be reported on a combined basis to reflect the merged entity. Comparable income from equity investments is a non-GAAP measure. See page 4 for more information on non-GAAP measures we use.

year ended December 31
(millions of $, unless noted otherwise)	2015			2014			2013
Comparable income from equity investments1
Bruce A	205			209			202
Bruce B	80			105			108
	285			314			310
Comprised of:
Revenues	1,301			1,256			1,258
Operating expenses	(691		)	(623		)	(618		)
Depreciation and other	(325		)	(319		)	(330		)
Comparable income from equity investments1	285			314			310
Bruce Power merger – debt retirement charge	(36		)	—			—
Income from equity investments1	249			314			310
Bruce Power – other information
Plant availability2
Bruce A	87		%	82		%	82		%
Bruce B	87		%	90		%	89		%
Combined Bruce Power	87		%	86		%	86		%
Planned outage days
Bruce A	164			118			123
Bruce B	163			127			140
Unplanned outage days
Bruce A	28			123			63
Bruce B	17			4			20
Sales volumes (GWh)1
Bruce A	11,148			10,526			10,458
Bruce B	8,210			8,197			8,010
	19,358			18,723			18,468
Realized sales price per MWh3
Bruce A		$71			$72			$70
Bruce B		$55			$56			$54
Combined Bruce Power		$63			$63			$62

¹  Represents our 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B up to December 3, 2015 when we increased our ownership percentage in Bruce B, and Bruce A and B were merged. Sales volumes include deemed generation.

²  The percentage of time in a year the plant is available to generate power, regardless of whether it is running.

³  Calculation based on actual and deemed generation. Bruce B realized sales price per MWh includes revenues under the floor price mechanism and revenues from contract settlements.

Comparable income from equity investments from Bruce A in 2015 was $4 million lower than 2014. The decrease was mainly due to higher operating expenses, partially offset by higher volumes resulting from fewer unplanned outage days.

TCPL Management's discussion and analysis 2015 63

Comparable income from equity investments from Bruce B in 2015 was $25 million lower than 2014. The decrease was mainly due to higher operating expenses and lower gains from contracting activities, partially offset by lower lease expense based on the terms of the lease agreement with OPG. All Bruce B units were removed from service in April 2015 to allow for inspection of the Bruce B vacuum building as mandated by the Canadian Nuclear Safety Commission to occur approximately once every decade. The outage, along with additional planned maintenance on Unit 6, was completed successfully during second quarter 2015.

Comparable income from equity investments from Bruce A in 2014 was $7 millionhigher than 2013. The increase was mainly due to lower depreciation and operating expenses and higher volumes, partially offset by recognition of an insurance recovery of approximately $40 million in the first quarter 2013. The negative impact of increased outage days in 2014 was offset by higher generation levels while operating.

Comparable income from equity investments from Bruce B in 2014 was $3 millionlower than 2013. The decrease was mainly due to higher lease expense recognized based on the terms of the lease agreement with OPG, partially offset by higher volumes and lower operating costs resulting from lower outage days.

U.S. Power

We own approximately 4,500 MW of power generation capacity in New York, New England and Pennsylvania, including plants powered by natural gas, oil, hydro and wind. We have recently acquired the 778 MW Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, which delivers energy into the PJM power market.

We earn revenues in New York, PJM and New England by providing generation capacity and by selling energy. Capacity markets compensate power suppliers for being available to provide power, and are intended to promote investment in new and existing power resources needed to meet customer demand and maintain a reliable power system. The energy markets compensate power providers for the actual energy they supply.

Providing capacity

Capacity revenue in New York, PJM and New England are a function of two factors, capacity prices and plant availability. It is important for us to keep our plant availability high to maximize the amount of capacity for which we get paid.

The price required for capacity in all of the three U.S. Northeast capacity markets where we have assets is determined by annual competitive auctions. Auction results are impacted by actual power supply and projected power demand levels within demand curve price setting processes. Each U.S. Northeast capacity market is similar in design, however, each has unique features. For example, the price paid for capacity in both the PJM and New England Power Pools is determined by annual competitive auctions that are held three years in advance of the applicable capacity year, while the New York capacity market does not have a three year advance attribute.

Selling energy

We focus on selling power under short- and long-term contracts to wholesale, commercial and industrial customers in the following power markets:

• New York, operated by the New York ISO

• New England, operated by the New England ISO

• PJM Interconnection area (PJM).

We also earn additional revenues by bundling power sales with other energy services.

We meet our power sales commitments using power we generate ourselves or acquire at fixed prices, thereby reducing our exposure to changes in commodity prices.

The timing of recognizing earnings from our U.S. power marketing business is impacted by different pricing profiles between the prices we charge our customers and the prices we pay for volumes purchased to fulfill our sales obligations over the term of the contracts. The costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers includes the impact of certain contracts to purchase power over multiple periods at a flat price. Because the price we charge our customers is typically shaped to the market, the impact of these two contract pricing profiles has generally resulted in higher earnings in December to February, offset by lower earnings between March and November, with overall positive margins over the term of the contracts.

64  TCPL Management's discussion and analysis 2015

U.S. Power results

Comparable EBITDA and comparable EBIT are non-GAAP measures. See page 4 for more information.

year ended December 31
(millions of US$)	2015		2014		2013
Revenue
Power1	1,975		1,794		1,587
Capacity	317		362		295
	2,292		2,156		1,882
Commodity purchases resold	(1,474	)	(1,297	)	(1,003	)
Plant operating costs and other2	(422	)	(529	)	(509	)
Exclude risk management activities1	22		46		(47	)
Comparable EBITDA	418		376		323
Comparable depreciation and amortization	(105	)	(107	)	(107	)
Comparable EBIT	313		269		216

¹  The realized and unrealized gains and losses from financial derivatives used to manage U.S. Power's assets are presented on a net basis in power revenues. The unrealized gains and losses from financial derivatives included in Revenue are excluded to arrive at Comparable EBITDA.

²  Includes the costs of fuel consumed in generation.

Sales volumes and plant availability

year ended December 31	2015		2014		2013
Physical sales volumes (GWh)
Supply
Generation	7,849		7,742		6,173
Purchased	20,937		13,798		12,050
	28,786		21,540		18,223
Plant availability1, 2	78	%	82	%	84	%

¹  The percentage of time the plant was available to generate power, regardless of whether it is running.

²  Plant availability was lower in 2015 due to an unplanned outage at the Ravenswood facility. The unit returned to service in May 2015.

U.S. Power - other information

year ended December 31	2015	2014	2013
Average Spot Power Prices (US$ per MWh)
New England¹	42	65	57
New York²	39	61	53
Average New York2 Zone J Spot Capacity Prices (US$ per KW-M)	11.44	13.96	11.31

¹  New England ISO all hours Mass Hub price.

²  Zone J market in New York City where the Ravenswood plant operates.

U.S. Power's comparable EBITDA in 2015 was US$42 millionhigher than 2014. This reflected the net effect of:

• higher margins and higher sales to wholesale, commercial and industrial customers in both the PJM and New England markets

• lower realized power prices at our facilities in New York and New England, partially offset by lower fuel costs

• lower capacity revenue at Ravenswood due to lower realized capacity prices in New York and the impact of lower availability at the facility.

In 2014, U.S. Power’s comparable EBITDA was US$53 millionhigher than 2013. This reflected the net effect of:

• higher realized capacity prices primarily in New York

• higher realized power prices for the New England and New York facilities

TCPL Management's discussion and analysis 2015 65

• higher generation volumes primarily at the Ravenswood facility

• higher prices and related costs on increased volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers.

Higher margins and higher sales volumes to wholesale, commercial and industrial customers in both PJM and New England markets resulted in significantly higher earnings during 2015 compared to 2014. The expansion of our customer base in these markets combined with lower and less volatile prices on volumes purchased to fulfill our sale obligations in 2015, provided the opportunity for higher earnings.

Wholesale electricity prices in New York and New England were lower in 2015 compared to 2014. Reductions in fuel oil prices and increased availability of liquefied natural gas in winter 2015 helped to mitigate the impact of pipeline constraints and keep peak price excursions limited compared to winter 2014. Average spot power prices in 2015 in New England decreased approximately 35 per cent and in New York spot power prices decreased approximately 36 per cent compared to 2014.

Average New York Zone J spot capacity prices were approximately 18 per cent lower in 2015 than in 2014. The decrease in spot prices and the impact of hedging activities, resulted in lower realized capacity prices in New York in 2015. The lower spot capacity prices were primarily due to increased available operational supply in New York City's Zone J market.

Capacity revenues were also negatively impacted by a unit outage from September 2014 to May 2015 at Ravenswood. The calculation used by the NYISO to determine the capacity volume which a generator is compensated utilizes a rolling average forced outage rate. As a result of this methodology, outages impact capacity volumes and associated revenues on a lagged basis. Accordingly, capacity revenues during 2015 were negatively impacted compared to the same period in 2014. The outage continues to be included in the rolling average forced outage rate.

Physical sales volumes and purchased volumes sold to wholesale, commercial and industrial customers were higher in 2015 compared to 2014 as we have expanded our customer base in both PJM and New England markets.

As at December 31, 2015, approximately 6,600 GWh or 70 per cent of U.S. Power's planned generation is contracted for 2016, and 3,000 GWh or 33 per cent for 2017. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.

Natural Gas Storage

We own and operate 118 Bcf of non-regulated natural gas storage capacity in Alberta. This business operates independently from our regulated natural gas transmission business and from ANR's regulated storage business, which are included in our Natural Gas Pipelines segment.

Storage capacity

year ended December 31, 2015	Working gas storage capacity (Bcf)	Maximum injection/ withdrawal capacity (MMcf/d)
Edson	50	725
CrossAlta	68	550
	118	1,275

We also hold a contract for additional Alberta-based storage capacity with a third party.

Our natural gas storage business helps balance seasonal and short-term supply and demand, and adds flexibility to the delivery of natural gas to markets in Alberta and the rest of North America. Market volatility creates arbitrage opportunities and our natural gas storage facilities also give customers the ability to capture value from short-term price movements. The natural gas storage business is affected by the change in seasonal natural gas price spreads which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons.

Our gas storage business contracts with third parties, typically participants in the Alberta and interconnected gas markets, for a fixed fee to provide gas storage services on a short, medium, and/or long term basis.

We also enter into proprietary natural gas storage transactions, which include a forward purchase of our own natural gas to be injected into storage and a simultaneous forward sale of natural gas for withdrawal at a later period, typically during the winter

66  TCPL Management's discussion and analysis 2015

withdrawal season. By matching purchase and sales volumes on a back-to-back basis, we lock in future positive margins, effectively eliminating our exposure to changes in gas prices.

Natural Gas Storage and other results

Comparable EBITDA in 2015 was $29 millionlower than 2014, mainly due to decreased proprietary and third party storage revenue as a result of lower realized natural gas storage price spreads as well as extreme natural gas price volatility experienced in first quarter 2014.

In 2014, comparable EBITDA was $19 millionlower than 2013, mainly due to decreased third party storage revenue as a result of lower realized natural gas storage price spreads.

SIGNIFICANT EVENTS

Canadian Power

Alberta Greenhouse Gas Emissions

In 2015, the Alberta government announced a renewal and change to the SGER in Alberta. Since 2007, under the SGER, established industrial facilities with GHG emissions above a certain threshold are required to reduce their emissions by 12 per cent below an average intensity baseline and a carbon levy of $15 per tonne is placed on emissions above this target.

The changed regulations include an increase in the emissions reductions target to 15 per cent in 2016 and 20 per cent in 2017, along with an increase in the carbon levy to $20 per tonne in 2016 and $30 per tonne in 2017. Starting in 2018, coal-fired generators will pay $30 per tonne of CO2 on emissions above what Alberta’s cleanest natural gas-fired plant would emit to produce an equivalent amount of electricity. While our Sundance and Sheerness PPAs are subject to this regulation, our inventory of carbon offset credits will mitigate some of these increased costs. The remaining compliance costs are expected to be somewhat recovered through increased market pricing but the full extent is not known at this time.

Napanee

In January 2015, we began construction activities on a 900 MW natural gas-fired power plant at Ontario Power Generation’s Lennox site in eastern Ontario in the town of Greater Napanee. We expect to invest approximately $1.0 billion in the Napanee facility during construction and commercial operations are expected to begin in late-2017 or early-2018. Production from the facility is fully contracted with the IESO.

Bécancour

In August 2015, we executed an agreement with HQ to amend Bécancour's electricity supply contract. The amendment allows HQ to dispatch up to 570 MW of firm peak winter capacity from the Bécancour facility for a term of 20 years commencing in December 2016. Annual payments received for this new service will be incremental to existing capacity payments earned under the agreement. In October 2015, the Régie de l’énergie approved the amended contract.

Bruce Power

In December 2015, Bruce Power entered into an agreement with the IESO to extend the operating life of the facility to the end of 2064. This new agreement represents an extension and material amendment to the earlier agreement that led to the refurbishment of Units 1 and 2 at the site.

The amended agreement is effective January 1, 2016 and allows Bruce Power to immediately invest in life extension activities for Units 3 through 8. Our share of investment in the Asset Management program to be completed over the life of the agreement is approximately $2.5 billion (2014 dollars). Our share of investment in the Major Component Replacement work that is expected to begin in 2020 is approximately $4 billion (2014 dollars). Under certain conditions, Bruce Power and the IESO can elect to not proceed with the remaining Major Component Replacement investments should the cost exceed certain thresholds or prove to not provide sufficient economic benefits. The agreement has been structured to account for changing cost inputs over time, including ongoing operating costs and additional capital investments. Beginning in 2016, Bruce Power receives a uniform price of $65.73 per MWh for all units. This price will be adjusted over the term of the agreement to incorporate incremental capital investment and cost changes.

In connection with this opportunity, we exercised our option to acquire an additional 14.89 per cent ownership interest in Bruce B for $236 million from OMERS. Subsequent to this acquisition, Bruce A and Bruce B were merged to form a single partnership

TCPL Management's discussion and analysis 2015 67

structure. In 2015, we recognized a $36 million charge, representing our proportionate share, on the retirement of Bruce Power debt in conjunction with this merger. Each partner now holds a 48.5 per cent interest in this newly merged partnership structure.

U.S. Power

Ravenswood

In late May 2015, the 972 MW Unit 30 at the Ravenswood Generating Station returned to service after a September 2014 unplanned outage which resulted from a problem with the generator associated with the high pressure turbine. Insurance recoveries for this event are expected to be received in 2016. As a result of the expected insurance recoveries, net of deductibles, the Unit 30 unplanned outage is not expected to have a significant impact on our earnings although the recording of earnings will not coincide with lost revenues due to timing of the insurance proceeds.

Ironwood

On February 1, 2016, we acquired the 778 MW Ironwood natural gas fired, combined cycle power plant located in Lebanon, Pennsylvania from Talen Energy Corporation for US$657 million before post closing adjustments. The Ironwood power plant delivers energy into the PJM power market and will provide us with a solid platform from which to continue to grow our wholesale, commercial and industrial customer base in this market area.

BUSINESS RISKS

The following are risks specific to our Energy business. See page 86 for information about general risks that affect the company as a whole, including other operational risks, health, safety and environment (HSE) risks, and financial risks.

Fluctuating power and natural gas market prices

Power and natural gas prices are affected by fluctuations in supply and demand, weather, and by general economic conditions. The power generation facilities in our Western Power operations in Alberta, and in our U.S. Northeast Power operations are exposed to commodity price volatility.

Earnings from these businesses are generally correlated to the prevailing power supply and demand conditions. In the U.S. Northeast, the price of natural gas also has a significant impact on power prices, as energy prices in these markets are usually set by gas-fired power supplies. Extended periods of low gas prices will generally exert downward pressure on power prices and therefore on earnings from our U.S. Northeast facilities.

Our portfolio of assets in eastern Canada and our Coolidge Generating Station in Arizona are fully contracted, and are therefore not materially impacted by fluctuating commodity prices. As these contracts expire in the long term, it is uncertain if we will be able to re-contract on similar terms.

To mitigate the impact of power price volatility in Alberta and the U.S. Northeast, we sell a portion of our supply under medium to long-term sales contracts where contract terms are acceptable. A portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements to ensure we have adequate power supply to fulfill sales obligations if unexpected plant outages occur. This unsold supply is exposed to fluctuating power and natural gas market prices. As power sales contracts expire, new forward contracts are entered into at prevailing market prices.

Our natural gas storage business is subject to fluctuating seasonal natural gas price spreads which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons.

Alberta Power Purchase Arrangements

As the Alberta power market conforms to the new climate change policies announced in 2015, the full extent of the impact to the economics of the PPAs is not known at this time. However, change of law provisions exist in the arrangements that afford PPA buyers an option to turn back PPAs to the Alberta Balancing Pool in the event that holding a PPA is deemed to be no longer economic.

U.S. Power capacity payments

A significant portion of revenues earned by our U.S. Northeast operations come from capacity payments where prices are determined in various competitive auctions. Fluctuations in capacity prices can have a material impact on these businesses. Auction pricing results are impacted by the prevailing supply and demand conditions for capacity and other factors. All three U.S.

68  TCPL Management's discussion and analysis 2015

Northeast capacity markets where we have assets feature demand curve price setting processes driven by a number of established parameters and other rules that are subject to periodic review and revisions by the respective ISOs and FERC.

Plant availability

Optimizing and maintaining plant availability is essential to the continued success of our Energy business. Unexpected outages or extended planned outages at our power plants can increase maintenance costs, lower plant output and sales revenue, and lower capacity payments and margins. We may also have to buy power or natural gas on the spot market to meet our delivery obligations.

We manage this risk by investing in a highly skilled workforce, operating prudently, running comprehensive, risk-based preventive maintenance programs and making effective capital investments.

For facilities we do not operate, our purchase agreements include a financial remedy if a plant owner does not deliver as agreed. The Sundance and Sheerness PPAs, for example, require the producers to pay us market-based penalties if they cannot supply the amount of power we have agreed to purchase.

Execution and capital costs

We make substantial capital commitments developing power generation infrastructure based on the assumption that these assets will deliver an attractive return on investment. While we carefully consider the scope and expected costs of our capital projects, we are exposed to execution and capital cost overrun risk which may impact our return on these projects. We mitigate this risk by implementing comprehensive project governance and oversight processes and through the structuring of commercial arrangements where certain execution and capital cost risks may be shared with counterparties.

Regulatory

We operate in both regulated and deregulated power markets in both the United States and Canada. These markets are subject to various federal, state and provincial regulations in both countries. As power markets evolve across North America, there is the potential for regulatory bodies to implement new rules that could negatively affect us as a generator and marketer of electricity. These may be in the form of market rule changes, changes in the interpretation and application of market rules by regulators, price caps, emission controls, emissions costs, cost allocations to generators and out-of-market actions taken by others to build excess generation, all of which negatively affect the price of power or capacity, or both. In addition, our development projects rely on an orderly permitting process and any disruption to that process can have negative effects on project schedules and costs. We are an active participant in formal and informal regulatory proceedings and take legal action where required.

Weather

Significant changes in temperature and other weather events have many effects on our business, ranging from the impact on demand, availability and commodity prices, to efficiency and output capability. Extreme temperature and weather can affect market demand for power and natural gas and can lead to significant price volatility. Extreme weather can also restrict the availability of natural gas and power if demand is higher than supply. Seasonal changes in temperature can reduce the efficiency of our natural gas-fired power plants, and the amount of power they produce. Variable wind speeds affect earnings from our wind assets, and sun-light hours and intensity affects earnings from our solar assets.

Hydrology

Our hydroelectric power generation facilities in the U.S. Northeast are subject to hydrology risks that can impact the volume of water available for generation at these facilities including weather changes and events, local river management and potential dam failures at these plants or upstream facilities.

Competition 

We face various competitive forces that impact our existing assets and prospects for growth. For instance, our existing power plants in deregulated markets will compete over time with new power capacity. New supply could come in several forms including supply that employs more efficient power generation technologies, additional supply from regional power transmission interconnections and new supply in the form of distributed generation. We also face competition from other power companies in the greenfield power plant development arena.

TCPL Management's discussion and analysis 2015 69

Corporate

The following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented losses (the equivalent GAAP measure). Comparable depreciation and amortization is also a non-GAAP measure. See page 4 for more information on non-GAAP measures we use and page 100 for reconciliation to its GAAP equivalent.

year ended December 31
(millions of $)	2015		2014		2013
Comparable EBITDA	(171	)	(127	)	(108	)
Comparable depreciation and amortization	(31	)	(23	)	(16	)
Comparable EBIT	(202	)	(150	)	(124	)
Specific item:
Restructuring costs	(99	)	—		—
Segmented losses	(301	)	(150	)	(124	)

Corporate segmented losses in 2015 increased by $151 million compared to 2014 and included a charge of $99 million before tax for restructuring charges comprised of $56 million mainly related to 2015 severance costs and a provision of $43 million for 2016 planned severance costs and expected future losses under lease commitments. See below for more information on our corporate restructuring and business transformation. This amount has been excluded from our calculation of comparable EBIT.

Corporate restructuring and business transformation

In mid-2015, we commenced a business restructuring and transformation initiative. While there is no change to our corporate strategy, we have undertaken this initiative to reduce overall costs and maximize the effectiveness and efficiency of our existing operations.

At December 31, 2015, we had incurred $122 million before tax of 2015 corporate restructuring charges primarily related to severance, and recorded a provision of $87 million before tax related to planned severance costs in 2016 and expected future losses under lease commitments.

Of the total corporate restructuring charges of $209 million, $157 million was recorded in plant operating costs and other in the consolidated statement of income which was partially offset by $58 million recorded in revenues in the consolidated statement of income related to costs that were recoverable through current year regulatory and tolling structures. In addition, $44 million was recorded as a regulatory asset on the consolidated balance sheet, as it is expected to be recovered in future periods' regulatory and tolling structures, and $8 million was capitalized to projects impacted by the corporate restructuring.

We continue to progress our restructuring and business transformation initiative with further work to be completed in 2016. Benefits, in the form of enhanced business efficiencies and effectiveness, will be reflected in savings related to the execution of our capital programs, flow-through amounts to customers under established regulatory and commercial arrangements,and increased earnings. Determination of the amount and allocation of these benefits is predicated on completing additional phases of the initiative either underway or in the planning stage.

70  TCPL Management's discussion and analysis 2015

OTHER INCOME STATEMENT ITEMS

The following are reconciliations and related analyses of our non-GAAP measures to the equivalent GAAP measures. See page 4 for more information on non-GAAP measures we use and page 100 for reconciliation to its GAAP equivalent.

Interest Expense

year ended December 31
(millions of $)	2015		2014		2013
Comparable interest on long-term debt (including interest on junior subordinated notes)
Canadian dollar-denominated	(437	)	(443	)	(495	)
U.S. dollar-denominated	(911	)	(854	)	(766	)
Foreign exchange	(255	)	(90	)	(20	)
	(1,603	)	(1,387	)	(1,281	)
Other interest and amortization expense	(75	)	(107	)	(51	)
Capitalized interest	280		259		287
Comparable interest expense	(1,398	)	(1,235	)	(1,045	)
Specific item:
NEB 2013 Decision – 2012	—		—		(1	)
Interest expense	(1,398	)	(1,235	)	(1,046	)

Comparable interest expense in 2015 was $163 million higher than in 2014 due to the net effect of:

• higher interest expense as a result of long term debt issuances partially offset by Canadian and U.S. dollar-denominated debt maturities. See the Financial condition section on page 79 for details on long term debt

• a stronger U.S dollar and its effect on the foreign exchange impact on interest expense related to U.S. dollar-denominated debt

• lower carrying charges to shippers in 2015 on the net revenue variance for the Canadian Mainline

• higher capitalized interest primarily due to capital spending on Liquids Pipelines projects, LNG projects and the Napanee power generating facility, partially offset by lower capitalized interest on the completion of the Gulf Coast extension of the Keystone Pipeline System in first quarter 2014

• lower interest on amounts due to TransCanada.

Comparable interest expense in 2014 was $190 millionhigher than 2013 due to the net effect of:

• higher interest expense as a result of long term debt issuances partially offset by Canadian and U.S. dollar-denominated debt maturities

• a stronger U.S dollar and its effect on the foreign exchange impact on interest expense related to U.S. dollar-denominated debt

• higher carrying charges to shippers in 2014 on the net revenue variance for Canadian Mainline

• lower capitalized interest due to the completion of the Gulf Coast extension of the Keystone Pipeline System in first quarter 2014, partially offset by higher capitalized interest primarily for Keystone XL

• lower interest on amounts due to TransCanada.

TCPL Management's discussion and analysis 2015 71

Interest income and other

year ended December 31
(millions of $)	2015		2014		2013
Comparable interest income and other	213		149		80
Specific items (pre-tax):
NEB 2013 Decision – 2012	—		—		1
Risk management activities	(21	)	(21	)	(9	)
Interest income and other	192		128		72

In 2015 comparable interest income and other was $64 million higher than 2014. In 2014, comparable interest income and other was $69 millionhigher than 2013. These variances were the net result of:

• increased AFUDC related to our rate-regulated projects, including Energy East Pipeline and our Mexico pipeline projects

• higher realized losses in 2015 compared to 2014 and 2014 compared to 2013 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income

• the impact of a fluctuating U.S. dollar on the translation of foreign currency denominated working capital

• lower interest on amounts due from TransCanada.

Income tax expense

year ended December 31
(millions of $)	2015		2014		2013
Comparable income tax expense	(904	)	(858	)	(656	)
Specific items:
Keystone XL impairment charge	795		—		—
TC Offshore loss on sale	39		—		—
Restructuring costs	25		—		—
Turbine equipment impairment charge	16		—		—
Bruce Power merger – debt retirement charge	9		—		—
Alberta corporate income tax rate increase	(34	)	—		—
Cancarb gain on sale	—		(9	)	—
Niska contract termination	—		11		—
Gas Pacifico/INNERGY gain on sale	—		(1	)	—
NEB 2013 Decision – 2012	—		—		42
Part VI.I income tax adjustment	—		—		25
Risk management activities	19		27		(16	)
Income tax expense	(35	)	(830	)	(605	)

Comparable income tax expense increased$46 million in 2015 compared to 2014 mainly because of higher pre-tax earnings in 2015 compared to 2014 and changes in the proportion of income earned between Canadian and foreign jurisdictions.

Comparable income tax expense increased$202 million in 2014 compared to 2013 because of higher pre-tax earnings in 2014, changes in the proportion of income earned between Canadian and foreign jurisdictions as well as higher flow-through taxes in 2014 on Canadian regulated pipelines.

72  TCPL Management's discussion and analysis 2015

Net income attributable to non-controlling interests

Comparable net income attributable to non-controlling interests is a non-GAAP measure. See page 4 for more information on non-GAAP measures we use.

year ended December 31
(millions of $)	2015		2014		2013
Comparable net income attributable to non-controlling interests	(205	)	(151	)	(105	)
Specific item:
TC PipeLines, LP – Great Lakes impairment	199		—		—
Net income attributable to non-controlling interests	(6	)	(151	)	(105	)

Net income attributable to non-controlling interests decreased by $145 million in 2015 compared to 2014due to an impairment charge recorded by TC PipeLines, LP related to their equity investment goodwill in Great Lakes. At December 31, 2015, TC PipeLines, LP recorded an impairment of US$199 million. On consolidation, we recorded the non-controlling interests' 72 per cent of this TC PipeLines, LP impairment charge, which was US$143 million, or $199 million in Canadian dollars. TC PipeLines, LP's impairment charge is not recognized at the TCPL consolidation level as a result of our lower carrying value of Great Lakes. This $199 million positive impact to net income attributable to non-controlling interests is excluded from comparable net income attributable to non-controlling interests. See Critical accounting estimates section on page 93 for more information on our goodwill impairment testing.

Comparable net income attributable to non-controlling interests increased by $54 million in 2015 compared to 2014due to higher earnings resulting from the sale of our remaining 30 per cent direct interests in GTN in April 2015 and Bison in October 2014 to TC PipeLines, LP along with the impact of a stronger U.S. dollar on the Canadian dollar equivalent earnings from TC PipeLines, LP.

Comparable net income attributable to non-controlling interest increased $46 million in 2014 compared to 2013 primarily due to the sale of a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP in July 2013 and the remaining 30 per cent of Bison in October 2014.

Preferred share dividends

year ended December 31
(millions of $)	2015	2014		2013
Preferred share dividends	—	(2	)	(20	)

Preferred share dividends were nil for 2015. See Financial condition section on page 80 for more information. Preferred share dividends decreased by $18 million to $2 million in 2014 compared to $20 million in 2013 due to the redemption of Series U preferred shares in October 2013 and Series Y preferred shares in March 2014.

TCPL Management's discussion and analysis 2015 73

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 cash flow from our operations, access to capital markets, portfolio management including proceeds from the sale of natural gas pipeline assets to TC PipeLines, LP, cash on hand and substantial committed credit facilities.

Balance sheet analysis

As of December 31, 2015, assets increased by $5.5 billion, liabilities increased by $7.9 billion and equity decreased by $2.4 billion compared to December 31, 2014.

The effect of the strengthened U.S. dollar in 2015 resulted in increases to the Canadian dollar equivalent of our U.S. dollar assets, liabilities and non-controlling interests. Also impacting the increase to assets were:

• investments in property, plant and equipment on the NGTL System, Mexico pipeline construction, ANR, Northern Courier and Napanee

• equity investments in Bruce Power and Grand Rapids

• capital investment in projects under development including Energy East.

74  TCPL Management's discussion and analysis 2015

These increases to assets were partially offset by the impairment of Keystone XL and related projects.

Aside from the foreign exchange impact, the increase in liabilities was mainly due to the issuance in 2015 of long-term debt and junior subordinated debt exceeding repayment and increased regulatory liabilities for the Canadian Mainline.

The decrease in equity in 2015 was mainly due to the net loss attributable to controlling interests of $1,146 million and the dividends declared on common shares in the year.

Consolidated capital structure

at December 31, 2015

⁽¹⁾  Includes non-controlling interests in TC PipeLines, LP and Portland

⁽²⁾  Net of cash, amount due to/from affiliates and excluding junior subordinated notes

As at December 31, 2015, we had unused capacity of $2.0 billion and US$4.0 billion under our Canadian debt and U.S. debt shelf prospectuses, respectively, to facilitate future access to the North American debt markets.

We were in compliance with all of our financial covenants at December 31, 2015. Provisions of various trust indentures and credit arrangements with certain of our subsidiaries can restrict those subsidiaries' ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on our ability to declare and pay dividends on our common shares. In the opinion of management, these provisions do not currently restrict or alter our ability to declare or pay dividends. These trust indentures and credit arrangements also require us to comply with various affirmative and negative covenants and maintain certain financial ratios.

Cash flow

The following tables summarize the consolidated cash flow of our business.

year ended December 31
(millions of $)	2015		2014		2013
Net cash provided by operations	4,154		4,078		3,643
Net cash used in investing activities	(4,608	)	(4,144	)	(5,120	)
Deficiency	(454	)	(66	)	(1,477	)
Net cash provided by/(used in) financing activities	671		(345	)	1,807
	217		(411	)	330
Effect of foreign exchange rate changes on Cash and Cash Equivalents	112		—		28
Net change in Cash and Cash Equivalents	329		(411	)	358

We continue to fund our capital program through cash flow from operations, capital market financing activities and the sale of our U.S. natural gas pipeline assets to TC PipeLines, LP.

Liquidity will continue to be comprised of predictable cash flow generated from operations, committed credit facilities, our ability to access debt and equity markets in both Canada and the U.S., portfolio management including additional drop downs of our U.S. natural gas pipeline assets into TC PipeLines, LP and cash on hand.

The drop down of our remaining U.S. natural gas pipeline assets into TC PipeLines, LP remains an important financing lever for us

TCPL Management's discussion and analysis 2015 75

as it executes our capital growth program, subject to actual funding needs, market conditions, the relative attractiveness of alternate capital sources and the approvals of TC PipeLines LP’s board and our board.

Net cash provided by operations

year ended December 31
(millions of $)	2015		2014		2013
Funds generated from operations	4,513		4,267		3,977
Increase in operating working capital	(359	)	(189	)	(334	)
Net cash provided by operations	4,154		4,078		3,643

Funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our operations excluding the timing effects of working capital changes. See page 4 for more information about non-GAAP measures. The increase in 2015 compared to 2014 was driven by the increase in comparable earnings (as discussed in Financial highlights on page 12) adjusted for the following non-cash items: decreased deferred income tax expense, increased depreciation, higher equity AFUDC income and lower equity earnings. Funds generated from operations also reflected higher distributed earnings from equity investments, primarily from Bruce Power and our U.S. natural gas pipelines.

At December 31, 2015, our current liabilities were higher than our current assets, leaving us with a working capital deficit of $1.2 billion. This short-term deficiency is considered to be in the normal course of a growing business and is managed through:

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

• our access to capital markets

• approximately $7 billion of unutilized unsecured credit facilities.

Comparable distributable cash flow

year ended December 31
(millions of $)	2015		2014		2013
Net cash provided by operations	4,154		4,078		3,643
Increase in operating working capital	359		189		334
Funds generated from operations	4,513		4,267		3,977
Distributions in excess of equity earnings	226		159		128
Preferred share dividends paid	—		(4	)	(22	)
Distributions paid to non-controlling interests	(224	)	(174	)	(146	)
Maintenance capital expenditures including equity investments	(937	)	(781	)	(573	)
Distributable cash flow	3,578		3,467		3,364
Specific items impacting distributable cash flow (net of tax):
Restructuring costs	60		—		—
Niska contract termination	—		32		—
NEB 2013 Decision – 2012	—		—		(84	)
Comparable distributable cash flow	3,638		3,499		3,280

Comparable distributable cash flow, a non-GAAP measure, helps us assess the cash available to common shareholder before capital allocation. The increases from 2014 to 2015 as well as 2013 to 2014 were driven by increases in funds generated from operations, as described above, partially offset by higher maintenance capital expenditures primarily on ANR in 2015, and the Canadian Mainline and the NGTL System in 2014 and 2013. See page 4 for more information on non-GAAP measures we use.

Maintenance capital expenditures on our Canadian regulated natural gas pipelines was $347 million in 2015, $355 million in 2014 and $236 million in 2013 which contributed to their respective rate bases and net income.

76  TCPL Management's discussion and analysis 2015

Net cash used in investing activities

year ended December 31
(millions of $)	2015		2014		2013
Capital spending
Capital expenditures	(3,918	)	(3,489	)	(4,264	)
Capital projects in development	(511	)	(848	)	(488	)
	(4,429	)	(4,337	)	(4,752	)
Contributions to equity investments	(493	)	(256	)	(163	)
Acquisitions, net of cash acquired	(236	)	(241	)	(216	)
Proceeds from sale of assets, net of transaction costs	—		196		—
Distributions in excess of equity earnings	226		159		128
Deferred amounts and other	324		335		(117	)
Net cash used in investing activities	(4,608	)	(4,144	)	(5,120	)

Our 2015 capital expenditures were incurred primarily for:

• the expansion of the NGTL System

• construction of Mexico pipelines

• capital additions to our ANR pipeline

• construction of the Northern Courier pipeline

• expansion of the Canadian Mainline

• construction of the Napanee power generating facility.

Our 2014 capital expenditures were incurred primarily for expanding our NGTL System, construction of our Mexican pipelines, construction of the Houston Lateral and Tank Terminal and expansion of the ANR pipeline.

Our 2013 capital expenditures were incurred primarily for construction of the Gulf Coast project, expanding our NGTL System and construction of our Mexican pipelines.

Costs incurred on capital projects in development in 2015, 2014 and 2013 primarily related to the Energy East Pipeline and LNG pipeline projects.

Contributions to equity investments increased in 2015 compared to 2014 and 2014 compared to 2013 primarily due to our investments in Bruce Power and in Grand Rapids Phase 1 pipeline.

In 2015, we acquired an additional ownership interest in Bruce Power. See Significant events in the Energy section for more information. In 2014, we acquired an additional four solar facilities in Ontario and sold Cancarb and its related power generation facilities. In 2013, we acquired our first four solar facilities.

The increases from 2014 to 2015 and 2013 to 2014 in distributions in excess of equity earnings are primarily due to distributions from Bruce A.

TCPL Management's discussion and analysis 2015 77

Net cash provided by/(used in) financing activities

year ended December 31
(millions of $)	2015		2014		2013
Notes payable (repaid)/issued, net	(1,382	)	544		(492	)
Long-term debt issued, net of issue costs	5,045		1,403		4,253
Long-term debt repaid	(2,105	)	(1,069	)	(1,286	)
Junior subordinated notes issued, net of issue costs	917		—		—
Advances to affiliates, net	(189	)	(694	)	(297	)
Dividends and distributions paid	(1,670	)	(1,523	)	(1,454	)
Common shares issued	—		1,115		899
Partnership units of subsidiary issued, net of issue costs	55		79		384
Preferred shares redeemed	—		(200	)	(200	)
Net cash provided by/(used in) financing activities	671		(345	)	1,807

78  TCPL Management's discussion and analysis 2015

Long-term debt issued

(millions of $)
Entity	Issue date	Type	Maturity date	Amount	Interest rate
TCPL	January 2016	Senior Unsecured Notes	January 2026	US$850	4.875	%
	January 2016	Senior Unsecured Notes	January 2019	US$400	3.125	%
	November 2015	Senior Unsecured Notes	November 2017	US$1,000	1.625	%
	October 2015	Medium-Term Notes	November 2041	$400	4.55	%
	July 2015	Medium-Term Notes	July 2025	$750	3.30	%
	March 2015	Senior Unsecured Notes	March 2045	US$750	4.60	%
	January 2015	Senior Unsecured Notes	January 2018	US$500	1.875	%
	January 2015	Senior Unsecured Notes	January 2018	US$250	Floating
	February 2014	Senior Unsecured Notes	March 2034	US$1,250	4.63	%
	October 2013	Senior Unsecured Notes	October 2023	US$625	3.75	%
	October 2013	Senior Unsecured Notes	October 2043	US$625	5.00	%
	July 2013	Senior Unsecured Notes	June 2016	US$500	Floating
	July 2013	Medium-Term Notes	July 2023	$450	3.69	%
	July 2013	Medium-Term Notes	November 2041	$300	4.55	%
	January 2013	Senior Unsecured Notes	January 2016	US$750	0.75	%
TC PipeLines, LP	September 2015	Unsecured Term Loan	October 2018	US$170	Floating
	March 2015	Senior Unsecured Notes	March 2025	US$350	4.375	%
	July 2013	Unsecured Term Loan Facility	July 2018	US$500	Floating
Gas Transmission Northwest LLC	June 2015	Unsecured Term Loan	June 2019	US$75	Floating

Junior subordinated notes issued

(millions of $) Entity	Issue date	Type	Maturity date	Amount	Interest rate
TCPL	May 2015	Junior subordinated notes1	May 2075	US$750	5.875%2

¹  The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL and are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption.

²  The Junior subordinated notes were issued to TransCanada Trust. The interest rate is fixed at 5.875 per cent per annum and will reset starting May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum.

TransCanada Trust (the Trust), a financing trust subsidiary wholly owned by TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors with a fixed interest rate of 5.625 per cent for the first ten years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to us in US$750 million junior subordinated notes of TCPL at a rate of 5.875 per cent which includes a 0.25 per cent administration charge. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in our financial statements as TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL. 

Pursuant to the terms of the Trust Notes and related agreements, in certain circumstances, (1) TCPL may issue deferral preferred shares to holders of the Trust Notes in lieu of interest; and (2) TransCanada and TCPL would be prohibited from declaring or paying dividends on or redeeming their outstanding preferred shares (or, if none are outstanding, their respective common shares) until all deferral preferred shares are redeemed by TCPL. The Trust Notes may also be automatically exchanged for preferred shares of TCPL upon certain kinds of bankruptcy and insolvency events. All of these preferred shares would rank equally with other outstanding first preferred shares of TCPL. Further details regarding the terms of the Trust Notes and the related agreements entered into by TransCanada and TCPL can be found in the prospectus in respect of the Trust Notes and other documents filed under the Trust's profile on SEDAR at www.sedar.com.

TCPL Management's discussion and analysis 2015 79

Long-term debt retired

(millions of $)	Retirement date
Entity		Type	Amount		Interest rate
TCPL	January 2016	Senior Unsecured Notes		US$750	0.75	%
	August 2015	Debentures		$150	11.90	%
	June 2015	Senior Unsecured Notes		US$500	3.40	%
	March 2015	Senior Unsecured Notes		US$500	0.875	%
	January 2015	Senior Unsecured Notes		US$300	4.875	%
	June 2014	Debentures		$125	11.10	%
	February 2014	Medium-Term Notes		$300	5.05	%
	January 2014	Medium-Term Notes		$450	5.65	%
	August 2013	Senior Unsecured Notes	US$500		5.05	%
	June 2013	Senior Unsecured Notes	US$350		4.00	%
Gas Transmission Northwest LLC	June 2015	Senior Unsecured Notes	US$75		5.09	%
Nova Gas Transmission Ltd.	June 2014	Debentures		$53	11.20	%

Preferred share redemption

In March 2014, we redeemed all four million Series Y preferred shares of TCPL at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends. The total face value of the outstanding Series Y shares was $200 million and they carried an aggregate of $11 million in annualized dividends.

The net proceeds of the above debt were used for general corporate purposes and to reduce short-term indebtedness.

TC PipeLines, LP

At-the-market equity issuance program

In August 2014, TC PipeLines, LP initiated its at-the-market equity issuance program (ATM program) under which it is authorized to offer and sell common units having an aggregate offering price of up to US$200 million. Our ownership interest in TC PipeLines, LP will decrease as a result of equity issuances under the ATM program.

From January 1 to December 31, 2015, 0.7 million common units were issued under the TC PipeLines, LP ATM program generating net proceeds of approximately US$44 million.

From August 2014 until December 31, 2014, 1.3 million common units were issued under the ATM program generating net proceeds of approximately US$73 million.

Asset drop downs

On January 1, 2016, we closed the sale of a 49.9 per cent interest of our total 61.7 per cent interest in PNGTS to TC PipeLines, LP for US$223 million including the assumption of US$35 million of proportional PNGTS debt.

In April 2015, we closed the sale of our remaining 30 per cent interest in GTN to TC PipeLines, LP, for an aggregate purchase price of US$457 million. Proceeds were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TC PipeLines, LP.

In October 2014, we closed the sale of our remaining 30 per cent interest in Bison to TC PipeLines, LP, for cash proceeds of US$215 million.

In July 2013, we closed the sale of a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million representing 45 per cent of GTN's debt.

80  TCPL Management's discussion and analysis 2015

Credit facilities

We have committed, revolving credit facilities that primarily support our commercial paper programs. In addition, we have demand credit facilities that are used for general corporate purposes, including issuing letters of credit and providing additional liquidity.

At December 31, 2015, we had $8.9 billion (2014 - $6.7 billion) in unsecured credit facilities, including:

Amount	Unused capacity	Borrower	Description	Matures
$3 billion	$3 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility that supports TCPL's Canadian commercial paper program	December 2020
US$1 billion	US$1 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility that supports TCPL's U.S. commercial paper program	December 2016
US$0.5 billion	US$0.5 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility that is used for TCPL USA general corporate purposes	December 2016
US$1.5 billion	US$1.5 billion	TAIL/TCPM	Committed, syndicated, revolving, extendible credit facility that supports the joint TAIL/TCPM commercial paper program in the U.S.	December 2016
$1.7 billion	$0.7 billion	TCPL/TCPL USA	Supports the issuance of letters of credit and provides additional liquidity	Demand

At December 31, 2015, our operated affiliates had an additional $0.6 billion (2014 - $0.4 billion) of undrawn capacity on committed credit facilities.

TCPL Management's discussion and analysis 2015 81

Related party debt financing

Related party debt consists of the following amounts due from affiliates:

	Amount	For	Matures
Discount Notes	$2.4 billion	Discount notes issued to TransCanada; used for general corporate purposes.	2016
Credit Facility	$0.1 billion	Demand revolving credit facility arrangement with TransCanada; used for general corporate purposes.	n/a

Related party debt consists of the following amounts due to affiliates:

	Amount	For	Matures
Credit Facility	$0.3 billion	TransCanada's unsecured credit facility agreement; used to repay indebtedness, make partner contributions to Bruce A, and for working capital and general corporate purposes.	2016

Contractual obligations

Our contractual obligations include our long-term debt, operating leases, purchase obligations and other liabilities incurred in our business such as environmental liability funds and employee retirement and post-retirement benefit plans.

Payments due (by period)

at December 31, 2015	Total	less than 12 months	12 – 36 months	37 – 60 months	more than 60 months
(millions of $)
Notes payable	1,218	1,218	—	—	—
Long-term debt (includes junior subordinated notes)	34,061	2,547	5,529	3,029	22,956
Operating leases (future payments for various premises, services and equipment, less sub-lease receipts)	1,561	308	554	389	310
Purchase obligations	3,759	2,397	853	150	359
Other long-term liabilities reflected on the balance sheet	96	8	18	19	51
	40,695	6,478	6,954	3,587	23,676

Long-term debt

At the end of 2015, we had $31.6 billion of long-term debt and $2.4 billion of junior subordinated notes outstanding, compared to $24.8 billion of long-term debt and $1.2 billion of junior subordinated notes at December 31, 2014.

Total notes payable were $1.2 billion at the end of 2015 compared to $2.5 billion at the end of 2014.

We attempt to spread out the maturity profile of our debt. The weighted-average maturity of our long-term debt is 16 years, with the majority maturing beyond five years.

Interest payments

At December 31, 2015, scheduled interest payments related to our long-term debt and junior subordinated notes were as follows:

at December 31, 2015	Total	less than 12 months	12 – 36 months	37 – 60 months	more than 60 months
(millions of $)
Long-term debt	21,786	1,612	3,022	2,625	14,527
Junior subordinated notes	8,229	149	298	298	7,484
	30,015	1,761	3,320	2,923	22,011

82  TCPL Management's discussion and analysis 2015

Operating leases

Our operating leases for premises, services and equipment expire at different times between now and 2052. Some of our operating leases include the option to renew the agreement for one to 25 years.

Our commitments under the Alberta PPAs are considered operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Fixed payments under these PPAs have been included in our summary of future obligations. Variable payments have been excluded as these payments are dependent upon plant availability and other factors. Our share of power purchased under the PPAs in 2015 was $348 million (2014 – $391 million; 2013 – $242 million).

Purchase obligations

We have purchase obligations that are transacted at market prices and in the normal course of business, including long-term natural gas transportation and purchase arrangements.

Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts.

Payments due (by period)¹ 

at December 31, 2015	Total	less than 12 months	12 – 36 months	37 – 60 months	more than 60 months
(millions of $)
Natural Gas Pipelines
Transportation by others2	286	91	153	24	18
Capital spending3	901	887	14	—	—
Other	4	2	2	—	—
Liquids Pipelines
Capital spending3	765	563	201	1	—
Other	38	6	12	9	11
Energy
Commodity purchases	460	262	188	10	—
Capital spending3	644	489	155	—	—
Other4	594	69	99	97	329
Corporate
Information technology and other	67	28	29	9	1
	3,759	2,397	853	150	359

¹  The amounts in this table exclude funding contributions to our pension plans.

²  Demand rates are subject to change. The contractual obligations in the table are based on demand volumes only and exclude commodity charges incurred when volumes flow.

³  Amounts include capital expenditures and capital projects under development, are estimates and are subject to variability based on timing of construction and project enhancements.

⁴  Includes estimates of certain amounts which are subject to change depending on plant-fired hours, use of natural gas storage facilities, the consumer price index, actual plant maintenance costs, plant salaries as well as changes in regulated rates for transportation.

Outlook

We are developing quality projects under our long-term $58.6 billion capital program. These long-life infrastructure assets are supported by long-term commercial arrangements, and once completed, are expected to generate significant growth in earnings and cash flow.

Our $58.6 billion capital program is comprised of $13.4 billion of near-term projects and $45.2 billion of commercially secured medium and longer-term projects, each of which are subject to key commercial or regulatory approvals. The portfolio is expected to be financed through our growing internally generated cash flow and a combination of funding options including:

TCPL Management's discussion and analysis 2015 83

• senior debt

• project financing

• preferred shares

• hybrid securities

• additional drop downs of our U.S. natural gas pipeline assets to TC PipeLines, LP

• asset sales

• potential involvement of strategic or financial partners

• portfolio management

Additional financing alternatives available include common equity through DRP or, lastly, discrete equity issuances.

84  TCPL Management's discussion and analysis 2015

GUARANTEES

Bruce Power

We and our partner, OMERS, have each severally guaranteed some of Bruce Power contingent financial obligations related to a lease agreement and contractor and supplier services. The Bruce Power guarantees have terms to 2018 except for one guarantee with no termination date that has no exposure associated with it.

At December 31, 2015, our share of the potential exposure under the Bruce Power guarantees was estimated to be $88 million. The carrying amount of these guarantees was estimated to be $2 million. Our exposure under certain of these guarantees is unlimited.

Other jointly owned entities

We and our partners in certain other jointly owned entities have also guaranteed (jointly, severally, or jointly and severally) the financial performance of these entities relating mainly to redelivery of natural gas, PPA payments and the payment of liabilities. The guarantees have terms ranging to 2040.

Our share of the potential exposure under these assurances was estimated at December 31, 2015 to be a maximum of $139 million. The carrying amount of these guarantees was $24 million, and is included in other long-term liabilities. In some cases, if we make a payment that exceeds our ownership interest, the additional amount must be reimbursed by our partners.

OBLIGATIONS – PENSION AND OTHER POST-RETIREMENT PLANS

In 2016, we expect to make funding contributions of approximately $70 million for the defined benefit pension plans, approximately $7 million for the other post-retirement benefit plans and approximately $37 million for the savings plan and defined contribution pension plans. In addition, we expect to provide a $33 million letter of credit to the Canadian defined benefit plan for the funding of solvency requirements.

In 2015, we made funding contributions of $96 million to our defined benefit pension plans, $6 million for the other post-retirement benefit plans and $41 million for the savings plan and defined contribution pension plans. We also provided a $33 million letter of credit to a defined benefit plan in lieu of cash funding.

Outlook

The next actuarial valuation for our pension and other post-retirement benefit plans will be carried out as at January 1, 2016. Based on current market conditions, we expect funding requirements for these plans to approximate 2015 levels for several years. This will allow us to amortize solvency deficiencies in the plans, in addition to normal funding costs.

Our net benefit cost for our defined benefit and other post-retirement plans increased to $146 million in 2015 from $115 million in 2014, mainly due to a lower discount rate used to measure the benefit obligation.

Future net benefit costs and the amount we will need to contribute to fund our plans will depend on a range of factors, including:

• interest rates

• actual returns on plan assets

• changes to actuarial assumptions and plan design

• actual plan experience versus projections

• amendments to pension plan regulations and legislation.

We do not expect future increases in the level of funding needed to maintain our plans to have a material impact on our liquidity.

TCPL Management's discussion and analysis 2015 85

Other information

RISKS AND RISK MANAGEMENT

The following is a summary of general risks that affect our company. You can find risks specific to each operating business segment in the business segment discussions.

Risk management is integral to the successful operation of our business. Our strategy is to ensure that our risks and related exposures are in line with our business objectives and risk tolerance.

We build risk assessment into our decision-making processes at all levels.

The Board's Governance Committee oversees our risk management activities, which includes ensuring that there are appropriate management systems in place to manage our risks, including adequate Board oversight of our risk management policies, programs and practices. Other Board committees oversee specific types of risk: the Audit Committee oversees management's role in monitoring financial risk, the Human Resources Committee oversees executive resourcing and compensation, organizational capabilities and compensation risk, and the Health, Safety and Environment Committee oversees operational, safety and environmental risk through regular reporting from management.

Our executive leadership team is accountable for developing and implementing risk management plans and actions, and effective risk management is reflected in their compensation.

Operational risks

Risk and Description	Impact	Monitoring and Mitigation
Business interruption
Operational risks, including labour disputes, equipment malfunctions or breakdowns, acts of terror, or natural disasters and other catastrophic events.	Decrease in revenues, increase in operating costs or legal proceedings or other expenses all of which could reduce our earnings. Losses not covered by insurance could have an adverse effect on operations, cash flow and financial position.	We have incident, emergency and crisis management systems to ensure an effective response to minimize further loss or injuries and to enhance our ability to resume operations. We also have a Business Continuity Program that determines critical business processes and develops resumption plans to ensure process continuity. We have comprehensive insurance to mitigate certain of these risks, but insurance does not cover all events in all circumstances.
Reputation and relationships
Our reputation and relationship with Indigenous communities and our stakeholders including other communities, landowners, governments and government agencies, and environmental non-governmental organizations is very important.	These Indigenous communities and stakeholders can have a significant impact on our operations, infrastructure development and overall reputation.	Our Stakeholder Engagement Framework is our formal commitment to stakeholder engagement. Our four core values – integrity, collaboration, responsibility and innovation – are at the heart of our commitment to stakeholder engagement, and guide us in our interactions with stakeholders. Additionally, our Aboriginal Relations and Native American Relations Policies guide our engagement with Indigenous communities.
Execution and capital costs
Investing in large infrastructure projects involves substantial capital commitments and associated execution risks based on the assumption that these assets will deliver an attractive return on investment in the future.	While we carefully consider the expected cost of our capital projects, under some contracts we bear capital cost overrun and schedule risk which may decrease our return on these projects.	Under some contracts, we share the cost of execution risks with customers, in exchange for the potential benefit they will realize when the project is finished.

86  TCPL Management's discussion and analysis 2015

Risk and Description	Impact	Monitoring and Mitigation
Cyber security
We rely on our information technology to process, transmit and store electronic information, including information we use to safely operate our assets.	A breach in the security of our information technology could expose our business to a risk of loss, misuse or interruption of critical information and functions. This could affect our operations, damage our assets, result in safety incidents, damage to the environment, reputational harm, competitive disadvantage, regulatory enforcement actions and potential litigation, which could have a material adverse effect on our operations, financial position and results of operations.	We have a comprehensive cyber security strategy which aligns with industry and recognized standards for cyber security. This strategy includes cyber security risk assessments, continuous monitoring of networks and other information sources for threats to the organization, comprehensive incident response plans/processes and a cyber security awareness program for employees.

Pipeline abandonment costs

The NEB's LMCI is an NEB-approved initiative that requires all Canadian pipeline companies regulated by the NEB to set aside funds to cover future pipeline abandonment costs.

Effective January 2015, funds to cover future abandonment costs are collected through an abandonment surcharge applied to monthly tolls set-aside and invested in a Government of Canada fixed income portfolio. A status report for each trust fund disclosing the 2015 year-end balance and audited financial statements will be filed with the NEB in April 2016.

Health, safety and environment

The Health, Safety and Environment committee of TransCanada’s Board of Directors (the Board) monitors compliance with our HSE corporate commitment statement through regular reporting from management. We have an integrated HSE Management System that is used to capture, organize, document, monitor and improve our related policies, programs and procedures.

The HSE Management System is modeled after international standards, conforms to external industry consensus standards and voluntary programs, and complies with applicable legislative requirements and other internal management systems. It follows a continuous improvement cycle.

The committee reviews HSE performance including risk management three times a year. It receives detailed reports on:

• overall HSE corporate governance and performance

• operational performance and preventive maintenance metrics

• asset integrity programs

• security and emergency preparedness, incident response and evaluation

• people and process safety performance metrics

• developments in and compliance with applicable legislation and regulations.

The committee also receives updates on any specific areas of operational and construction risk management review being conducted by management and the results and corrective action plans emanating from internal and third party audits.

The safety and integrity of our existing and newly-developed infrastructure is a top priority. All assets are designed, constructed and commissioned with full consideration given to safety and integrity, and are brought in service only after all necessary requirements have been satisfied. In 2015, we spent $803 million for pipeline integrity on the natural gas and liquids pipelines we operate, an increase of $253 million over 2014 primarily due to an increase of in-line pipeline inspections and related maintenance projects on all systems as well as an increased amount of pipe replacement required due to population encroachment on the pipelines. Under the approved regulatory models in Canada, non-capital pipeline integrity expenditures on NEB-regulated pipelines are generally treated on a flow-through basis and, as a result, these expenditures have minimal impact on our earnings. Under the Keystone Pipeline System contracts, pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures generally have no impact on our earnings. We continue to have industry leading safety performance in 2015.

TCPL Management's discussion and analysis 2015 87

Our Energy operations spending associated with process safety and our various integrity programs is used to minimize risk to employees and the public, process equipment, the surrounding environment, and to prevent disruptions to serving the electrical needs of our customers, within the footprint of each facility.

Spending associated with public safety on Energy assets is focused primarily on our hydro dams and associated equipment.

Our main environmental risks are:

• air and GHG emissions

• product releases, including crude oil and natural gas, into the environment (land, water and air)

• use, storage and disposal of chemicals and hazardous materials

• compliance with corporate and regulatory policies and requirements and new regulations.

As described in the Business interruption section, above, we have a set of procedures in place to manage our response to natural disasters which include catastrophic events such as forest fires, tornadoes, earthquakes, floods, volcanic eruptions and hurricanes. The procedures, which are included in our Emergency Preparedness and Response Program, are designed to help protect the health and safety of our employees, minimize risk to the public and limit any operational impacts on the environment.

Environmental compliance and liabilities

Our facilities are subject to federal, state, provincial and local environmental statutes and regulations governing environmental protection, including air and GHG emissions, water quality, wastewater discharges and waste management. Our facilities are required to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals and requirements. Failure to comply could result in administrative, civil or criminal penalties, remedial requirements or orders affecting future operations.

Through our Environmental Management Program we continually monitor our facilities to ensure compliance with all environmental requirements. We routinely monitor proposed changes in environmental policy, legislation and regulation, and where the risks are potentially large or uncertain, we comment on proposals independently or through industry associations.

We are not aware of any material outstanding orders, claims or lawsuits against us related to releasing or discharging any material into the environment or in connection with environmental protection.

Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on operations.

Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties, and with damage claims arising from the contamination of properties.

It is not possible to estimate the amount and timing of all our future expenditures related to environmental matters because:

• environmental laws and regulations (and interpretation and enforcement of them) change

• new claims can be brought against our existing or discontinued assets

• our pollution control and clean up cost estimates may change, especially when our current estimates are based on preliminary site investigation or agreements

• we may find new contaminated sites, or what we know about existing sites could change

• where there is potentially more than one responsible party involved in litigation, we cannot estimate our joint and several liability with certainty.

At December 31, 2015, we had accrued approximately $32 million related to these obligations (2014 - $31 million). This represents the amount that we have estimated that we will need to manage our currently known environmental liabilities. We believe that we have considered all necessary contingencies and established appropriate reserves for environmental liabilities; however, there is the risk that unforeseen matters may arise requiring us to set aside additional amounts. We adjust this reserve quarterly to account for changes in liabilities.

88  TCPL Management's discussion and analysis 2015

Greenhouse gas emissions regulation risk

We own assets and have business interests in a number of regions where there are regulations to address industrial GHG emissions. We have procedures in place to comply with these regulations, including:

• under the SGER in Alberta, established industrial facilities with GHG emissions above a certain threshold have to reduce their emissions below an intensity baseline. Our Sundance and Sheerness PPA facilities and NGTL System facilities are subject to this regulation. We recover compliance costs on the NGTL System through the tolls our customers pay. A portion of the compliance costs for Sundance and Sheerness are recovered through market pricing and hedging activities. A new climate change policy, the Climate Leadership Plan (CLP), was announced by the Alberta government in the fall of 2015 that has the objective of positioning the provincial economy to be less carbon intensive. Our internal processes and procedures for managing changing regulations such as the CLP are mature. The potential new costs and business opportunities that come with the Alberta CLP are within the bounds of our previously expected changes to GHG regulation. We have been actively managing its exposure to the existing and newly-announced Alberta carbon pricing policies to minimize the impact.

• B.C. has a tax on GHG emissions from fossil fuel combustion. We recover the compliance costs for our compressor and meter stations through the tolls our customers pay.

• U.S. northeastern states that are members of the RGGI have implemented a CO2 cap-and-trade program for electricity generators. This program applies to both the Ravenswood and Ocean State Power generation facilities.

• Québec’s Regulation Respecting a Cap-and-Trade System for Greenhouse Gas Emission Allowances came into force in 2011. Bécancour has been required to cover its GHG emissions since 2013. As per the regulations, the government allocates free emission units for the majority of Bécancour's compliance requirements. The remaining requirements were met with GHG instruments purchased at auctions or secondary markets. The costs of these emissions units were recovered through commercial contracts. The pipeline facilities in Québec are also covered under this regulation and have purchased compliance instruments.

• in 2013, California implemented a cap-and-trade program for industrial emitters of GHGs, including electricity importers. We have costs associated with the program from our power marketing activities.

We recorded $59 million of expenses under these programs in 2015 (2014 - $54 million). There are federal, regional, state and provincial initiatives currently in development. While economic events may continue to affect the scope and timing of new regulations, we anticipate that most of our facilities will be subject to future regulations to manage industrial GHG emissions.

Financial risks

We are exposed to market risk, counterparty credit risk and liquidity risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value.

These strategies, policies and limits are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance. We manage market risk and counterparty credit risk within limits that are ultimately established by the Board, implemented by senior management and monitored by our risk management and internal audit groups. Management monitors compliance with market and counterparty risk management policies and procedures, and reviews the adequacy of the risk management framework, overseen by the Audit Committee. Our internal audit group assists the Audit Committee by carrying out regular and ad-hoc reviews of risk management controls and procedures, and reporting up to the Audit Committee.

Market risk

We build and invest in energy infrastructure projects, buy and sell energy commodities, issue short-term and long-term debt (including amounts in foreign currencies) and invest in foreign operations. Certain of these activities expose us to market risk from changes in commodity prices and foreign exchange and interest rates which may affect our earnings and the value of the financial instruments we hold.

We use derivative contracts to assist in managing our exposure to market risk, including:

• forwards and futures contracts – agreements to buy or sell a financial instrument or commodity at a specified price and date in the future. We use foreign exchange and commodity forwards and futures to manage the impact of changes in foreign exchange rates and commodity prices

• swaps – agreements between two parties to exchange streams of payments over time according to specified terms. We use interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices

TCPL Management's discussion and analysis 2015 89

• options – agreements that give the purchaser the right (but not the obligation) to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. We use option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

We assess contracts we use to manage market risk to determine whether all, or a portion of it, meets the definition of a derivative.

Commodity price risk

We are exposed to changes in commodity prices which may affect our earnings. We use several strategies to reduce this exposure, including:

• committing a portion of expected power supply to fixed price sales contracts of varying terms while reserving a portion of our unsold power supply to mitigate operational and price risk in our asset portfolio

• purchasing a portion of the natural gas we need to fuel our natural gas-fired power plants in advance or entering into contracts that base the sale price of our electricity on the cost of the natural gas, effectively locking in a margin

• meeting our power sales commitments using power we generate ourselves or with power we buy at fixed prices, reducing our exposure to changes in commodity prices

• using derivative instruments to enter into offsetting or back-to-back positions to manage commodity price risk created by certain fixed and variable prices in arrangements for different pricing indices and delivery points.

Foreign exchange and interest rate risk

Certain of our businesses generate income in U.S. dollars, but since we report 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 of our foreign operations and by using foreign exchange derivatives.

We have floating interest rate debt which subjects us to interest rate cash flow risk. We manage this using a combination of interest rate swaps and options.

Average exchange rate – U.S. to Canadian dollars

2015	1.28
2014	1.10
2013	1.03

The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly 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 page 4 for more information.

Significant U.S. dollar-denominated amounts

year ended December 31
(millions of US$)	2015		2014		2013
U.S. and International Natural Gas Pipelines comparable EBIT	738		630		542
U.S. Liquids Pipelines comparable EBIT	640		570		389
U.S. Power comparable EBIT	313		269		216
Interest on U.S. dollar-denominated long-term debt	(911	)	(854	)	(766	)
Capitalized interest on U.S. dollar-denominated capital expenditures	109		154		219
U.S. non-controlling interests and other	231		(234	)	(196	)
	1,120		535		404

90  TCPL Management's discussion and analysis 2015

Derivatives designated as a 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 or principal amounts for the derivatives designated as a net investment hedge were as follows:

	2015			2014
at December 31	Fair value1		Notional or principal amount	Fair value1		Notional or principal amount
(millions of $)
U.S. dollar cross-currency interest rate swaps (maturing 2016 to 2019)2	(730	)	US 3,150	(431	)	US 2,900
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	50		US 1,800	(28	)	US 1,400
	(680	)	US 4,950	(459	)	US 4,300

¹  Fair values equal carrying values.

²  Consolidated net income in 2015 included net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements.

U.S. dollar-denominated debt designated as a net investment hedge

at December 31
(millions of $)	2015	2014
Carrying value	23,000 (US 16,600)	17,000 (US 14,700)
Fair value	23,800 (US 17,200)	19,000 (US 16,400)

Counterparty credit risk

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

• accounts receivable

• portfolio investments

• the fair value of derivative assets

• cash and notes receivable.

If a counterparty fails to meet its financial obligations to us according to the terms and conditions of the financial instrument, we could experience a financial loss. We manage our exposure to this potential loss using recognized credit management techniques, including:

• dealing with creditworthy counterparties – a significant amount of our credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

• setting limits on the amount we can transact with any one counterparty – we monitor and manage the concentration of risk exposure with any one counterparty, and reduce our exposure when we feel we need to and when it is allowed under the terms of our contracts

• using contract netting arrangements and obtaining financial assurances, such as guarantees and letters of credit or cash, when we believe it is necessary.

There is no guarantee that these techniques will protect us from material losses.

We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. We had no significant credit losses in 2015 and no significant amounts past due or impaired at year end. We had a credit risk concentration of $248 million (US$179 million) at December 31, 2015 with one counterparty (2014 - $258 million (US$222 million)). This amount is secured by a guarantee from the counterparty's parent company and is expected to be fully collectible.

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.

TCPL Management's discussion and analysis 2015 91

For our Canadian regulated gas pipeline assets, counterparty credit risk is managed through application of tariff provisions as approved by the NEB.

Liquidity risk

Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage our liquidity by continuously forecasting our cash flow for a 12 month period and making sure 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.

See page 74 Financial condition for more information about our liquidity.

Dealing with legal proceedings

Legal proceedings, arbitrations and actions are part of doing business. While we cannot predict the final outcomes of proceedings and actions with certainty, management does not expect any current proceeding or action to have a material impact on our consolidated financial position, results of operations or liquidity. Other than the Keystone XL legal proceedings described on page 46, we are not aware of any potential legal proceeding or action that would have a material impact on our consolidated financial position, results of operations or liquidity.

CONTROLS AND PROCEDURES

We meet Canadian and U.S. regulatory requirements for disclosure controls and procedures, internal control over financial reporting and related CEO and CFO certifications.

Disclosure controls and procedures

Under the supervision and with the participation of management, including our President and CEO and our CFO, we carried out quarterly evaluations of the effectiveness of our disclosure controls and procedures, including for the period ended December 31, 2015, as required by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, our President and CEO and our CFO have concluded that the disclosure controls and procedures are effective in that they are designed to ensure that the information we are required to disclose in reports we file with or send to securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws.

Management’s annual report on internal control over financial reporting

We are responsible for establishing and maintaining adequate internal control over financial reporting, which is a process designed by, or under the supervision of, our President and CEO and our CFO, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.

Under the supervision and with the participation of management, including our President and CEO and our CFO, an evaluation of the effectiveness of the internal control over financial reporting was conducted as of December 31, 2015 based on the criteria described in “Internal Control - Integrated Framework” issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that, as of December 31, 2015, the internal control over financial reporting was effective.

CEO and CFO Certifications

Our President and CEO and our CFO have attested to the quality of the public disclosure in our fiscal 2015 reports filed with Canadian securities regulators and the SEC, and have filed certifications with them.

Changes in internal control over financial reporting

There has been no change in our internal control over financial reporting that occurred during the year covered by this annual report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

92  TCPL Management's discussion and analysis 2015

CRITICAL ACCOUNTING ESTIMATES

When we prepare financial statements that conform with GAAP, we are required to make certain estimates and assumptions that affect the timing and amount 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 judgment. We also regularly assess the assets and liabilities themselves.

The following accounting estimates require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements from those estimates.

Rate-regulated accounting

Under GAAP, an asset qualifies to use RRA when it meets three criteria:

• a regulator must establish or approve the rates for the regulated services or activities

• the regulated rates must be designed to recover the cost of providing the services or products

• it is reasonable to assume that rates set at levels to recover the cost can be charged to (and collected from) customers because of the demand for services or products and the level of direct and indirect competition.

We believe that the regulated natural gas pipelines and certain liquids pipelines projects we account for using RRA meet these criteria. The most significant impact of using these principles is the timing of when we recognize certain expenses and revenues, which is based on the economic impact of the regulators' decisions about our revenues and tolls, and may be different from what would otherwise be expected under GAAP. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods. Regulatory liabilities are amounts that are expected to be refunded through customer rates in future periods.

Regulatory assets and liabilities

at December 31
(millions of $)	2015	2014
Regulatory assets
Long-term assets	1,184	1,297
Short-term assets (included in Other current assets)	85	16
Regulatory liabilities
Long-term liabilities	1,159	263
Short-term liabilities (included in Accounts payable and other)	44	30

Impairment of long-lived assets and goodwill

We review long-lived assets (such as plant, property and equipment) and intangible assets for impairment whenever events or changes in circumstances lead us to believe we might not be able to recover an asset's carrying value. If the total of the undiscounted future cash flows we estimate for an asset is less than its carrying value, we consider its fair value to be less than its carrying value and we calculate and record an impairment loss to recognize this.

In 2015, the following impairments were recorded:

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

• a loss of $43 million after tax relating to certain Energy turbine equipment.

TCPL Management's discussion and analysis 2015 93

Keystone XL impairment

At December 31, 2015, in connection with the denial of the U.S. Presidential permit, we evaluated our $4.3 billion investment in Keystone XL and related projects, including Keystone Hardisty Terminal, for impairment. As a result of our analysis, we determined that the carrying amount of these assets was no longer recoverable, and recognized a total non-cash impairment charge of $3.7 billion ($2.9 billion after tax). The impairment charge was based on the excess of the carrying value over the estimated fair value of$621 million.

at December 31, 2015	Estimated	Impairment charge
(millions of $)	fair value	Pre-tax	After-tax
Plant and equipment	463	1,460	1,391
Terminals, including Keystone Hardisty Terminal	158	274	219
Intangible assets	—	1,150	737
Capitalized interest	—	725	488
Future cancellation costs	—	77	56
	621	3,686	2,891

The estimated fair value of $463 million on plant and equipment was based on an expected price that would be received to sell the assets in their current condition. An independent third party evaluation was utilized in the assessment of the fair value of these assets. Key assumptions used in the determination of selling price included an estimated two year disposal period and the current weak energy market conditions. Various outcomes were also considered, including alternate uses for the remaining assets. Depending on the outcomes of sales and alternate uses for the assets, the value realized may be different than what has been estimated. The $158 million fair value of the terminals was estimated using a risk-adjusted discounted cash flow approach as a measure of fair value and considered alternative independent utility of these assets. We recorded a full impairment charge on capitalized interest and other intangible assets as these costs are no longer probable to be recovered. The impairment charge also included certain cancellation fees that will be incurred in the future if the project is ultimately abandoned.

Energy Turbine Impairment

Following the evaluation of specific capital project opportunities in 2015, it was determined that the carrying value of certain Energy turbine equipment was not fully recoverable. These turbines had been previously purchased for a power development project that did not proceed. Various other projects have recently been evaluated for possible use of this equipment and we have determined there is not an appropriate operation or project in which we currently expect to economically utilize this asset. As a result, at December 31, 2015, we recognized a non-cash impairment charge of $59 million ($43 million after tax) on the excess of the carrying value over the fair value of the turbines, which was determined using a third party valuation based on a comparison to similar assets available for sale in the market.

Goodwill

We test goodwill for impairment annually or more frequently if events or changes in circumstances lead us to believe it might be impaired. We first assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired, and if we conclude that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, we use a two-step process to test for impairment:

1. First, we compare the fair value of the reporting unit to its book value, including its goodwill. If fair value is less than book value, we consider our goodwill to be impaired.

2. Next, we measure the amount of the impairment by calculating the implied fair value of the reporting unit's goodwill. We do this by deducting the fair value of the tangible and intangible net assets of the reporting unit from the fair value we calculated in the first step. If the goodwill's carrying value exceeds its implied fair value, we record an impairment charge.

94  TCPL Management's discussion and analysis 2015

We base these valuations on our projections of future cash flows, which involves making estimates and assumptions about:

• discount rates

• commodity and capacity prices

• market supply and demand assumptions

• growth opportunities

• output levels

• competition from other companies

• regulatory changes.

If our assumptions change significantly, our requirement to record an impairment charge could also change.

The estimated fair value of Great Lakes natural gas transportation business exceeded its carrying value by less than 10 per cent using a discounted cash flow analysis. Despite the recent improvement in income from Great Lakes, its long term value has been adversely impacted by the changing natural gas flows in its market region as well as a change in our view of the strategic alternatives to increase utilization of Great Lakes. As a result, we reduced forecasted cash flows from the reporting unit for the next ten years as compared to those utilized in previous impairment tests. There is a risk that continued reductions in future cash flow forecasts and adverse changes in key assumptions could result in a future impairment of a portion of the goodwill balance relating to Great Lakes.

Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$386 millionat December 31, 2015 (2014 – US$243 million). The increase in our share of goodwill is a result of the impairment charge of US$199 million recorded at the TC PipeLines, LP level on its equity method goodwill related to Great Lakes. On a consolidated basis, our carrying value of our investment in Great Lakes is proportionately lower compared to the 46.45 per cent owned through TC PipeLines, LP. As a result, the estimated fair value of Great Lakes exceeded our consolidated carrying value and no impairment was recorded in 2015.

Our assumptions of ANR’s projected future cash flows would be impacted should ANR not reach a new settlement or other positive outcome through its Section 4 rate case proceeding. An adverse outcome could result in future impairment of a portion of the goodwill balance relating to ANR. The goodwill balance related to ANR was US$1.9 billion at December 31, 2015 (2014 - US$1.9 billion).

Asset retirement obligations

When there is a legal obligation to set aside funds to cover future abandonment costs, and we can reasonably estimate them, we recognize the fair value of the ARO in our financial statements.

We cannot determine when we will retire many of our hydro-electric power plants, oil pipelines, natural gas pipelines and transportation facilities and regulated natural gas storage systems because we intend to operate them as long as there is supply and demand, and so we have not recorded obligations for them.

For those we do record, we use the following assumptions:

• when we expect to retire the asset

• the scope of abandonment and reclamation activities that are required

• inflation and discount rates.

The ARO is initially recorded when the obligation exists and is subsequently accreted through charges to operating expenses.

We continue to evaluate our future abandonment obligations and costs and monitor developments that could affect the amounts we record.

TCPL Management's discussion and analysis 2015 95

FINANCIAL INSTRUMENTS

All financial instruments, including both derivative and non-derivative 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 normal 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.

Non-derivative financial instruments

Fair value of non-derivative financial instruments

The fair value of our notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt and junior subordinated notes has been estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments including cash and cash equivalents, accounts receivable, due from affiliates, intangibles and other assets, notes payable, accounts payable and other, due to affiliates, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity and would be classified in Level II of the fair value hierarchy.

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

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 effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in OCI in the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other and interest expense.

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.  

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

Fair value of derivative instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

96  TCPL Management's discussion and analysis 2015

Balance sheet presentation of derivative instruments

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

at December 31
(millions of $)	2015		2014
Other current assets	442		409
Intangible and other assets	168		93
Accounts payable and other	(926	)	(749	)
Other long-term liabilities	(625	)	(411	)
	(941	)	(658	)

Anticipated timing of settlement – derivative instruments

The anticipated timing of settlement for derivative instruments assumes constant commodity prices, interest rates and foreign exchange rates. Settlements will vary based on the actual value of these factors at the date of settlement.

at December 31, 2015	Total fair value		2016		2017 and 2018		2019 and 2020
(millions of $)
Derivative instruments held for trading
Assets	456		330		113		13
Liabilities	(630	)	(499	)	(124	)	(7	)
Derivative instruments in hedging relationships
Assets	154		112		28		14
Liabilities	(921	)	(427	)	(435	)	(59	)
	(941	)	(484	)	(418	)	(39	)

Unrealized and realized (losses)/gains of derivative instruments

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

year ended December 31
(millions of $)	2015		2014
Derivative instruments held for trading1
Amount of unrealized losses in the year
Commodities	(37	)	(40	)
Foreign exchange	(21	)	(20	)
Amount of realized losses in the year
Commodities	(151	)	(28	)
Foreign exchange	(112	)	(28	)
Derivative instruments in hedging relationships2,3
Amount of realized (losses)/gains in the year
Commodities	(179	)	130
Interest rate	8		4

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 2015, net realized gains on fair value hedges were $11 million (2014 - $7 million) and were included in interest expense.

³  In 2015 and 2014, 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.

TCPL Management's discussion and analysis 2015 97

Derivatives in cash flow hedging relationships

The components of the consolidated statement of OCI related to derivatives in cash flow hedging relationships is as follows:

year ended December 31
(millions of $, pre-tax)	2015		2014
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Commodities	(92	)	(128	)
Foreign exchange	—		10
	(92	)	(118	)
Reclassification of gains/(losses) on derivative instruments from AOCI to net income (effective portion)1
Commodities2	128		(111	)
Interest rate3	16		16
	144		(95	)
Losses on derivative instruments recognized in net income (ineffective portion)
Commodities2	—		(13	)
	—		(13	)

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

²  Reported within revenues on the consolidated statement of income.

³  Reported within interest expense on the consolidated statement of income.

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 December 31, 2015, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $32 million (2014 – $15 million), with collateral provided in the normal course of business of nil (2014 – nil). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2015, we would have been required to provide additional collateral of $32 million (2014 – $15 million) to our counterparties. We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.

ACCOUNTING CHANGES

Changes in accounting policies for 2015

Derivatives and Hedging

In August 2015, the FASB issued new guidance on the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments in this update apply to entities that enter into contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through or delivery to a location within a nodal energy market whereby one of the contracting parties incurs charges (or credits) for the transmission of that electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. This new guidance was effective upon issuance, was applied prospectively and did not have a material impact on our consolidated financial statements.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, we elected to retrospectively apply this guidance on January 1, 2015. Application of this new guidance simplified our process in determining deferred tax amounts and our presentation. The application of this amendment resulted in a reclassification of deferred tax assets previously recorded in other current assets and deferred tax liabilities previously recorded in accounts payable and other to non-current deferred income tax assets and liabilities. Prior year amounts have been reclassified to conform to current year presentation.

98  TCPL Management's discussion and analysis 2015

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what qualifies as a discontinued operation has changed and there are expanded disclosures required. This new guidance was applied prospectively from January 1, 2015 and there was no impact on our consolidated financial statements as a result of applying this new standard.

Future accounting changes

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application.

We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from GAAP the concept of extraordinary items. This new guidance is effective from January 1, 2016 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

Consolidation

In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. We are currently evaluating the impact of the adoption of this guidance and have not yet determined the effect on our consolidated financial statements.

Imputation of interest

In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in Intangible and other assets to an offset of their respective debt liabilities.

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify

that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable

value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and

transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

Business Combinations

In September 2015, the FASB issued guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements as the adjustment was determined, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.

TCPL Management's discussion and analysis 2015 99

RECONCILIATION OF NON-GAAP MEASURES

year ended December 31
(millions of $)	2015		2014		2013
EBITDA	1,866		5,542		4,958
Specific items:
Keystone XL impairment charge	3,686		—		—
TC Offshore loss on sale	125		—		—
Restructuring costs	99		—		—
Turbine equipment impairment charge	59		—		—
Bruce Power merger – debt retirement charge	36		—		—
Cancarb gain on sale	—		(108	)	—
Niska contract termination	—		43		—
Gas Pacifico/ INNERGY gain on sale	—		(9	)	—
NEB 2013 Decision – 2012	—		—		(55	)
Risk management activities1	37		53		(44	)
Comparable EBITDA	5,908		5,521		4,859
Comparable depreciation and amortization	(1,765	)	(1,611	)	(1,472	)
Comparable EBIT	4,143		3,910		3,387
Other income statement items
Comparable interest expense	(1,398	)	(1,235	)	(1,045	)
Comparable interest income and other	213		149		80
Comparable income taxes	(904	)	(858	)	(656	)
Comparable net income attributable to non-controlling interests	(205	)	(151	)	(105	)
Preferred share dividends	—		(2	)	(20	)
Comparable earnings	1,849		1,813		1,641
Specific items (net of tax):
Keystone XL impairment charge	(2,891	)	—		—
TC Offshore loss on sale	(86	)	—		—
Restructuring costs	(74	)	—		—
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		—		—
Cancarb gain on sale	—		99		—
Niska contract termination	—		(32	)	—
Gas Pacifico/ INNERGY gain on sale	—		8		—
NEB 2013 Decision – 2012	—		—		84
Part VI.I income tax adjustment	—		—		25
Risk management activities1	(39	)	(47	)	19
Net (loss)/income attributable to common shares	(1,146	)	1,841		1,769
Comparable depreciation and amortization	(1,765	)	(1,611	)	(1,472	)
Specific item:
NEB 2013 Decision – 2012	—		—		(13	)
Depreciation and amortization	(1,765	)	(1,611	)	(1,485	)

100  TCPL Management's discussion and analysis 2015

year ended December 31
(millions of $)	2015		2014		2013
Comparable interest expense	(1,398	)	(1,235	)	(1,045	)
Specific item:
NEB 2013 Decision – 2012	—		—		(1	)
Interest expense	(1,398	)	(1,235	)	(1,046	)
Comparable interest income and other	213		149		80
Specific items:
NEB 2013 Decision – 2012	—		—		1
Risk management activities1	(21	)	(21	)	(9	)
Interest income and other	192		128		72
Comparable income tax expense	(904	)	(858	)	(656	)
Specific items:
Keystone XL impairment charge	795		—		—
TC Offshore loss on sale	39		—		—
Restructuring costs	25		—		—
Turbine equipment impairment charge	16		—		—
Bruce Power merger – debt retirement charge	9		—		—
Alberta corporate income tax rate increase	(34	)	—		—
Cancarb gain on sale	—		(9	)	—
Niska contract termination	—		11		—
Gas Pacifico/ INNERGY gain on sale	—		(1	)	—
NEB 2013 Decision – 2012	—		—		42
Part VI.I income tax adjustment	—		—		25
Risk management activities1	19		27		(16	)
Income tax expense	(35	)	(830	)	(605	)

1	year ended December 31
	(millions of $)	2015		2014		2013
	Canadian Power	(8	)	(11	)	(4	)
	U.S. Power	(30	)	(55	)	50
	Natural Gas Storage	1		13		(2	)
	Foreign exchange	(21	)	(21	)	(9	)
	Income taxes attributable to risk management activities	19		27		(16	)
	Total (losses)/gains from risk management activities	(39	)	(47	)	19

TCPL Management's discussion and analysis 2015 101

Comparable EBITDA and comparable EBIT by business segment

year ended December 31, 2015	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of $)
EBITDA	3,352		(2,364	)	1,148		(270	)	1,866
Keystone XL impairment charge	—		3,686		—		—		3,686
TC Offshore loss on sale	125		—		—		—		125
Restructuring costs	—		—		—		99		99
Turbine equipment impairment charge	—		—		59		—		59
Bruce Power merger – debt retirement charge	—		—		36		—		36
Risk management activities	—		—		37		—		37
Comparable EBITDA	3,477		1,322		1,280		(171	)	5,908
Comparable depreciation and amortization	(1,132	)	(266	)	(336	)	(31	)	(1,765	)
Comparable EBIT	2,345		1,056		944		(202	)	4,143
year ended December 31, 2014	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of $)
EBITDA	3,250		1,059		1,360		(127	)	5,542
Cancarb gain on sale	—		—		(108	)	—		(108	)
Niska contract termination	—		—		43		—		43
Gas Pacifico/ INNERGY gain on sale	(9	)	—		—		—		(9	)
Risk management activities	—		—		53		—		53
Comparable EBITDA	3,241		1,059		1,348		(127	)	5,521
Comparable depreciation and amortization	(1,063	)	(216	)	(309	)	(23	)	(1,611	)
Comparable EBIT	2,178		843		1,039		(150	)	3,910
year ended December 31, 2013	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of $)
EBITDA	2,907		752		1,407		(108	)	4,958
NEB 2013 Decision – 2012	(55	)	—		—		—		(55	)
Risk management activities	—		—		(44	)	—		(44	)
Comparable EBITDA	2,852		752		1,363		(108	)	4,859
Comparable depreciation and amortization	(1,013	)	(149	)	(294	)	(16	)	(1,472	)
Comparable EBIT	1,839		603		1,069		(124	)	3,387

102  TCPL Management's discussion and analysis 2015

QUARTERLY RESULTS

Selected quarterly consolidated financial data

(unaudited, millions of $)

2015	Fourth		Third	Second	First
Revenues	2,851		2,944	2,631	2,874
Net (loss)/income attributable to common shares	(2,436	)	424	454	412
Comparable earnings	475		462	422	490

2014	Fourth	Third	Second	First
Revenues	2,616	2,451	2,234	2,884
Net income attributable to common shares	485	481	443	432
Comparable earnings	538	474	359	442

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 Natural Gas Pipelines, 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 crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income are affected by:

• developments outside of the normal course of operations

• newly constructed assets being placed in service

• regulatory decisions.

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.

TCPL Management's discussion and analysis 2015 103

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 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 2015, comparable earnings excluded:

• 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 expected to close in early 2016

• a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 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 form 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 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.

In third quarter 2015, comparable earnings excluded a charge of $6 million after-tax for severance costs as part of a restructuring initiative to maximize the effectiveness and efficiency of our existing operations.

In second quarter 2015, comparable earnings excluded a $34 million adjustment to income tax expense due to the enactment of an increase in the Alberta corporate income tax rate in June 2015 and a charge of $8 million after-tax for severance costs primarily as a result of the restructuring of our major projects group in response to delayed timelines on certain of our major projects along with a continued focus on enhancing the efficiency and effectiveness of our operations.

In fourth quarter 2014, comparable earnings excluded an $8 million after-tax gain on the sale of Gas Pacifico/INNERGY.

In second quarter 2014, comparable earnings excluded a $99 million after-tax gain on the sale of Cancarb Limited and a $32 million after-tax loss related to the termination of the Niska Gas Storage contract.

104  TCPL Management's discussion and analysis 2015

FOURTH QUARTER 2015 HIGHLIGHTS

Consolidated results

three months ended December 31	2015		2014
(millions of $)
Natural Gas Pipelines	572		621
Liquids Pipelines	(3,413	)	230
Energy	82		219
Corporate	(161	)	(43	)
Total segmented (losses)/earnings	(2,920	)	1,027
Interest expense	(386	)	(332	)
Interest income and other	85		39
(Loss)/Income before income taxes	(3,221	)	734
Income tax recovery/(expense)	646		(206	)
Net (loss)/income	(2,575	)	528
Net income/(loss) attributable to non-controlling interests	139		(43	)
Net (loss)/income attributable to controlling interests	(2,436	)	485
Preferred share dividends	—		—
Net (loss)/income attributable to common shares	(2,436	)	485

Net income attributable to common shares decreased by $2,921 million to a net loss of $2,436 million for the three months ended December 31, 2015 compared to the same period in 2014. The 2015 results included:

• 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 expected to close in early 2016

• a net charge of $60 million after tax for our business restructuring and transformation initiative comprised of $28 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 form 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 on turbine equipment held for future use in our Energy business

• a charge of $27 million after tax charge 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.

The 2014 results included:

• an $8 million after-tax gain on sale of our 30 per cent interest in Gas Pacifico/INNERGY.

Net income in both 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.

Comparable earnings decreased by $63 million for the three months ended December 31, 2015 compared to the same period in 2014 as discussed below in the reconciliation of net income to comparable earnings.

TCPL Management's discussion and analysis 2015 105

Reconciliation of net income to comparable earnings

three months ended December 31	2015		2014
(millions of $)
Net (loss)/income attributable to common shares	(2,436	)	485
Specific items (net of tax):
Keystone XL impairment charge	2,891		—
TC Offshore loss on sale	86		—
Restructuring costs	60		—
Turbine equipment impairment charge	43		—
Bruce Power merger – debt retirement charge	27		—
Non-controlling interests (TC PipeLines, LP – Great Lakes impairment)	(199	)	—
Gas Pacifico/ INNERGY gain on sale	—		(8	)
Risk management activities1	3		61
Comparable earnings	475		538

1	three months ended December 31
	(millions of $)	2015		2014
	Canadian Power	(1	)	(11	)
	U.S. Power	(8	)	(85	)
	Natural Gas Storage	(1	)	9
	Foreign exchange	4		(12	)
	Income tax attributable to risk management activities	3		38
	Total losses from risk management activities	(3	)	(61	)

106  TCPL Management's discussion and analysis 2015

Comparable EBITDA and comparable EBIT by business segment

three months ended December 31, 2015	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of $)
Comparable EBITDA	984		342		275		(74	)	1,527
Depreciation and amortization	(287	)	(69	)	(88	)	(8	)	(452	)
Comparable EBIT	697		273		187		(82	)	1,075

three months ended December 31, 2014	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of $)
Comparable EBITDA	884		288		385		(36	)	1,521
Depreciation and amortization	(272	)	(58	)	(79	)	(7	)	(416	)
Comparable EBIT	612		230		306		(43	)	1,105

Comparable earnings

Comparable earnings decreased by $63 million for the three months ended December 31, 2015 compared to the same period in 2014. This was primarily the net effect of:

• lower Canadian Mainline incentive earnings

• lower earnings from Canadian Power due to lower realized power prices and PPA volumes from Western Power, lower earnings from Bruce Power due to higher planned outage days and higher operating expenses at Bruce A, partially offset by fewer planned outage days and lower lease expense at Bruce B and lower earnings on sale of unused natural gas transportation from Eastern Power

• higher earnings from Liquids Pipelines due to higher contracted volumes

• higher interest expense due to long-term debt issuances and the ceasing of capitalized interest on Keystone XL and related projects following the November 6, 2015 denial of a U.S. Presidential permit.

The stronger U.S. dollar in 2015 compared to 2014 positively impacted the translated results in our U.S. businesses, however, this impact was partially offset by a corresponding increase in interest expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our exposure.

Highlights by business segment

Natural Gas Pipelines

Natural Gas Pipelines segmented earnings decreased by $49 million for the three months ended December 31, 2015 compared to the same period in 2014 and included a $125 million pre-tax loss provision recorded as a result of a December 2015 agreement to sell TC Offshore, which is expected to close in early 2016. Segmented earnings in 2014 included a $9 million pre-tax gain related to the sale of Gas Pacifico/INNERGY in November 2014. These amounts has been excluded from our calculation of comparable EBIT.

Depreciation and amortization increased by $15 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly because of a higher investment base on the NGTL System, depreciation for the completed Tamazunchale Extension, and the effect of a stronger U.S. dollar.

Canadian Pipelines

Net income for the Canadian Mainline decreased by $63 million for the three months ended December 31, 2015 compared to the same period in 2014 primarily due to a lower average investment base in 2015 and a lower ROE of 10.1 per cent in 2015 compared to 11.5 per cent in 2014. Incentive earnings of $59 million for 2014 were recorded in the fourth quarter 2014 contributing to the higher net income in that period.

Net income for the NGTL System increased by $10 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to a higher average investment base and OM&A incentive losses realized in 2014.

TCPL Management's discussion and analysis 2015 107

U.S. and International Pipelines

Comparable EBITDA for U.S. and International Pipelines increased by US$42 million for the three months ended December 31, 2015 compared to the same period in 2014. This increase was the net effect of higher ANR Southeast Mainline transportation revenue, partially offset by increased spending on ANR pipeline integrity work.

A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.

Liquids Pipelines

Liquids Pipelines segmented earnings decreased by $3,643 million to a segmented loss of $3,413 million for the three months ended December 31, 2015 compared to the same period in 2014. The segmented loss in 2015 included a $3,686 million pre-tax impairment charge related to Keystone XL and related projects in connection with the denial of the U.S. Presidential permit. This amount has been excluded from our calculation of comparable EBIT. The remainder of the Liquids Pipelines segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.

Comparable EBITDA for the Keystone Pipeline System increased by $54 million for the three months ended December 31, 2015 compared to the same period in 2014 and was primarily due to higher contracted volumes and a stronger U.S. dollar and its positive effect on the foreign exchange impact.

Comparable depreciation and amortization increased by $11 million for the three months ended December 31, 2015 compared to the same period in 2014 primarily due to the effect of a stronger U.S. dollar.

Energy

Energy segmented earnings decreased by $137 million for the three months ended December 31, 2015 compared to the same period in 2014 and included the following specific items for the three months ended December 31, 2015 that are excluded from comparable earnings:

• a $59 million pre-tax charge relating to an impairment in value on turbine equipment previously purchased for a new power development project that did not proceed. Various other projects have recently been evaluated for possible use of this equipment and those evaluations support the impairment of the carrying value. The evaluation included a comparison to similar assets available for sale on the market

• a pre-tax charge of $36 million related to Bruce Power's retirement of debt in conjunction with the merger of the Bruce A and Bruce B partnerships

• unrealized losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks as follows:

Risk management activities	three months ended December 31
(millions of $, pre-tax)	2015		2014
Canadian Power	(1	)	(11	)
U.S. Power	(8	)	(85	)
Natural Gas Storage	(1	)	9
Total losses from risk management activities	(10	)	(87	)

The period-over-period 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 particular 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 impact of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them representative of our underlying operations.

108  TCPL Management's discussion and analysis 2015

Comparable EBITDA for Energy decreased by $110 million for the three months ended December 31, 2015 compared to the same period in 2014 due to the net effect of:

• lower earnings from Western Power as a result of lower realized power prices and PPA volumes

• lower earnings from Bruce Power due to lower volumes resulting from higher planned outage days and higher operating expenses at Bruce A, partially offset by higher volumes resulting from fewer planned outage days and lower lease expense at Bruce B

• lower earnings from Eastern Power primarily due to lower earnings on the sale of unused natural gas transportation

• a stronger U.S. dollar and its positive effect on the foreign exchange impact.

Comparable EBITDA for Western Power decreased by $60 million for the three months ended December 31, 2015 compared to the same period in 2014. The decrease was due to lower realized power prices and lower PPA volumes.

Comparable EBITDA for Eastern Power decreased by $26 million for the three months ended December 31, 2015 compared to the same period in 2014 due to lower earnings on the sale of unused natural gas transportation and lower contractual earnings at Bécancour.

Comparable income from equity investments from Bruce A decreased by $58 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to lower volumes resulting from higher planned outage days and higher operating expenses.

Comparable income from equity investments from Bruce B increased by $26 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to higher volumes resulting from lower planned outage days and lower lease expense based on the terms of the lease agreement with Ontario Power Generation.

Comparable EBITDA for U.S. Power decreased US$5 million for the three months ended December 31, 2015 compared to the same period in 2014 primarily due to the net effect of:

• lower capacity revenue at Ravenswood due to lower realized capacity prices in New York and the impact of lower availability at the facility

• lower realized power prices at our New England facilities

• higher generation at our Ravenswood facility

• higher sales to wholesale, commercial and industrial customers in both the PJM and New England markets.

Comparable EBITDA for Natural Gas Storage and Other decreased by $5 million for the three months ended December 31, 2015 compared to the same period in 2014 mainly due to decreased proprietary revenue as a result of lower realized natural gas storage price spreads.

TCPL Management's discussion and analysis 2015 109

Glossary

Units of measure		Accounting terms
Bbl/d	Barrel(s) per day	AFUDC	Allowance for funds used during construction
Bcf	Billion cubic feet	AOCI	Accumulated other comprehensive (loss)/income
Bcf/d	Billion cubic feet per day	ARO	Asset retirement obligations
GWh	Gigawatt hours	ASU	Accounting Standards Update
km	Kilometres	DRP	Dividend reinvestment plan
KW-M	Kilowatt month	EBIT	Earnings before interest and taxes
MMcf/d	Million cubic feet per day	EBITDA	Earnings before interest, taxes, depreciation and amortization
MW	Megawatt(s)	GAAP	U.S. generally accepted accounting principles
MWh	Megawatt hours	FASB	Financial Accounting Standards Board (U.S.)
		OCI	Other comprehensive (loss)/income
		RRA	Rate-regulated accounting
General terms and terms related to our operations		ROE	Rate of return on common equity
bitumen	A thick, heavy oil that must be diluted to flow (also see: diluent). One of the components of the oil sands, along with sand, water and clay	Specific Item	Items we believe are significant but not reflective of our underlying operations in the period
cogeneration facilities	Facilities that produce both electricity and useful heat at the same time	Government and regulatory bodies terms
diluent	A thinning agent made up of organic compounds. Used to dilute bitumen so it can be transported through pipelines	CFE	Comisión Federal de Electricidad (Mexico)
Eastern Triangle	Canadian Mainline region between North Bay, Toronto and Montréal	CRE	Comisión Reguladora de Energia, or Energy Regulatory Commission (Mexico)
FID	Final investment decision	DOS	Department of State (U.S.)
FIT	Feed-in tariff	EPA	Environmental Protection Agency (U.S.)
force majeure	Unforeseeable circumstances that prevent a party to a contract from fulfilling it	FERC	Federal Energy Regulatory Commission (U.S.)
fracking	Hydraulic fracturing. A method of extracting natural gas from shale rock	IEA	International Energy Agency
GHG	Greenhouse gas	IESO	Independent Electricity System Operator
HSE	Health, safety and environment	ISO	Independent System Operator
investment base	Includes rate base as well as assets under construction	LMCI	Land Matters Consultation Initiative (Canada)
LNG	Liquefied natural gas	NAFTA	North American Free Trade Agreement
NEB 2014 Decision	In response to the RH-01-2014 Decision on the Canadian Mainline's 2015-2030 Tolls Application	NEB	National Energy Board (Canada)
OM&A	Operating, maintenance and administration	OPA	Ontario Power Authority (Canada)
PJM Interconnection area (PJM)	A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 states and the District of Columbia	OPEC	Organization of the Petroleum Exporting Countries
PPA	Power purchase arrangement	RGGI	Regional Greenhouse Gas Initiative (northeastern U.S.)
rate base	Our annual average investment used	SEC	U.S. Securities and Exchange Commission
WCSB	Western Canada Sedimentary Basin	SGER	Specified Gas Emitters Regulations

110  TCPL Management's discussion and analysis 2015

EX-13.2

EXHIBIT 13.2

Management's report on Internal Control over Financial Reporting

The consolidated financial statements and Management's Discussion and Analysis (MD&A) included in this Annual Report are the responsibility of the management of TransCanada PipeLines Limited (TCPL or the Company) and have been approved by the Board of Directors of the Company. The consolidated financial statements have been prepared by management in accordance with United States generally accepted accounting principles (GAAP) and include amounts that are based on estimates and judgments. The MD&A is based on the Company's financial results. It compares the Company's financial and operating performance in 2015 to that in 2014, and highlights significant changes between 2014 and 2013. The MD&A should be read in conjunction with the consolidated financial statements and accompanying notes. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.

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

Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control (COSO) – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded, based on its evaluation, that internal control over financial reporting was effective as of December 31, 2015, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.

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

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

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

Russell K. Girling	Donald R. Marchand
President and Chief Executive Officer	Executive Vice-President and Chief Financial Officer
February 10, 2016

TCPL Consolidated financial statements2015111

Independent Auditors' Report

TO THE SHAREHOLDER OF TRANSCANADA PIPELINES LIMITED

We have audited the accompanying consolidated financial statements of TransCanada PipeLines Limited, which comprise the Consolidated balance sheets as at December 31, 2015 and December 31, 2014, the Consolidated statements of income, comprehensive income, cash flows and equity for each of the years in the three-year period ended December 31, 2015, and Notes, comprising a summary of significant accounting policies and other explanatory information.

MANAGEMENT'S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

AUDITORS' RESPONSIBILITY

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

OPINION

In our opinion, the Consolidated financial statements present fairly, in all material respects, the consolidated financial position of TransCanada PipeLines Limited as at December 31, 2015 and December 31, 2014, and its consolidated results of operations and its consolidated cash flows for each of the years in the three-year period ended December 31, 2015 in accordance with U.S. generally accepted accounting principles.

Chartered Professional Accountants

Calgary, Canada

February 10, 2016

112 TCPL Consolidated financial statements2015

Consolidated statement of income

year ended December 31	2015		2014		2013
(millions of Canadian $)
Revenues
Natural Gas Pipelines	5,383		4,913		4,497
Liquids Pipelines	1,879		1,547		1,124
Energy	4,038		3,725		3,176
	11,300		10,185		8,797
Income from Equity Investments (Note 8)	440		522		597
Operating and Other Expenses
Plant operating costs and other	3,250		2,973		2,674
Commodity purchases resold	2,237		1,836		1,317
Property taxes	517		473		445
Depreciation and amortization	1,765		1,611		1,485
Asset impairment charges (Note 7)	3,745		—		—
	11,514		6,893		5,921
(Loss)/Gain on Assets Held for Sale/Sold (Notes 6 and 25)	(125	)	117		—
Financial Charges
Interest expense (Note 16)	1,398		1,235		1,046
Interest income and other	(192	)	(128	)	(72	)
	1,206		1,107		974
(Loss)/Income before Income Taxes	(1,105	)	2,824		2,499
Income Tax Expense/(Recovery) (Note 15)
Current	137		146		43
Deferred	(102	)	684		562
	35		830		605
Net (Loss)/Income	(1,140	)	1,994		1,894
Net Income attributable to non-controlling interests (Note 18)	6		151		105
Net (Loss)/Income Attributable to Controlling Interests	(1,146	)	1,843		1,789
Preferred share dividends	—		2		20
Net (Loss)/Income Attributable to Common Shares	(1,146	)	1,841		1,769

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

TCPL Consolidated financial statements2015113

Consolidated statement of comprehensive income

year ended December 31	2015		2014		2013
(millions of Canadian $)
Net (Loss)/Income	(1,140	)	1,994		1,894
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains on net investment in foreign operations	813		517		383
Change in fair value of net investment hedges	(372	)	(276	)	(239	)
Change in fair value of cash flow hedges	(57	)	(69	)	71
Reclassification to net income of gains and losses on cash flow hedges	88		(55	)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	51		(102	)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	32		18		23
Other comprehensive income/(loss) on equity investments	47		(204	)	234
Other comprehensive income/(loss) (Note 21)	602		(171	)	580
Comprehensive (Loss)/Income	(538	)	1,823		2,474
Comprehensive income attributable to non-controlling interests	312		281		171
Comprehensive (Loss)/Income Attributable to Controlling Interests	(850	)	1,542		2,303
Preferred share dividends	—		2		20
Comprehensive (Loss)/Income Attributable to Common Shares	(850	)	1,540		2,283

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

114 TCPL Consolidated financial statements2015

Consolidated statement of cash flows

year ended December 31	2015		2014		2013
(millions of Canadian $)
Cash Generated from Operations
Net (loss)/income	(1,140	)	1,994		1,894
Depreciation and amortization	1,765		1,611		1,485
Asset impairment charges (Note 7)	3,745		—		—
Deferred income taxes (Note 15)	(102	)	684		562
Income from equity investments (Note 8)	(440	)	(522	)	(597	)
Distributed earnings received from equity investments (Note 8)	576		579		605
Employee post-retirement benefits expense, net of funding (Note 22)	44		37		50
Loss/(gain) on assets held for sale/sold (Notes 6 and 25)	125		(117	)	—
Equity allowance for funds used during construction	(165	)	(95	)	(19	)
Unrealized losses/(gains) on financial instruments	58		74		(35	)
Other	47		22		32
Increase in operating working capital (Note 24)	(359	)	(189	)	(334	)
Net cash provided by operations	4,154		4,078		3,643
Investing Activities
Capital expenditures (Note 4)	(3,918	)	(3,489	)	(4,264	)
Capital projects in development (Note 4)	(511	)	(848	)	(488	)
Contributions to equity investments (Note 8)	(493	)	(256	)	(163	)
Acquisitions, net of cash acquired (Note 25)	(236	)	(241	)	(216	)
Proceeds from sale of assets, net of transaction costs (Note 25)	—		196		—
Distributions in excess of equity earnings (Note 8)	226		159		128
Deferred amounts and other	324		335		(117	)
Net cash used in investing activities	(4,608	)	(4,144	)	(5,120	)
Financing Activities
Notes payable (repaid)/issued, net	(1,382	)	544		(492	)
Long-term debt issued, net of issue costs	5,045		1,403		4,253
Long-term debt repaid	(2,105	)	(1,069	)	(1,286	)
Junior subordinated notes issued, net of issue costs	917		—		—
Advances to affiliates, net	(189	)	(694	)	(297	)
Dividends on common shares	(1,446	)	(1,345	)	(1,286	)
Dividends on preferred shares	—		(4	)	(22	)
Distributions paid to non-controlling interests	(224	)	(174	)	(146	)
Common shares issued	—		1,115		899
Partnership units of subsidiary issued, net of issue costs	55		79		384
Preferred shares redeemed (Note 20)	—		(200	)	(200	)
Net cash provided by/(used in) financing activities	671		(345	)	1,807
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	112		—		28
Increase/(Decrease) in Cash and Cash Equivalents	329		(411	)	358
Cash and Cash Equivalents
Beginning of year	484		895		537
Cash and Cash Equivalents
End of year	813		484		895

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

TCPL Consolidated financial statements2015115

Consolidated balance sheet

at December 31		2015		2014
(millions of Canadian $)
ASSETS
Current Assets
Cash and cash equivalents		813		484
Accounts receivable (Note 28)		1,401		1,372
Due from affiliates (Note 28)		2,476		2,842
Inventories		323		292
Other (Note 5)		1,353		1,018
		6,366		6,008
Plant, Property and Equipment (Note 7)		44,817		41,774
Equity Investments (Note 8)		6,214		5,598
Regulatory Assets (Note 9)		1,184		1,297
Goodwill (Note 10)		4,812		4,034
Intangible and Other Assets (Note 11)		3,185		2,641
Restricted Investments		351		63
		66,929		61,415
LIABILITIES
Current Liabilities
Notes payable (Note 12)		1,218		2,467
Accounts payable and other (Note 13 and 28)		3,014		2,891
Due to affiliates (Note 28)		311		866
Accrued interest		520		425
Current portion of long-term debt (Note 16)		2,547		1,797
		7,610		8,446
Regulatory Liabilities (Note 9)		1,159		263
Other Long-Term Liabilities (Note 14)		1,260		1,052
Deferred Income Tax Liabilities (Note 15)		5,144		4,856
Long-Term Debt (Note 16)		29,037		22,960
Junior Subordinated Notes (Note 17)		2,422		1,160
		46,632		38,737
EQUITY
Common shares, no par value (Note 19)		16,320		16,320
Issued and outstanding:	December 31, 2015 – 779 million shares
	December 31, 2014 – 779 million shares
Additional paid-in capital		210		404
Retained earnings		2,989		5,606
Accumulated other comprehensive loss (Note 21)		(939	)	(1,235	)
Controlling interests		18,580		21,095
Non-controlling interests (Note 18)		1,717		1,583
		20,297		22,678
		66,929		61,415

Commitments, Contingencies and Guarantees (Note 26)

Corporate Restructuring Costs (Note 27)

Subsequent Events (Note 29)

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

On behalf of the Board:

Russell K. Girling Director	Siim A. Vanaselja Director

116 TCPL Consolidated financial statements2015

Consolidated statement of equity

year ended December 31	2015		2014		2013
(millions of Canadian $)
Common Shares
Balance at beginning of year	16,320		15,205		14,306
Proceeds from shares issued (Note 19)	—		1,115		899
Balance at end of year	16,320		16,320		15,205
Preferred Shares
Balance at beginning of year	—		194		389
Redemption of preferred shares	—		(194	)	(195	)
Balance at end of year	—		—		194
Additional Paid-In Capital
Balance at beginning of year	404		431		400
Issuance of stock options, net of exercises	13		7		7
Dilution impact from TC PipeLines, LP units issued	6		9		29
Redemption of preferred shares	—		(6	)	(5	)
Impact of asset drop downs to TC PipeLines, LP (Note 25)	(213	)	(37	)	—
Balance at end of year	210		404		431
Retained Earnings
Balance at beginning of year	5,606		5,125		4,657
Net (loss)/income attributable to controlling interests	(1,146	)	1,843		1,789
Common share dividends	(1,471	)	(1,360	)	(1,301	)
Preferred share dividends	—		(2	)	(20	)
Balance at end of year	2,989		5,606		5,125
Accumulated Other Comprehensive Loss
Balance at beginning of year	(1,235	)	(934	)	(1,448	)
Other comprehensive income/(loss) (Note 21)	296		(301	)	514
Balance at end of year	(939	)	(1,235	)	(934	)
Equity Attributable to Controlling Interests	18,580		21,095		20,021
Equity Attributable to Non-Controlling Interests
Balance at beginning of year	1,583		1,417		1,036
Net (loss)/income attributable to non-controlling interests
TC PipeLines, LP	(13	)	136		93
Portland Natural Gas Transmission System	19		15		12
Other comprehensive income attributable to non-controlling interests	306		130		66
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs	55		79		384
Decrease in TCPL's ownership of TC PipeLines, LP	(11	)	(14	)	(47	)
Distributions declared to non-controlling interests	(222	)	(180	)	(146	)
Other	—		—		19
Balance at end of year	1,717		1,583		1,417
Total Equity	20,297		22,678		21,438

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

TCPL Consolidated financial statements2015117

Notes to consolidated financial statements

1.DESCRIPTION OF TCPL'S BUSINESS

TransCanada PipeLines Limited (TCPL or the Company) is a leading North American energy infrastructure company which operates in three business segments, Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services. The Company is a wholly-owned subsidiary of TransCanada Corporation (TransCanada).

Natural Gas Pipelines

The Natural Gas Pipelines segment consists of the Company's investments in 67,300 km (41,900 miles) of regulated natural gas pipelines and 250 Bcf of regulated natural gas storage facilities. These assets are located in Canada, the United States (U.S.) and Mexico.

Liquids Pipelines

The Liquids Pipelines segment consists of 4,247 km (2,639 miles) of wholly-owned and operated crude oil pipeline systems which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas.

Energy

The Energy segment primarily consists of the Company's investments in 19 electrical power generation plants and 2 non-regulated natural gas storage facilities. These include Canadian plants in Alberta, Ontario, Québec and New Brunswick and U.S. plants in New York, New England and Arizona.

2.  ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of TCPL and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-controlling interests. TCPL uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TCPL records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates and Judgments

In preparing these financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to:

• fair value and depreciation rates of plant, property and equipment (Note 7);

• carrying value of regulatory assets and liabilities (Note 9);

• fair value of goodwill (Note 10);

• amortization rates and fair value of intangible assets (Note 11);

• carrying value of asset retirement obligations (Note 14);

• provisions for income taxes (Note 15);

• assumptions used to measure retirement and other post-retirement obligations (Note 22);

• fair value of financial instruments (Note 23); and

• provision for commitments, contingencies and guarantees (Note 26).

Actual results could differ from those estimates.

118 TCPL Consolidated financial statements2015

Regulation

In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB). In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls.Rate-regulatedaccounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TCPL's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of its liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System as the regulators' decisions regarding operations and tolls on that system generally do not have an impact on timing of recognition of revenues and expenses.

Revenue Recognition

Natural Gas Pipelines and Liquids Pipelines

Revenues from the Company's natural gas and liquids pipelines, with the exception of Canadian natural gas pipelines which are subject to RRA, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made.

Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are at times subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved ROE assumptions. Adjustments to revenue are recorded when the NEB decision is received.

The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final.

Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas or oil that it transports or stores for others.

Energy

Power

Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative Instruments and Hedging Activities section of this note.

Natural Gas Storage

Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues.

TCPL Consolidated financial statements2015119

Cash and Cash Equivalents

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

Inventories

Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.

Plant, Property and Equipment

Natural Gas Pipelines

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

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

Liquids Pipelines

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

Energy

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

Corporate

Corporate Plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

120 TCPL Consolidated financial statements2015

Capitalized Project Costs

The Company capitalizes project costs once advancement to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest for non-regulated projects in development and AFUDC for regulated projects. Capital projects in development are included in Intangible and other assets. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's depreciation policies.

Project costs related to acquisitions are capitalized once the acquisition is probable.

Assets Held For Sale

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

Impairment of Long-Lived Assets

The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated price to sell is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the fair value of the asset.

Acquisitions and Goodwill

The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company initially assesses qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If TCPL concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value is less than carrying value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference.

Power Purchase Arrangements

A power purchase agreement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. Substantially all PPAs under which TCPL buys power are accounted for as operating leases. Initial payments for these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TCPL records the margin earned from the subleases as a component of Revenues.

Restricted Investments

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

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

TCPL Consolidated financial statements2015121

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, NGTL System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

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

Asset Retirement Obligations

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

The Company has recorded ARO related to the non-regulated natural gas storage operations and certain power generation facilities. The scope and timing of asset retirements related to natural gas pipelines, liquids pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities.

Environmental Liabilities

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

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

Stock Options and Other Compensation Programs

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

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

Employee Post-Retirement Benefits

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

122 TCPL Consolidated financial statements2015

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

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

Foreign Currency Transactions and Translation

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

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

Derivative Instruments and Hedging Activities

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

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

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

In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the amounts recognized previously in AOCI are reclassified to Revenues, Interest expense and Interest income and other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net income or as the original hedged item settles. Gains and losses on derivatives are reclassified

TCPL Consolidated financial statements2015123

immediately to Net income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.

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

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

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

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

Long-Term Debt Transaction Costs

The Company records Long-term debt transaction costs as other assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.

Guarantees

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

3. ACCOUNTING CHANGES

Changes in Accounting Policies for 2015

Derivatives and Hedging

In August 2015, the Financial Accounting Standards Board (FASB) issued new guidance on the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments in this update apply to entities that enter into contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through or delivery to a location within a nodal energy market whereby one of the contracting parties incurs charges (or credits) for the transmission of that electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. This new guidance was effective upon issuance, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Company elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Company’s process in determining deferred tax amounts and simplify their presentation. The application of this amendment resulted in a reclassification of Deferred tax assets previously recorded in Other current assets, and Deferred tax liabilities previously

124 TCPL Consolidated financial statements2015

recorded in Accounts payable and other to non-current Deferred income tax assets and liabilities. Prior year amounts have been reclassified to conform to current year presentation.

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance was applied prospectively from January 1, 2015 and there was no impact on the Company's consolidated financial statements as a result of applying this new standard.

Future Accounting Changes

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application.

The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from GAAP the concept of extraordinary items. This new guidance is effective from January 1, 2016 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Consolidation

In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Imputation of interest

In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in Intangible and other assets to an offset of their respective debt liabilities.

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify

that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable

value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and

transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Business Combinations

In September 2015, the FASB issued guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements as the adjustment

TCPL Consolidated financial statements2015125

was determined, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

4.SEGMENTED INFORMATION

year ended December 31, 2015	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	5,383		1,879		4,038		—		11,300
Income from equity investments	179		—		261		—		440
Plant operating costs and other	(1,736	)	(478	)	(766	)	(270	)	(3,250	)
Commodity purchases resold	—		—		(2,237	)	—		(2,237	)
Property taxes	(349	)	(79	)	(89	)	—		(517	)
Depreciation and amortization	(1,132	)	(266	)	(336	)	(31	)	(1,765	)
Asset impairment charges	—		(3,686	)	(59	)	—		(3,745	)
Loss on assets held for sale	(125	)	—		—		—		(125	)
Segmented earnings/(losses)	2,220		(2,630	)	812		(301	)	101
Interest expense									(1,398	)
Interest income and other									192
Loss before income taxes									(1,105	)
Income tax expense									(35	)
Net loss									(1,140	)
Net income attributable to non-controlling interests									(6	)
Net loss attributable to controlling interests									(1,146	)
Preferred share dividends									—
Net loss attributable to common shares									(1,146	)
Capital spending
Capital expenditures	2,466		1,012		376		64		3,918
Capital projects in development	233		278		—		—		511
	2,699		1,290		376		64		4,429

126 TCPL Consolidated financial statements2015

year ended December 31, 2014	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	4,913		1,547		3,725		—		10,185
Income from equity investments	163		—		359		—		522
Plant operating costs and other	(1,501	)	(426	)	(919	)	(127	)	(2,973	)
Commodity purchases resold	—		—		(1,836	)	—		(1,836	)
Property taxes	(334	)	(62	)	(77	)	—		(473	)
Depreciation and amortization	(1,063	)	(216	)	(309	)	(23	)	(1,611	)
Gain on assets sold	9		—		108		—		117
Segmented earnings/(losses)	2,187		843		1,051		(150	)	3,931
Interest expense									(1,235	)
Interest income and other									128
Income before income taxes									2,824
Income tax expense									(830	)
Net income									1,994
Net income attributable to non-controlling interests									(151	)
Net income attributable to controlling interests									1,843
Preferred share dividends									(2	)
Net income attributable to common shares									1,841
Capital spending
Capital expenditures	1,768		1,469		206		46		3,489
Capital projects in development	368		480		—		—		848
	2,136		1,949		206		46		4,337

TCPL Consolidated financial statements2015127

year ended December 31, 2013	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	4,497		1,124		3,176		—		8,797
Income from equity investments	145		—		452		—		597
Plant operating costs and other	(1,405	)	(328	)	(833	)	(108	)	(2,674	)
Commodity purchases resold	—		—		(1,317	)	—		(1,317	)
Property taxes	(329	)	(44	)	(72	)	—		(445	)
Depreciation and amortization	(1,027	)	(149	)	(293	)	(16	)	(1,485	)
Segmented earnings/(losses)	1,881		603		1,113		(124	)	3,473
Interest expense									(1,046	)
Interest income and other									72
Income before income taxes									2,499
Income tax expense									(605	)
Net income									1,894
Net income attributable to non-controlling interests									(105	)
Net income attributable to controlling interests									1,789
Preferred share dividends									(20	)
Net income attributable to common shares									1,769
Capital spending
Capital expenditures	1,776		2,286		152		50		4,264
Capital projects in development	245		243		—		—		488
	2,021		2,529		152		50		4,752

128 TCPL Consolidated financial statements2015

at December 31	2015	2014
(millions of Canadian $)
Total Assets
Natural Gas Pipelines	31,072	27,103
Liquids Pipelines	16,046	16,116
Energy	15,558	14,197
Corporate	4,253	3,999
	66,929	61,415

Geographic Information

year ended December 31	2015	2014	2013
(millions of Canadian $)
Revenues
Canada – domestic	3,877	3,956	4,659
Canada – export	1,292	1,314	997
United States	5,872	4,718	3,029
Mexico	259	197	112
	11,300	10,185	8,797

at December 31	2015	2014
(millions of Canadian $)
Plant, Property and Equipment
Canada	19,287	19,191
United States	21,899	20,098
Mexico	3,631	2,485
	44,817	41,774

TCPL Consolidated financial statements2015129

5. OTHER CURRENT ASSETS

at December 31		2014
(millions of Canadian $)	2015
Cash held as collateral	585	423
Fair value of derivative contracts (Note 23)	442	409
Regulatory assets (Note 9)	85	16
Assets held for sale (Note 6)	20	—
Other	221	170
	1,353	1,018

6.ASSETS HELD FOR SALE

On December 18, 2015, the Company entered into an agreement to sell TC Offshore LLC (TCO) to a third party and expects the sale to close in early 2016. As a result, at December 31, 2015, the related assets and liabilities were held for sale in the Natural Gas Pipelines segment and were recorded at their fair values less costs to sell. This resulted in a loss of $125 million pre-tax in 2015 which is included in (Loss)/gain on assets held for sale/sold in the Consolidated statement of income. TCO is a FERC regulated entity that operates as part of ANR. TCO does not represent a major line of business or geographical area of the Company, and therefore is not considered to be a discontinued operation as of December 31, 2015.

at December 31	2015
(millions of Canadian $)
Assets Held for Sale
Accounts receivable	4
Inventories	1
Other current assets	1
Plant, property and equipment	14
Total Assets Held for Sale (included in Other current assets, Note 5)	20
Liabilities Related to Assets Held for Sale
Accounts payable and other	38
Other long-term liabilities	1
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13)	39

130 TCPL Consolidated financial statements2015

7. PLANT, PROPERTY AND EQUIPMENT

	2015			2014
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)
Natural Gas Pipelines
Canadian Mainline
Pipeline	9,164	5,966	3,198	9,045	5,712	3,333
Compression	3,433	2,220	1,213	3,423	2,100	1,323
Metering and other	499	192	307	458	180	278
	13,096	8,378	4,718	12,926	7,992	4,934
Under construction	257	—	257	135	—	135
	13,353	8,378	4,975	13,061	7,992	5,069
NGTL System
Pipeline	8,456	3,820	4,636	8,185	3,619	4,566
Compression	2,188	1,404	784	2,055	1,318	737
Metering and other	1,096	489	607	1,032	446	586
	11,740	5,713	6,027	11,272	5,383	5,889
Under construction	969	—	969	413	—	413
	12,709	5,713	6,996	11,685	5,383	6,302
ANR1
Pipeline	1,449	350	1,099	1,217	227	990
Compression	1,101	187	914	780	140	640
Metering and other	977	252	725	737	231	506
	3,527	789	2,738	2,734	598	2,136
Under construction	304	—	304	127	—	127
	3,831	789	3,042	2,861	598	2,263
Mexico
Pipeline	1,296	162	1,134	1,053	104	949
Compression	183	14	169	151	6	145
Metering and other	388	27	361	314	20	294
	1,867	203	1,664	1,518	130	1,388
Under construction	1,959	—	1,959	1,098	—	1,098
	3,826	203	3,623	2,616	130	2,486
Other Natural Gas Pipelines
GTN	2,278	765	1,513	1,842	588	1,254
Great Lakes	2,157	1,155	1,002	1,807	939	868
Foothills	1,606	1,162	444	1,671	1,180	491
Other2	2,223	572	1,651	1,800	363	1,437
	8,264	3,654	4,610	7,120	3,070	4,050
Under construction	71	—	71	34	—	34
	8,335	3,654	4,681	7,154	3,070	4,084
	42,054	18,737	23,317	37,377	17,173	20,204

TCPL Consolidated financial statements2015131

Liquids Pipelines
Keystone
Pipeline	9,288	718	8,570	7,931	463	7,468
Pumping equipment	1,092	108	984	964	80	884
Tanks and other	3,034	228	2,806	2,282	144	2,138
	13,414	1,054	12,360	11,177	687	10,490
Under construction	1,826	—	1,826	4,438	—	4,438
	15,240	1,054	14,186	15,615	687	14,928
Energy
Natural Gas – Ravenswood	2,607	654	1,953	2,140	476	1,664
Natural Gas – Other3,4	3,361	1,164	2,197	3,214	971	2,243
Hydro, Wind and Solar5	2,417	476	1,941	2,194	359	1,835
Natural Gas Storage and Other	740	132	608	717	118	599
	9,125	2,426	6,699	8,265	1,924	6,341
Under construction	430	—	430	149	—	149
	9,555	2,426	7,129	8,414	1,924	6,490
Corporate	267	82	185	232	80	152
	67,116	22,299	44,817	61,638	19,864	41,774

¹  TCO is excluded from the ANR net book value at December 31, 2015 as it has been classified as an asset held for sale. Refer to Note 6 for further information.

²  Includes Bison, Portland Natural Gas Transmission System (PNGTS), North Baja, Tuscarora and Ventures LP.

³  Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $813 million and $142 million, respectively, at December 31, 2015 (2014 – $695 million and $103 million, respectively). Revenues of $93 million were recognized in 2015 (2014 – $81 million; 2013 – $78 million) through the sale of electricity under the related PPAs.

⁴  Includes Halton Hills, Coolidge, Bécancour, Ocean State Power, Mackay River and other natural gas-fired facilities.

⁵  Includes the acquisitions of four solar power facilities in 2014.

Keystone XL Impairment

At December 31, 2015, the Company evaluated its investment in Keystone XL and related projects, including the Keystone Hardisty Terminal (KHT), for impairment in connection with the November 6, 2015 denial of the U.S. Presidential permit. As a result of the analysis, the Company recognized a non-cash impairment charge of $3,686 million ($2,891 million after-tax) based on the excess of the carrying value over the estimated fair value of $621 million of these assets. The impairment charge includes $77 million ($56 million after-tax) for certain cancellation fees that will be incurred in the future if the project is ultimately abandoned.

at December 31, 2015	Estimated	Impairment charge
(millions of Canadian $)	Fair Value	Pre-tax	After-tax
Plant and equipment	463	1,460	1,391
Terminals, including KHT	158	274	219
Intangible assets	—	1,150	737
Capitalized interest	—	725	488
Future cancellation costs	—	77	56
	621	3,686	2,891

The estimated fair value of $463 million related to plant and equipment was based on the price that would be received on sale of the plant and equipment in its current condition. An independent third party valuation was utilized in the assessment of the fair value of these assets. Key assumptions used in the determination of selling price included an estimated two year disposal period and the current weak energy market conditions. The valuation considered a variety of potential selling prices that were based on the various markets that could be used in order to dispose of these assets.

The estimated $158 million fair value of the terminal assets, including KHT, was determined using a discounted cash flow approach as a measure of fair value. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. 

132 TCPL Consolidated financial statements2015

The valuation techniques above required the use of unobservable inputs. As a result, the fair value is classified within Level 3 of the fair value hierarchy. Refer to Note 23 for further information on the fair value hierarchy.

Energy Turbine Impairment

Following the evaluation of specific capital project opportunities in 2015, it was determined that the carrying value of certain Energy turbine equipment was not fully recoverable. These turbines had been previously purchased for a power development project that did not proceed. As a result, at December 31, 2015, the Company recognized a non-cash impairment charge of $59 million ($43 million after-tax). This impairment charge was based on the excess of the carrying value over the fair value of the turbines, which was determined based on a comparison to similar assets available for sale in the market.

8. EQUITY INVESTMENTS

(millions of Canadian $)	Ownership   Interest at   December 31, 2015		Income / (Loss) from Equity Investments				Equity Investments
			year ended December 31				at December 31
			2015		2014	2013	2015	2014
Natural Gas Pipelines
Northern Border1,2			85		76	66	664	587
Iroquois	44.5	%	51		43	41	238	210
TQM	50.0	%	12		12	13	72	73
Other	Various		31		32	25	73	68
Liquids Pipelines
Grand Rapids	50.0	%	—		—	—	542	240
Canaport Energy East Marine Terminal	50.0	%	—		—	—	16	—
Energy
Bruce Power3,4	48.5	%	249		314	310	4,200	3,995
ASTC Power Partnership	50.0	%	(23	)	8	110	21	29
Portlands Energy	50.0	%	30		36	31	321	335
Other	Various		5		1	1	67	61
			440		522	597	6,214	5,598

¹  The results reflect a 50.0 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2015, TCPL had an ownership interest in TC PipeLines, LP of 28.0 per cent (2014 – 28.3 and 2013 – 28.9 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.0 per cent (2014 – 14.2 and 2013 – 14.5 per cent).

²  At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$117 million (2014 – US$117 million) due to the fair value assessment of assets at the time of acquisition.

³  As a result of TCPL's increased ownership in Bruce Power L.P. (Bruce B) and the merger of Bruce Power A L.P. (Bruce A) and Bruce B (to form Bruce Power) in December 2015, TCPL has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TCPL applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TCPL continues to apply equity accounting to Bruce Power. Refer to Note 25 for further information.

⁴  At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $973 million (2014 – $776 million) due to the fair value assessment of assets at the time of acquisitions.

Distributions received from equity investments for the year ended December 31, 2015 were $802 million (2014 – $738 million; 2013 – $733 million) of which $226 million (2014 – $159 million; 2013 – $128 million) were returns of capital and are included in Investing activities in the Consolidated statement of cash flows. The undistributed earnings from equity investments as at December 31, 2015 were $198 million (2014 – $551 million; 2013 – $754 million).

Contributions made to equity investments for the year ended December 31, 2015 were $493 million (2014 – $256 million; 2013 –$163 million) and are included in Equity investments in the Consolidated statement of cash flows.

TCPL Consolidated financial statements2015133

Summarized Financial Information of Equity Investments

year ended December 31	2015		2014		2013
(millions of Canadian $)
Income
Revenues	4,337		4,814		4,989
Operating and other expenses	(3,254	)	(3,489	)	(3,536	)
Net income	1,046		1,264		1,390
Net income attributable to TCPL	440		522		597

at December 31	2015		2014
(millions of Canadian $)
Balance Sheet
Current assets	1,530		1,412
Non-current assets	13,190		12,260
Current liabilities	(1,370	)	(1,067	)
Non-current liabilities	(3,116	)	(3,255	)

9.RATE-REGULATED BUSINESSES

TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain Canadian liquids pipelines currently in development. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities.

Canadian Regulated Operations

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

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

Canadian Mainline

In March 2015, TCPL filed a compliance filing with the NEB in response to the RH-001-2014 Decision on TCPL's 2015-2030 Tolls Application (the NEB 2014 Decision) and is required to file a toll review for the 2018 to 2020 period prior to December 31, 2017. In June 2015, the NEB approved the applied-for compliance tolls as filed and these tolls became effective on July 1, 2015.

The NEB's 2014 Decision acknowledged that an off-ramp had been reached on the NEB 2013 Decision (described below) and approved fixed tolls for 2015 to 2020 as well as certain parameters for a toll setting methodology to 2030. Features of the settlement reached with shippers as approved in the NEB 2014 Decision include an ROE of 10.1 per cent on deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TCPL contribution to reduce the revenue requirement. Toll stabilization is achieved through the continued use of deferral accounts, namely the Long-term adjustment account (LTAA) and the Bridging amortization account, to capture the surplus or the shortfall between the Company's revenues and cost of service for each year over the six-year fixed toll term of the NEB 2014 Decision.

134 TCPL Consolidated financial statements2015

In March 2013, the Company received a decision from the NEB which set tolls for 2013 through 2017 at competitive levels, fixing tolls for some services and providing unlimited pricing discretion for others (the NEB 2013 Decision). The decision established an ROE of 11.5 per cent on deemed common equity of 40 per cent and included mechanisms to achieve the fixed tolls through the use of a LTAA as well as the establishment of a Tolls Stabilization Account (TSA) to capture the surplus or the shortfall between revenues and cost of service for each year over the five-year term of the decision. In addition, the decision provided an opportunity to generate incentive earnings by increasing revenues and reducing costs. The NEB also identified certain circumstances that would require a new tolls application prior to the end of the five-year term. One of those circumstances occurred in 2013 when the TSA balance became positive. In December 2013, TCPL filed the 2015-2030 Tolls Application with the NEB that addressed tolls moving forward including continuation of the NEB 2013 Decision tolls for 2014.

NGTL System

In February 2015, the NEB approved the NGTL System’s 2015 Revenue Requirement Settlement. The terms of the one year settlement include ROE of 10.1 per cent on 40 per cent deemed equity, a continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount that was based on an escalation of 2014 actual costs.

The NGTL System’s 2014 results reflect the terms of the 2013-2014 Revenue Requirement Settlement Application. This settlement had fixed annual OM&A costs and a 10.1 per cent ROE on deemed common equity of 40 per cent. Any variance between fixed OM&A costs in the settlement and actual costs accrued to TCPL. The settlement also included a composite depreciation rate of 3.12 per cent in 2014.

Energy East

Energy East is currently in the development stage, awaiting regulatory approval from the NEB. Tolls will be designed to provide for cost recovery including return of and on capital as approved by the NEB.

Other Canadian Pipelines

The Foothills operating model for 2014 and 2015 provides for recovery of all revenue requirement components on a flow-through basis. TQM operates under a model consisting of fixed and flow-through revenue requirement components for 2014 through 2016. Any variances between actual costs and those included in the fixed component accrue to TQM.

U.S. Regulated Operations

TCPL's U.S. natural gas pipelines are "natural gas companies" operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.

ANR

ANR's natural gas transportation and storage services are provided under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and allow ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC that was effective for all periods presented, beginning in 1997. On January 29, 2016, ANR Pipeline Company filed an application with the FERC under section 4 of the NGA to establish new rates expected to be effective, subject to refund, on August 1, 2016.

ANR Storage Company rates were established pursuant to a settlement approved by the FERC in August 2012 and ANR Storage Company is required to file for new rates to be effective no later than July 1, 2016.

TCO, another ANR-related regulated entity, began operating under FERC-approved tariff rates on November 1, 2012. As at December 31, 2015, TCO assets were classified as Assets held for sale. Refer to Note 6 for more information.

Other U.S. Natural Gas Pipelines

GTN, Great Lakes and Bison are regulated by the FERC and operate in accordance with FERC-approved tariffs that establish maximum and minimum rates for various services. Each pipeline is permitted to discount or negotiate these rates on a non-discriminatory basis.

TCPL Consolidated financial statements2015135

GTN’s rates were established pursuant to a settlement approved by the FERC in January 2012. On June 30, 2015, FERC approved GTN’s new settlement with its shippers which satisfies GTN’s obligations from the 2012 settlement for new rates to be in effect on January 1, 2016, and reduced rates on the mainline by three per cent on July 1, 2015.  In January 2016, GTN’s rates will decrease a further 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN’s rates will decrease an additional eight per cent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates. 

Great Lakes operates under rates established pursuant to a settlement approved by the FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

Bison continues to operate under the rates approved by FERC in connection with Bison's initial construction and has no requirement to file a new rate proceeding.

Mexico Regulated Operations

TCPL's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. In 2014, TCPL began using RRA for all natural gas pipelines in Mexico. The rates were established based on CRE approved negotiated contracts.

Regulatory Assets and Liabilities

at December 31	2015	2014	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)
Regulatory Assets
Deferred income taxes1	848	1,001	n/a
Operating and debt-service regulatory assets2	47	4	1
Pensions and other post retirement benefits3	210	236	n/a
Foreign exchange on long-term debt5	54	—	1-14
Other4	110	72	n/a
	1,269	1,313
Less: Current portion included in Other current assets (Note 5)	85	16
	1,184	1,297
Regulatory Liabilities
Foreign exchange on long-term debt5	—	42	1-14
Operating and debt-service regulatory liabilities2	32	21	1
ANR-related post-employment and retirement benefits other than pension6	147	117	n/a
Long term adjustment account7	231	64	45
Pipeline abandonment costs8	285	—	n/a
Bridging amortization account9	456	—	15
Other4	52	49	n/a
	1,203	293
Less: Current portion included in Accounts payable and other (Note 13)	44	30
	1,159	263

¹  These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.

²  Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. Pre-tax operating results in 2015 would have been $32 million lower (2014 – $28 million higher; 2013 – $76 million lower) had these amounts not been recorded as Regulatory assets and liabilities.

³  These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. The balances are excluded from the rate base and do not earn a return on investment. Pre-tax operating results in 2015 would have been $26 million higher (2014 – $46 million lower; 2013 – $171 million higher) had these amounts not been recorded as regulatory assets and liabilities.

136 TCPL Consolidated financial statements2015

⁴  Pre-tax operating results in 2015 would have been $35 million lower (2014 – $2 million higher; 2013 – $2 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁵  Foreign exchange on long-term debt of the NGTL System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, GAAP would have required the inclusion of these unrealized gains or losses in Net income.

⁶  Under the terms of ANR’s last rate settlement, ANR will be required to make refunds to its customers, pursuant to a refund plan to be approved by FERC in a future rate proceeding, of those amounts in the post-retirement benefit trust fund that have not been used to pay benefits to its employees. This regulatory liability represents the difference between the amount collected in rates and the amount of post-retirement benefits expense. ANR anticipates that the resolution of this liability will be determined through the section 4 rate case ANR filed with the FERC on January 29, 2016.  Since the timing of the rate case conclusion is uncertain, a settlement period cannot be determined at this time. Pre-tax operating results in 2015 would have been $30 million higher (2014 – $13 million higher; 2013 – $16 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁷  Pre-tax operating results in 2015 would have been $167 million higher (2014 – $418 million higher; 2013 – $247 million lower) had these amounts not been recorded as regulatory liabilities.

⁸  Effective January 1, 2015, NEB regulated pipelines including the Mainline, NGTL System, Foothills, Keystone and TQM are required to collect and set-aside funds received from customers to be used for future pipeline abandonment activities. Funds are collected through a surcharge mechanism, set-aside in trust accounts, and the obligation to use these funds for future pipeline abandonment activities is recorded as a regulatory liability. Pre-tax operating results in 2015 would have been $285 million higher (2014 –nil; 2013 –nil) had these amounts not been recorded as regulatory liabilities.

⁹  Pre-tax operating results in 2015 would have been $456 million higher (2014 – nil; 2013 –nil) had these amounts not been recorded as regulatory liabilities.

Allowance for Funds Used During Construction

The total amount of debt and equity AFUDC included in the Consolidated statement of income was $295 million in 2015 (2014 – $136 million; 2013 – $37 million).

10.GOODWILL

The Company has recorded the following Goodwill on its acquisitions in the U.S.:

(millions of Canadian $)	Natural Gas Pipelines	Energy	Total
Balance at January 1, 2014	2,816	880	3,696
Foreign exchange rate changes	258	80	338
Balance at December 31, 2014	3,074	960	4,034
Foreign exchange rate changes	593	185	778
Balance at December 31, 2015	3,667	1,145	4,812

At December 31, 2015, TCPL’s Goodwill included US$573 million (2014 - US$573 million) related to the Great Lakes natural gas transportation business. TCPL's share of this Goodwill (net of non-controlling interests) was US$386 million (2014 – US$243 million). The increase in TCPL's share is a result of the impairment charge of US$199 million recorded by TC PipeLines, LP on its equity method goodwill related to Great Lakes. On a consolidated basis, TCPL’s carrying value of its investment in Great Lakes is proportionately lower compared to the 46.45% owned through TC PipeLines, LP. As a result, the estimated fair value of Great Lakes exceeded TCPL's consolidated carrying value of the investment and no impairment was recorded in 2015.

The estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. The fair value of this reporting unit was measured by using a discounted cash flow analysis. Assumptions regarding Great Lakes’ ability to realize long-term value in the North American energy market have been adversely impacted by the changing natural gas flows in its market region as well as a change in the Company's view of other strategic alternatives to increase utilization of Great Lakes. As a result, the Company reduced forecasted cash flows from the reporting unit for the next ten years as compared to those utilized in previous impairment tests. There is a risk that continued reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of a portion of the Goodwill balance relating to Great Lakes.

TCPL Consolidated financial statements2015137

11.INTANGIBLE AND OTHER ASSETS

at December 31	2015	2014
(millions of Canadian $)
Capital projects in development	1,814	1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances1	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	9	181
Other	797	628
	3,185	2,641

¹  TCPL held a note receivable from the seller of Ravenswood of $213 million (US$154 million) and $213 million (US$184 million) as at December 31, 2015 and at December 31, 2014, which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other current assets was $55 million (US$40 million) at December 31, 2015 and $46 million (US$40 million) at December 31, 2014.

The following amounts related to PPAs are included in Intangible and other assets:

	2015			2014
at December 31	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
(millions of Canadian $)
Sheerness (expires 2020)	585	390	195	585	351	234
Sundance A (expires 2017)	225	200	25	225	187	38
	810	590	220	810	538	272

Amortization expense for these PPAs was $52 million for the year ended December 31, 2015 (2014 and 2013 – $52 million). The expected annual amortization expense for 2016 and 2017 is $52 million, and $39 million for 2018 to 2020.

12.NOTES PAYABLE

	2015			2014
(millions of Canadian $, unless otherwise noted)	Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31
Canadian	697	0.8	%	1,540	1.2	%
U.S. (2015 – US$376; 2014 – US$800)	521	1.1	%	927	0.7	%
	1,218			2,467

At December 31, 2015, Notes payable consists of commercial paper issued by TCPL, TransCanada American Investments Ltd. (TAIL), and TransCanada Power Marketing Ltd. (TCPM). In November 2015, the TAIL credit facility was increased to US$1.5 billion from US$1.0 billion and, subsequently, TAIL and TCPM became co-borrowers under the facility and co-issuers under the related commercial paper program. At the same time, the TCPL USA credit facility was reduced from the US$1.0 billion to US$0.5 billion. In December 2015, a new US$1.0 billion credit facility and related commercial paper program was initiated for TCPL.

At December 31, 2015, total committed revolving and demand credit facilities of $8.9 billion (2014 – $6.7 billion) were available. When drawn, interest on these lines of credit is charged at prime rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

138 TCPL Consolidated financial statements2015

					year ended December 31
at December 31, 2015					2015	2014	2013
Amount	Unused Capacity	Borrower	Description	Matures	Cost to maintain
					(millions of Canadian $)
$3 billion	$3 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2020	6	6	4
US$1 billion	US$1 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2016	—	—	—
US$0.5 billion	US$0.5 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL	December 2016	3	2	1
US$1.5 billion	US$1.5 billion	TAIL/TCPM	Committed, syndicated, revolving, extendible TAIL/TCPM credit facility, guaranteed by TCPL	December 2016	2	1	—
$1.7 billion	$0.7 billion	TCPL/TCPL USA	Supports the issuance of letters of credit and provides additional liquidity	Demand	—	—	—

At December 31, 2015, the Company's operated affiliates had an additional $0.6 billion (2014 – $0.4 billion) of undrawn capacity on committed credit facilities.

13.ACCOUNTS PAYABLE AND OTHER

at December 31	2015	2014
(millions of Canadian $)
Trade payables	1,506	1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	370	345
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39	—
Other	129	143
	3,014	2,891

14.OTHER LONG-TERM LIABILITIES

at December 31	2015	2014
(millions of Canadian $)
Fair value of derivative contracts (Note 23)	625	411
Employee post-retirement benefits (Note 22)	380	444
Asset retirement obligations	109	98
Guarantees (Note 26)	26	20
Other	120	79
	1,260	1,052

TCPL Consolidated financial statements2015139

15. INCOME TAXES

Provision for Income Taxes

year ended December 31	2015		2014	2013
(millions of Canadian $)
Current
Canada	45		104	27
Foreign	92		42	16
	137		146	43
Deferred
Canada	33		307	239
Foreign	(135	)	377	323
	(102	)	684	562
Income Tax Expense	35		830	605

Geographic Components of Income

year ended December 31	2015		2014	2013
(millions of Canadian $)
Canada	(623	)	1,146	1,201
Foreign	(482	)	1,678	1,298
(Loss)/Income Before Income Taxes	(1,105	)	2,824	2,499

Reconciliation of Income Tax Expense

year ended December 31	2015		2014		2013
(millions of Canadian $)
(Loss)/Income before income taxes	(1,105	)	2,824		2,499
Federal and provincial statutory tax rate	26.0	%	25.0	%	25.0	%
Expected income tax (recovery)/expense	(287	)	706		625
Income tax differential related to regulated operations	159		129		(13	)
Higher effective foreign tax rates	14		25		33
Income from equity investments and non-controlling interests	(56	)	(38	)	(28	)
Tax rate and legislative changes	34		—		(25	)
Asset impairment charges1	170		—		—
Other	1		8		13
Actual Income Tax Expense	35		830		605

¹  The asset impairment impact is net of $311 million attributed to higher foreign tax rates.

140 TCPL Consolidated financial statements2015

Deferred Income Tax Assets and Liabilities

at December 31	2015	2014
(millions of Canadian $)
Deferred Income Tax Assets
Difference in accounting and tax bases of impaired assets	916	—
Tax loss and credit carryforwards	1,325	1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	132	146
	3,304	1,970
Less: Valuation allowance1	1,060	125
	2,244	1,845
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,441	5,548
Equity investments	656	648
Taxes on future revenue requirement	227	253
Other	55	71
	7,379	6,520
Net Deferred Income Tax Liabilities	5,135	4,675

¹  In 2015, an increase to the valuation allowance of $935 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt and unrealized losses on certain impaired assets will not be realized in the future.

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

at December 31	2015	20141
(millions of Canadian $)
Deferred Income Tax Assets
Intangible and other assets (Note 11)	9	181
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,856
Net Deferred Income Tax Liabilities	5,135	4,675

¹  As a result of retrospectively applying guidance on the presentation of deferred taxes on the Consolidated balance sheet on January 1, 2015, the Company reclassified its December 31, 2014 current Deferred income tax assets of $427 million, and current Deferred income tax liabilities of $4 million to its non-current Deferred income tax assets and liabilities.

At December 31, 2015, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,276 million (2014 – $1,131 million) for federal and provincial purposes in Canada, which expire from 2026 to 2035. The Company also has Ontario minimum tax credits of $57 million (2014 – $50 million), which expire from 2016 to 2035.

At December 31, 2015, the Company has recognized the benefit of unused net operating loss carryforwards of US$1,617 million (2014 – US$2,267 million) for federal purposes in the U.S., which expire from 2029 to 2034. The Company also has alternative minimum tax credits of US$41 million (2014 – US$26 million).

Unremitted Earnings of Foreign Investments

Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2015 by approximately$308 million (2014 – $236 million) if there had been a provision for these taxes.

TCPL Consolidated financial statements2015141

Income Tax Payments

Income tax payments of $164 million, net of refunds, were made in 2015 (2014 – payments, net of refunds, of $109 million; 2013 – payments, net of refunds, of $206 million).

Reconciliation of Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:

at December 31	2015		2014		2013
(millions of Canadian $)
Unrecognized tax benefit at beginning of year	13		19		45
Gross increases – tax positions in prior years	2		2		3
Gross decreases – tax positions in prior years	(2	)	(8	)	(28	)
Gross increases – tax positions in current year	1		1		2
Lapses of statute of limitations	(1	)	(1	)	(3	)
Unrecognized Tax Benefit at End of Year	13		13		19

TCPL recognized a favourable income tax adjustment of approximately $25 million due to the enactment of certain Canadian federal tax legislation in June 2013.

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

TCPL and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2007. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2010.

TCPL's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax expense for the year ended December 31, 2015 reflects a $1 million reversal of Interest expense and nil for penalties (2014 – nil for Interest expense and nil for penalties; 2013 – nil for Interest expense and nil for penalties). At December 31, 2015, the Company had $4 million accrued for Interest expense and nil accrued for penalties (December 31, 2014 –$5 million accrued for Interest expense and nil accrued for penalties).

142 TCPL Consolidated financial statements2015

16.LONG-TERM DEBT

		2015			2014
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate1		Outstanding at December 31	Interest Rate1
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
Debentures
Canadian	2017 to 2020	599	10.7	%	749	10.9	%
U.S. (2015 and 2014 – US$400)	2021	554	9.9	%	464	9.9	%
Medium-Term Notes
Canadian	2016 to 2041	5,192	5.3	%	4,048	5.7	%
Senior Unsecured Notes
U.S. (2015 – US$14,723; 2014 – US$13,526)	2016 to 2045	20,340	4.8	%	15,655	5.0	%
		26,685			20,916
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian2	2016 to 2024	325	11.5	%	325	11.5	%
U.S. (2015 and 2014 – US$200)	2023	277	7.9	%	232	7.9	%
Medium-Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2015 and 2014 – US$33)	2026	45	7.5	%	38	7.5	%
		1,151			1,099
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2015 and 2014 – US$432)	2021 to 2025	598	8.9	%	502	8.9	%
GAS TRANSMISSION NORTHWEST LLC
Unsecured Term Loan
U.S. (2015 – US$75)	2019	104	1.4	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$250; 2014 – US$325)	2020 to 2035	346	5.6	%	377	5.5	%
		450			377
TC PIPELINES, LP
Unsecured Loan
U.S. (2015 – US$200; 2014 – US$330)	2017	277	1.6	%	383	1.4	%
Unsecured Term Loan Facility
U.S. (2015 and 2014 – US$500)	2018	692	1.6	%	580	1.4	%
Unsecured Term Loan
U.S. (2015 – US$170)	2018	235	1.6	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$698; 2014 – US$350)	2021 to 2025	967	4.7	%	405	4.7	%
		2,171			1,368
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2015 – US$297; 2014 – US$316)	2018 to 2030	411	7.8	%	367	7.8	%

TCPL Consolidated financial statements2015143

TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. (2015 – US$16; 2014 – US$20)	2017	22	4.0	%	23	4.0	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes3
U.S. (2015 – US$69; 2014 – US$90)	2018	96	6.1	%	105	6.1	%
		31,584			24,757
Less: Current portion of Long-term debt		2,547			1,797
		29,037			22,960

¹  Interest rates are the effective interest rates except for those pertaining to Long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.

²  Debentures issued by NGTL in the amount of $225 million have retraction provisions that entitle the holders to periodically require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made in 2015 or 2014.

³  Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

Principal Repayments

At December 31, 2015, principal repayments on the Long-term debt of the Company for the next five years are approximately as follows:

(millions of Canadian $)	2016	2017	2018	2019	2020
Principal repayments on Long-term debt	2,547	2,150	3,379	1,228	1,801

Long-Term Debt Issued

The Company issued Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)
Company	Issue date	Type	Maturity date	Amount	Interest Rate
TRANSCANADA PIPELINES LIMITED
	November 2015	Senior Unsecured Notes	November 2017	US 1,000	1.625	%
	October 2015	Medium-Term Notes	November 2041	400	4.55	%
	July 2015	Medium-Term Notes	July 2025	750	3.30	%
	March 2015	Senior Unsecured Notes	March 2045	US 750	4.60	%
	January 2015	Senior Unsecured Notes	January 2018	US 500	1.875	%
	January 2015	Senior Unsecured Notes	January 2018	US 250	Floating
	February 2014	Senior Unsecured Notes	March 2034	US 1,250	4.63	%
	October 2013	Senior Unsecured Notes	October 2023	US 625	3.75	%
	October 2013	Senior Unsecured Notes	October 2043	US 625	5.00	%
	July 2013	Senior Unsecured Notes	June 2016	US 500	Floating
	July 2013	Medium-Term Notes	July 2023	450	3.69	%
	July 2013	Medium-Term Notes	November 2041	300	4.55	%
	January 2013	Senior Unsecured Notes	January 2016	US 750	0.75	%
TC PIPELINES, LP
	September 2015	Unsecured Term Loan	October 2018	US 170	Floating
	March 2015	Senior Unsecured Notes	March 2025	US 350	4.375	%
	July 2013	Unsecured Term Loan Facility	July 2018	US 500	Floating
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Unsecured Term Loan	June 2019	US 75	Floating

144 TCPL Consolidated financial statements2015

Long-Term Debt Retired

The Company retired Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)
Company	Retirement date	Type	Amount	Interest Rate
TRANSCANADA PIPELINES LIMITED
	August 2015	Debentures	150	11.90	%
	June 2015	Senior Unsecured Notes	US 500	3.40	%
	March 2015	Senior Unsecured Notes	US 500	0.875	%
	January 2015	Senior Unsecured Notes	US 300	4.875	%
	June 2014	Debentures	125	11.10	%
	February 2014	Medium-Term Notes	300	5.05	%
	January 2014	Medium-Term Notes	450	5.65	%
	August 2013	Senior Unsecured Notes	US 500	5.05	%
	June 2013	Senior Unsecured Notes	US 350	4.00	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Senior Unsecured Notes	US 75	5.09	%
NOVA GAS TRANSMISSION LTD.
	June 2014	Debentures	53	11.20	%

Interest Expense

Interest expense over the three years ended December 31 was as follows:

year ended December 31	2015		2014		2013
(millions of Canadian $)
Interest on Long-term debt	1,487		1,317		1,216
Interest on Junior subordinated notes (Note 17)	116		70		65
Interest on short-term debt	44		52		73
Capitalized interest	(280	)	(259	)	(287	)
Amortization and other financial charges1	31		55		(21	)
	1,398		1,235		1,046

¹  Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates.

The Company made interest payments of $1,295 million in 2015 (2014 – $1,160 million; 2013 – $1,047 million) on Long-term debt, Junior subordinated notes and Notes payable, net of interest capitalized.

TCPL Consolidated financial statements2015145

17.JUNIOR SUBORDINATED NOTES

		2015			2014
Outstanding loan amount	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
U.S. (2015 and 2014 – US$1,000)1	2067	1,384	6.4	%	1,160	6.5	%
U.S. (2015 – US$750)1	2075	1,038	5.3	%	—	—
		2,422			1,160

¹  The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL.

Junior subordinated notes of US$1.0 billion mature in May 2067 and bear interest at 6.35 per cent per annum until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 2.21 per cent. The Company has the option to defer payment of interest for periods of up to 10 years without giving rise to a default or permitting acceleration of payment under the terms of the Junior subordinated notes, however, the Company would be prohibited from paying dividends during any such deferral period. The Junior subordinated notes are callable at the Company's option at any time on or after May 15, 2017 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. The Junior subordinated notes are callable earlier, in whole or in part, upon the occurrence of certain events and at the Company's option at an amount equal to the greater of 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with their terms.

In May 2015, TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors at a fixed interest rate of 5.625 per cent for the first 10 years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$750 million of Junior subordinated notes of TCPL at a rate of 5.875 per cent, including a 0.25 per cent administration charge. The rate will reset commencing May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum. The Junior subordinated notes of TCPL are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TCPL's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL.

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

146 TCPL Consolidated financial statements2015

18.NON-CONTROLLING INTERESTS

The Company's Non-controlling interests included in the Consolidated balance sheet are as follows:

at December 31	2015	2014
(millions of Canadian $)
Non-controlling interest in TC PipeLines, LP	1,590	1,479
Non-controlling interest in PNGTS	127	104
	1,717	1,583

The Company's Non-controlling interests included in the Consolidated statement of income are as follows:

year ended December 31	2015		2014	2013
(millions of Canadian $)
Non-controlling interest in TC PipeLines, LP	(13	)	136	93
Non-controlling interest in PNGTS	19		15	12
	6		151	105

During 2015, the Non-controlling interest in TC PipeLines, LP increased from 71.7 per cent to 72.0 per cent due to periodic issuances of common units in TC PipeLines, LP to non-controlling interests. In 2014, the Non-controlling interest in TC PipeLines, LP ranged between 71.1 per cent and 71.7 per cent and, in 2013, between 66.7 per cent and 71.1 per cent.

At December 31, 2015, TC PipeLines, LP recorded an impairment charge of US$199 million related to its equity investment in Great Lakes. The Non-controlling interest's share of this charge was US$143 million and is included in the $13 million Non-controlling interest in TC PipeLines, LP in the Consolidated statement of income.

The Non-controlling interest in PNGTS as at December 31, 2015 represented the 38.3 per cent interest held by third parties (2014 and 2013 – 38.3 per cent).

In 2015, TCPL received fees of $4 million from TC PipeLines, LP (2014 and 2013 – $3 million) and $11 million from PNGTS (2014 – $8 million; 2013 – $7 million) for services provided.

TCPL Consolidated financial statements2015147

19.COMMON SHARES

	Number of Shares	Amount
	(thousands)	(millions of Canadian $)
Outstanding at January 1, 2013	738,381	14,306
Issuance of common shares for cash	18,733	899
Outstanding at December 31, 2013	757,114	15,205
Issuance of common shares for cash	22,365	1,115
Outstanding at December 31, 2014	779,479	16,320
Outstanding at December 31, 2015	779,479	16,320

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

Restrictions on Dividends

Certain terms of the Company's debt instruments can limit the amount of dividends the Company can pay on preferred and common shares. At December 31, 2015 these terms limit the company from paying dividends in excess of $4.1 billion (2014 – $8.7 billion; 2013 – $1.3 billion). Under the agreements, TCPL can adjust this limit throughout the year if required, at is sole discretion, without incurring significant costs.

Stock Option Plan

Certain key employees, including officers, are granted stock options from TransCanada to purchase common shares at the market price on the grant date. Stock options vest equally over three years, beginning on the first anniversary of the grant date, and expire after seven years.

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

year ended December 31	2015		2014		2013
Expected life (years)	5.8		6.0		6.0
Interest rate	1.1	%	1.8	%	1.7	%
Volatility1	18	%	17	%	18	%
Dividend yield	3.7	%	3.8	%	3.7	%
Forfeiture rate	5	%	5	%	15	%

¹  Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $11 million in 2015 (2014 – $9 million; 2013 – $6 million).

The following table summarizes additional stock option information:

year ended December 31	2015	2014	2013
(millions of Canadian $, unless otherwise noted)
Total intrinsic value of options exercised	37	68	25
Fair value of options that have vested	91	95	64
Total options vested	2.0 million	1.7 million	1.3 million

148 TCPL Consolidated financial statements2015

As at December 31, 2015, the aggregate intrinsic value of the total options exercisable was $23 million and the total intrinsic value of options outstanding was $23 million.

20.PREFERRED SHARES

In March 2014, TCPL redeemed all of the 4 million outstanding Series Y preferred shares at a redemption price of $50 per share for a gross payment of $200 million.

In October 2013, TCPL redeemed all of the 4 million outstanding Series U preferred shares at a redemption price of $50 per share for a gross payment of $200 million.

21.OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS

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

year ended December 31, 2015	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	798		15		813
Change in fair value of net investment hedges	(505	)	133		(372	)
Change in fair value of cash flow hedges	(92	)	35		(57	)
Reclassification to net income of gains and losses on cash flow hedges	144		(56	)	88
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	74		(23	)	51
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	41		(9	)	32
Other comprehensive income on equity investments	62		(15	)	47
Other Comprehensive Income	522		80		602

year ended December 31, 2014	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	462		55		517
Change in fair value of net investment hedges	(373	)	97		(276	)
Change in fair value of cash flow hedges	(118	)	49		(69	)
Reclassification to net income of gains and losses on cash flow hedges	(95	)	40		(55	)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(146	)	44		(102	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	25		(7	)	18
Other comprehensive loss on equity investments	(272	)	68		(204	)
Other Comprehensive Loss	(517	)	346		(171	)

TCPL Consolidated financial statements2015149

year ended December 31, 2013	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	269		114		383
Change in fair value of net investment hedges	(323	)	84		(239	)
Change in fair value of cash flow hedges	121		(50	)	71
Reclassification to net income of gains and losses on cash flow hedges	60		(19	)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	96		(29	)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	34		(11	)	23
Other comprehensive income on equity investments	313		(79	)	234
Other Comprehensive Income	570		10		580

The changes in AOCI by component are as follows:

	Currency Translation Adjustments		Cash Flow Hedges		Pension and Other Post-Retirement Benefit Plan Adjustments		Equity Investments		Total1
AOCI balance at January 1, 2013	(707	)	(116	)	(287	)	(338	)	(1,448	)
Other comprehensive income before reclassifications2	78		71		67		219		435
Amounts reclassified from accumulated other comprehensive loss	—		41		23		15		79
Net current period other comprehensive income	78		112		90		234		514
AOCI balance at December 31, 2013	(629	)	(4	)	(197	)	(104	)	(934	)
Other comprehensive income/(loss) before reclassifications2	111		(69	)	(102	)	(206	)	(266	)
Amounts reclassified from accumulated other comprehensive loss	—		(55	)	18		2		(35	)
Net current period other comprehensive income/(loss)	111		(124	)	(84	)	(204	)	(301	)
AOCI balance at December 31, 2014	(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income/(loss) before reclassifications2	135		(57	)	51		33		162
Amounts reclassified from accumulated other comprehensive loss3	—		88		32		14		134
Net current period other comprehensive income	135		31		83		47		296
AOCI balance at December 31, 2015	(383	)	(97	)	(198	)	(261	)	(939	)

¹  All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

²  Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $306 million in 2015 (2014 – $130 million gains; 2013 – $66 million gains).

³  Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $83 million ($51 million, net of tax) at December 31, 2015. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

150 TCPL Consolidated financial statements2015

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

	Amounts Reclassified From Accumulated Other Comprehensive Loss1						Affected Line Item in the Consolidated Statement of Income
year ended December 31	2015		2014		2013
(millions of Canadian $)
Cash flow hedges
Commodities	(128	)	111		(44	)	Revenues (Energy)
Interest	(16	)	(16	)	(16	)	Interest expense
	(144	)	95		(60	)	Total before tax
	56		(40	)	19		Income tax expense/(recovery)
	(88	)	55		(41	)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial loss and past service cost	(41	)	(25	)	(34	)	2
	9		7		11		Income tax recovery
	(32	)	(18	)	(23	)	Net of tax
Equity investments
Equity income	(19	)	(2	)	(20	)	Income from equity investments
	5		—		5		Income tax recovery
	(14	)	(2	)	(15	)	Net of tax

¹  All amounts in parentheses indicate expenses to the Consolidated statement of income.

²  These Accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 22 for further information.

22.EMPLOYEE POST-RETIREMENT BENEFITS

The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 2015 (2014 and 2013 – nine years).

The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining life expectancy of former employees, which was approximately 12 years at December 31, 2015 (2014 – 12 years; 2013 – 11 years). In 2015, the Company expensed $41 million (2014 – $37 million; 2013 – $29 million) for the savings and DC Plans.

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

year ended December 31	2015	2014	2013
(millions of Canadian $)
DB Plans	96	73	79
Other post-retirement benefit plans	6	6	6
Savings and DC Plans	41	37	29
	143	116	114

Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. As such, in addition to the cash contributions noted above, the Company provided a $33 million letter of credit to the Canadian DB Plan in 2015 (2014 – $47 million; 2013 – $59 million), resulting in a total of $214 million provided to the Canadian DB Plan under letters of credit at December 31, 2015.

TCPL Consolidated financial statements2015151

The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2015 and the next required valuation will be as at January 1, 2016.

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Change in Benefit Obligation1
Benefit obligation – beginning of year	2,658		2,224		216		191
Service cost	108		85		3		2
Interest cost	115		113		10		10
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Actuarial (gain)/loss	(57	)	302		(11	)	14
Foreign exchange rate changes	81		32		14		6
Benefit obligation – end of year	2,780		2,658		225		216
Change in Plan Assets
Plan assets at fair value – beginning of year	2,398		2,152		39		35
Actual return on plan assets	160		246		(1	)	2
Employer contributions2	96		73		6		6
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Foreign exchange rate changes	62		25		8		3
Plan assets at fair value – end of year	2,591		2,398		45		39
Funded Status – Plan Deficit	(189	)	(260	)	(180	)	(177	)

¹  The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation

²  Excludes $214 million in letters of credit provided to the Canadian DB Plans for funding purposes (2014 – $181 million).

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Intangible and other assets (Note 11)	—		—		18		14
Accounts payable and other	—		—		(7	)	(7	)
Other long-term liabilities (Note 14)	(189	)	(260	)	(191	)	(184	)
	(189	)	(260	)	(180	)	(177	)

152 TCPL Consolidated financial statements2015

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Projected benefit obligation1	(2,780	)	(2,658	)	(198	)	(191	)
Plan assets at fair value	2,591		2,398		—		—
Funded Status – Plan Deficit	(189	)	(260	)	(198	)	(191	)

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

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

at December 31	2015		2014
(millions of Canadian $)
Accumulated benefit obligation	(2,600	)	(2,437	)
Plan assets at fair value	2,591		2,398
Funded Status – Plan Deficit	(9	)	(39	)

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

at December 31	2015		2014
(millions of Canadian $)
Accumulated benefit obligation	(807	)	(715	)
Plan assets at fair value	680		597
Funded Status – Plan Deficit	(127	)	(118	)

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

	Percentage of Plan Assets				Target Allocations
at December 31	2015		2014		2015
Debt securities	34	%	31	%	25% to 35%
Equity securities	66	%	69	%	50% to 70%
Alternatives	—		—		5 % to 15%
	100	%	100	%

TCPL Consolidated financial statements2015153

Debt and equity securities include the Company's debt and common shares as follows:

at December 31			Percentage of Plan Assets
(millions of Canadian $)	2015	2014	2015		2014
Debt securities	2	1	0.1	%	0.1	%
Equity securities	4	1	0.1	%	0.1	%

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

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

154 TCPL Consolidated financial statements2015

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

at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2015	2014	2015	2014	2015	2014	2015	2014	2015	2014
Asset Category
Cash and Cash Equivalents	44	20	2	—	—	—	46	20	2	1
Equity Securities:
Canadian	317	361	147	142	—	—	464	503	17	21
U.S.	589	516	40	35	—	—	629	551	24	23
International	38	218	300	147	—	—	338	365	13	15
Global	—	—	154	141	—	—	154	141	6	6
Emerging	7	7	143	80	—	—	150	87	6	3
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	206	218	—	—	206	218	8	9
Provincial	—	—	202	180	—	—	202	180	8	7
Municipal	—	—	7	7	—	—	7	7	—	—
Corporate	—	—	113	76	—	—	113	76	4	3
U.S. Bonds:
State	—	—	50	47	—	—	50	47	2	2
Corporate	—	—	57	59	—	—	57	59	2	2
International:
Corporate	—	—	25	14	—	—	25	14	1	1
Mortgage backed	—	—	58	39	—	—	58	39	2	2
Other Investments:
Private equity funds	—	—	—	—	14	13	14	13	—	—
Funds held on deposit	123	117	—	—	—	—	123	117	5	5
	1,118	1,239	1,504	1,185	14	13	2,636	2,437	100	100

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

(millions of Canadian $, pre-tax)	Private Equity Funds
Balance at December 31, 2013	18
Purchases and sales	(7	)
Realized and unrealized gains	2
Balance at December 31, 2014	13
Purchases and sales	(1	)
Realized and unrealized gains	2
Balance at December 31, 2015	14

TCPL Consolidated financial statements2015155

The Company's expected funding contributions in 2016 are approximately $70 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $37 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $33 million letter of credit to the Canadian DB Plan for the funding of solvency requirements.

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

(millions of Canadian $)	Pension Benefits	Other Post- Retirement Benefits
2016	129	8
2017	133	9
2018	138	9
2019	142	9
2020	146	10
2021 to 2025	808	51

The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2015. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

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

	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2015		2014		2015		2014
Discount rate	4.20	%	4.15	%	4.40	%	4.20	%
Rate of compensation increase	0.50	%	3.15	%	—	%	—	%

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

	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2015		2014		2013		2015		2014		2013
Discount rate	4.15	%	4.95	%	4.35	%	4.20	%	5.00	%	4.35	%
Expected long-term rate of return on plan assets	6.95	%	6.90	%	6.70	%	4.60	%	4.60	%	4.60	%
Rate of compensation increase	3.15	%	3.15	%	3.15	%	—		—		—

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

156 TCPL Consolidated financial statements2015

A seven per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2021 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:

(millions of Canadian $)	Increase	Decrease
Effect on total of service and interest cost components	1	(1	)
Effect on post-retirement benefit obligation	14	(12	)

The Company's net benefit cost recognized is as follows:

at December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2013		2015		2014		2013
Service cost	108		85		84		3		2		2
Interest cost	115		113		96		10		10		7
Expected return on plan assets	(155	)	(139	)	(120	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	35		21		30		3		2		2
Amortization of past service cost	2		2		2		1		—		—
Amortization of regulatory asset	23		18		30		1		1		1
Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
Net Benefit Cost Recognized	128		100		122		18		15		12

Pre-tax amounts recognized in AOCI were as follows:

	2015		2014		2013
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)
Net loss	247	28	348	39	236	32
Prior service cost	—	—	2	1	3	1
	247	28	350	40	239	33

The estimated net loss for the DB Plans and for the other post-retirement benefit plans that will be amortized from AOCI into net periodic benefit cost in 2016 is $21 million and $3 million respectively.

Pre-tax amounts recognized in OCI were as follows:

	2015				2014				2013
at December 31	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
(millions of Canadian $)
Amortization of net loss from AOCI to OCI	(34	)	(4	)	(21	)	(2	)	(30	)	(2	)
Amortization of prior service costs from AOCI to OCI	(2	)	(1	)	(2	)	—		(2	)	—
Funded status adjustment	(67	)	(7	)	137		9		(96	)	—
	(103	)	(12	)	114		7		(128	)	(2	)

TCPL Consolidated financial statements2015157

23.RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

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

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

Market Risk

The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds.

The Company uses derivatives as part of its overall risk management strategy to assist in managing the exposure to market risk that results from these activities. These derivative contracts may consist of the following:

• Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TCPL enters into foreign exchange and commodity forwards and futures to manage the impact of changes in foreign exchange rates and commodity prices.

• Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

• Options – contractual agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

Commodity Price Risk

The Company is exposed to commodity price movements as part of its normal business operations. A number of strategies are used to manage these exposures, including the following:

• Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio.

• The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin.

• The Company's power sales commitments are fulfilled through power generation or through purchased contracts, thereby reducing the Company's exposure to fluctuating commodity prices.

• The Company enters into offsetting or back-to-back positions using derivative instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

Natural Gas Storage Commodity Price Risk

TCPL manages its exposure to seasonal natural gas price spreads in its non-regulated Natural Gas Storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TCPL simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to

158 TCPL Consolidated financial statements2015

natural gas price movements. Unrealized gains and losses on fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement.

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates.

A portion of TCPL's earnings from its Natural Gas Pipelines, Liquids Pipelines and Energy segments are generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TCPL's net income. As the Company’s U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases; some of this foreign exchange impact is partially offset by interest expense on U.S. dollar-denominated debt of the Company's foreign operations and by using foreign exchange derivatives.

The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to other U.S. dollar-denominated transactions including those that may arise on some of the Company’s regulated assets. The realized gains and losses on these derivatives are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers.

TCPL has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk.

Net Investment in Foreign Operations

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

U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge

at December 31	2015	2014
(millions of Canadian $, unless otherwise noted)
Carrying value	23,000 (US 16,600)	17,000 (US 14,700)
Fair value	23,800 (US 17,200)	19,000 (US 16,400)

Derivatives Designated as a Net Investment Hedge

	2015				2014
at December 31	Fair Value1		Notional or Principal Amount		Fair Value1		Notional or Principal Amount
(millions of Canadian $, unless otherwise noted)
U.S. dollar cross-currency interest rate swaps (maturing 2016 to 2019)2	(730	)	US	3,150	(431	)	US	2,900
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	50		US	1,800	(28	)	US	1,400
	(680	)	US	4,950	(459	)	US	4,300

¹  Fair values equal carrying values.

²  In 2015, net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements are included in Interest expense.

Counterparty Credit Risk

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

The Company manages its exposure to this potential loss by using recognized credit management techniques, including:

• Dealing with creditworthy counterparties – a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

TCPL Consolidated financial statements2015159

• Setting limits on the amount TCPL can transact with any one counterparty – the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when necessary and when it is allowed under the terms of the contracts

• Using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary.

There is no guarantee that these techniques will protect the Company from material losses.

TCPL's maximum counterparty credit exposure with respect to financial instruments at December 31, 2015, without taking into account security held, consisted of accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2015, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

The Company had a credit risk concentration due from a counterparty of $248 million (US$179 million) and $258 million (US$222 million) at December 31, 2015 and 2014, respectively. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.

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

Fair Value of Non-Derivative Financial Instruments

The fair value of the Company's Notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of Long-term debt and Junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Due from affiliates, Intangible and other assets, Notes payable, Accounts payable and other, Due to affiliates, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.

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

Balance Sheet Presentation of Non-Derivative Financial Instruments

The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy:

	2015				2014
at December 31	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions of Canadian $)
Notes receivable1	214		265		213		263
Current and Long-term debt2,3 (Note 16)	(31,584	)	(34,309	)	(24,757	)	(28,713	)
Junior subordinated notes (Note 17)	(2,422	)	(2,011	)	(1,160	)	(1,157	)
	(33,792	)	(36,055	)	(25,704	)	(29,607	)

¹  Notes receivable are included in Other current assets and Intangible and other assets on the Consolidated balance sheet.

²  Long-term debt is recorded at amortized cost, except for US$850 million (2014 – US$400 million) that is attributed to hedged risk and recorded at fair value.

³  Consolidated Net income in 2015 included gains of $2 million (2014 – losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of Long-term debt at December 31, 2015 (2014 – US$400 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

160 TCPL Consolidated financial statements2015

Available for Sale Assets Summary

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

	2015		2014
at December 31	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2
(millions of Canadian $)
Fair values
Fixed income securities (maturing within 5 years)	—	90	—	75
Fixed income securities (maturing after 10 years)	261	—	—	—
	261	90	—	75

¹  Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company would record these gains and losses as regulatory assets or liabilities. In 2015 and 2014, there were no net realized or unrealized gains or losses on LMCI restricted investments.

²  Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. In 2015 and 2014, there were no net realized or unrealized gains or losses on other restricted investments.

Fair Value of Derivative Instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

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

TCPL Consolidated financial statements2015161

Balance Sheet Presentation of Derivative Instruments

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2015 is as follows:

at December 31, 2015	Cash Flow Hedges1		Fair Value Hedges1		Net Investment Hedges1		Held for Trading1		Total Fair Value of Derivative Instruments
(millions of Canadian $)
Other current assets (Note 5)
Commodities2	46		—		—		326		372
Foreign exchange	—		—		65		2		67
Interest rate	—		1		—		2		3
	46		1		65		330		442
Intangible and other assets (Note 11)
Commodities2	11		—		—		126		137
Foreign exchange	—		—		29		—		29
Interest rate	—		2		—		—		2
	11		2		29		126		168
Total Derivative Assets	57		3		94		456		610
Accounts payable and other (Note 13)
Commodities2	(112	)	—		—		(443	)	(555	)
Foreign exchange	—		—		(313	)	(54	)	(367	)
Interest rate	(1	)	(1	)	—		(2	)	(4	)
	(113	)	(1	)	(313	)	(499	)	(926	)
Other long-term liabilities (Note 14)
Commodities2	(31	)	—		—		(131	)	(162	)
Foreign exchange	—		—		(461	)	—		(461	)
Interest rate	(1	)	(1	)	—		—		(2	)
	(32	)	(1	)	(461	)	(131	)	(625	)
Total Derivative Liabilities	(145	)	(2	)	(774	)	(630	)	(1,551	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power and natural gas.

162 TCPL Consolidated financial statements2015

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2014 is as follows:

at December 31, 2014	Cash Flow Hedges1		Fair Value Hedges1	Net Investment Hedges1		Held for Trading1		Total Fair Value of Derivative Instruments
(millions of Canadian $)
Other current assets (Note 5)
Commodities2	39		—	—		359		398
Foreign exchange	—		—	5		1		6
Interest rate	—		2	—		3		5
	39		2	5		363		409
Intangible and other assets (Note 11)
Commodities2	18		—	—		72		90
Foreign exchange	—		—	1		—		1
Interest rate	—		1	—		1		2
	18		1	1		73		93
Total Derivative Assets	57		3	6		436		502
Accounts payable and other (Note 13)
Commodities2	(136	)	—	—		(422	)	(558	)
Foreign exchange	—		—	(155	)	(32	)	(187	)
Interest rate	(1	)	—	—		(3	)	(4	)
	(137	)	—	(155	)	(457	)	(749	)
Other long-term liabilities (Note 14)
Commodities2	(27	)	—	—		(72	)	(99	)
Foreign exchange	—		—	(310	)	—		(310	)
Interest rate	(1	)	—	—		(1	)	(2	)
	(28	)	—	(310	)	(73	)	(411	)
Total Derivative Liabilities	(165	)	—	(465	)	(530	)	(1,160	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power and natural gas.

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

TCPL Consolidated financial statements2015163

Notional and Maturity Summary

The following tables present the maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations:

at December 31, 2015	Power	Natural Gas	Foreign Exchange	Interest
Purchases1	70,331	133	—	—
Sales1	54,382	70	—	—
Millions of dollars	—	—	US 1,476	US 1,100
Maturity dates	2016–2020	2016–2020	2016	2016–2019

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

at December 31, 2014	Power	Natural Gas	Foreign Exchange	Interest
Purchases1	53,217	60	—	—
Sales1	39,429	38	—	—
Millions of dollars	—	—	US 1,374	US 650
Maturity dates	2015–2019	2015–2020	2015	2015–2018

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

Unrealized and Realized (Losses)/Gains of Derivative Instruments

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

year ended December 31	2015		2014
(millions of Canadian $)
Derivative instruments held for trading1
Amount of unrealized losses in the year
Commodities	(37	)	(40	)
Foreign exchange	(21	)	(20	)
Amount of realized losses in the year
Commodities	(151	)	(28	)
Foreign exchange	(112	)	(28	)
Derivative instruments in hedging relationships2,3
Amount of realized (losses)/gains in the year
Commodities	(179	)	130
Interest rate	8		4

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 derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively.

²  In 2015, net realized gains on fair value hedges were $11 million (2014 – gains of $7 million) and were included in Interest expense.

³  In 2015 and 2014, 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.

164 TCPL Consolidated financial statements2015

Derivatives in Cash Flow Hedging Relationships

The components of OCI (Note 21) related to derivatives in cash flow hedging relationships are as follows:

year ended December 31	2015		2014
(millions of Canadian $, pre-tax)
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Commodities	(92	)	(128	)
Foreign exchange	—		10
	(92	)	(118	)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net income (effective portion)1
Commodities2	128		(111	)
Interest rate3	16		16
	144		(95	)
Losses on derivative instruments recognized in Net income (ineffective portion)
Commodities2	—		(13	)

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

²  Reported within Revenues on the Consolidated statement of income.

³  Reported within Interest expense on the Consolidated statement of income.

Offsetting of Derivative Instruments

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

at December 31, 2015	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
	(1,551	)	512		(1,039	)

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

TCPL Consolidated financial statements2015165

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2014:

at December 31, 2014	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	488		(387	)	101
Foreign exchange	7		(7	)	—
Interest rate	7		(1	)	6
	502		(395	)	107
Derivative - Liability
Commodities	(657	)	387		(270	)
Foreign exchange	(497	)	7		(490	)
Interest rate	(6	)	1		(5	)
	(1,160	)	395		(765	)

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

With respect to the derivative instruments presented above as at December 31, 2015, the Company had provided cash collateral of $482 million (2014 – $459 million) and letters of credit of $41 million (2014 – $26 million) to its counterparties. The Company held nil (2014 – $1 million) in cash collateral and $2 million (2014 – $1 million) in letters of credit from counterparties on asset exposures at December 31, 2015.

Credit Risk Related Contingent Features of Derivative Instruments

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade.

Based on contracts in place and market prices at December 31, 2015, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $32 million (2014 – $15 million), for which the Company has provided collateral in the normal course of business of nil (2014 – nil). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2015, the Company would have been required to provide additional collateral of $32 million (2014 – $15 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

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

166 TCPL Consolidated financial statements2015

Fair Value Hierarchy

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

Levels	How fair value has been determined
Level I	Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level II	Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances.
Level III	Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the fair value of the derivatives. This category includes long-dated commodity transactions in certain markets where liquidity is low and inputs may include long-term broker quotes. Valuation of options is based on the Black-Scholes pricing model. Long-term electricity prices may also be estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Model inputs include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices might be estimated on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, increases in the supply of electricity or natural gas, or a small number of transactions in markets with lower liquidity are expected to or may result in a lower fair value measurement of contracts included in Level III. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.

TCPL Consolidated financial statements2015167

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015, are categorized as follows:

at December 31, 2015	Quoted Prices in Active Markets Level I1		Significant Other Observable Inputs Level II1		Significant Unobservable Inputs Level III1		Total
(millions of Canadian $)
Derivative Instrument Assets:
Commodities	34		462		13		509
Foreign exchange	—		96		—		96
Interest rate	—		5		—		5
Derivative Instrument Liabilities:
Commodities	(102	)	(611	)	(4	)	(717	)
Foreign exchange	—		(828	)	—		(828	)
Interest rate	—		(6	)	—		(6	)
	(68	)	(882	)	9		(941	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:

at December 31, 2014	Quoted Prices in Active Markets Level I1		Significant Other Observable Inputs Level II1		Significant Unobservable Inputs Level III1		Total
(millions of Canadian $)
Derivative Instrument Assets:
Commodities	40		441		7		488
Foreign exchange	—		7		—		7
Interest rate	—		7		—		7
Derivative Instrument Liabilities:
Commodities	(86	)	(568	)	(3	)	(657	)
Foreign exchange	—		(497	)	—		(497	)
Interest rate	—		(6	)	—		(6	)
	(46	)	(616	)	4		(658	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2014.

168 TCPL Consolidated financial statements2015

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

(millions of Canadian $, pre-tax)	2015		2014
Balance at beginning of year	4		1
Transfers out of Level III	5		—
Total gains included in Net income	3		3
Sales	(2	)	—
Settlements	(1	)	—
Balance at end of year1	9		4

¹  Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2015 of $7 million (2014 – $3 million).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2015.

24.CHANGES IN OPERATING WORKING CAPITAL

year ended December 31	2015		2014		2013
(millions of Canadian $)
Increase in Accounts receivable	(20	)	(205	)	(60	)
Increase in Inventories	(3	)	(27	)	(30	)
(Increase)/decrease in Other current assets	(268	)	(386	)	40
(Decrease)/increase in Accounts payable and other	(159	)	393		(291	)
Increase in Accrued interest	91		36		7
Increase in Operating Working Capital	(359	)	(189	)	(334	)

25.ACQUISITIONS AND DISPOSITIONS

Natural Gas Pipelines

TC PipeLines, LP

On April 1, 2015, TCPL completed the sale of its remaining 30 per cent interest in Gas Transmission Northwest LLC (GTN) to TC PipeLines, LP for an aggregate purchase price of US$457 million. Proceeds were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN LLC debt and US$95 million of new Class B units of TC PipeLines, LP.

On October 1, 2014, TCPL completed the sale of its remaining 30 per cent interest in Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$215 million.

In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at a price of US$43.85 per unit, resulting in gross proceeds of approximately US$388 million and net proceeds of US$373 million after unit issuance costs. TCPL contributed approximately US$8 million to maintain its two per cent general partnership interest and did not purchase any other units. Upon completion of this offering, TCPL's ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent and an after-tax dilution gain of $29 million ($47 million pre-tax) was recorded in Additional paid-in capital.

In July 2013, TCPL completed the sale of a 45 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million for the assumption of 45 per cent of GTN LLC debt outstanding, plus normal closing adjustments. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.

Gas Pacifico/INNERGY

On November 26, 2014, TCPL sold its 30 per cent equity investments in Gas Pacifico and INNERGY for aggregate gross proceeds of $9 million and recognized a gain of $9 million ($8 million after-tax).

TCPL Consolidated financial statements2015169

Energy

Bruce Power

On December 3, 2015, TCPL exercised its option to acquire an additional 14.89 per cent ownership interest in Bruce B from the Ontario Municipal Employees Retirement System (OMERS) for $236 million, increasing its ownership interest to 46.5 per cent. The difference between the purchase price and the underlying carrying value of Bruce B is primarily related to the estimated fair value of the amended agreement with Ontario's Independent Electricity System Operator to extend the operating life of the Bruce Power facility to 2064. On December 4, 2015, Bruce B and Bruce A merged to form a single limited partnership (Bruce Power). This merger was accounted for as a transaction between entities under common control whereby the assets and liabilities of Bruce A and Bruce B were combined at their carrying values. Upon completion of the merger, TCPL applied equity accounting to its 48.5 per cent ownership interest in Bruce Power. Prior to the acquisition, TCPL applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B.

Ontario Solar

As part of a purchase agreement with Canadian Solar Solutions Inc. signed in 2011, TCPL completed the acquisition of four Ontario solar facilities for $241 million in 2014. In 2013, TCPL completed the acquisition of four solar facilities for $216 million. The Company's total investment in the eight solar facilities is $457 million. All power produced by the solar facilities is sold under 20-year PPAs with the Ontario Power Authority.

Cancarb

On April 15, 2014, TCPL sold Cancarb Limited and its related power generation for aggregate gross proceeds of $190 million and recognized a gain of $108 million ($99 million after-tax).

26.COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating Leases

Future annual payments under the Company's operating leases for various premises, services and equipment as well as fixed payments on Alberta PPAs, net of sublease receipts, are approximately as follows:

year ended December 31	Minimum Lease Payments	Amounts Recoverable under Sub-leases	Net Payments
(millions of Canadian $)
2016	354	46	308
2017	355	45	310
2018	270	26	244
2019	248	24	224
2020	185	20	165
2021 and thereafter	311	1	310
	1,723	162	1,561

The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 25 years. Net rental expense on operating leases in 2015 was $131 million (2014 – $114 million; 2013 – $98 million).

170 TCPL Consolidated financial statements2015

TCPL's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Fixed payments under these PPAs have been included in the above operating leases table. Variable payments have been excluded as these payments are dependent upon plant availability and other factors. TCPL's share of payments under the PPAs in 2015 was $348 million (2014 – $391 million; 2013 – $242 million). The generating capacities and expiry dates of the PPAs are as follows:

	MW	Expiry Date
Sundance A	560	December 31, 2017
Sheerness	756	December 31, 2020

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

Other Commitments

Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts.

At December 31, 2015, TCPL was committed to Natural Gas Pipelines capital expenditures totaling approximately $0.9 billion (2014 – $0.9 billion), primarily related to construction costs related to the NGTL System, Mexican and other natural gas pipeline projects.

At December 31, 2015, the Company was committed to Liquids Pipelines capital expenditures totaling approximately $0.8 billion (2014 – $1.8 billion), primarily related to construction costs of Grand Rapids and Northern Courier.

At December 31, 2015, the Company was committed to Energy capital expenditures totaling approximately $0.6 billion (2014 – $0.2 billion), related to capital costs of the Napanee Generating Station. The Company also entered into an agreement to acquire the Ironwood natural gas fired, combined cycle power plant for US$657 million, before post-closing adjustments.

Contingencies

TCPL is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2015, the Company had accrued approximately $32 million (2014 – $31 million; 2013 – $32 million) related to operating facilities, which represents the present value of the estimated future amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.

TCPL and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions, other than the Keystone XL legal proceeding described in Note 29, will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees

TCPL and its joint venture partner on Bruce Power, OMERS, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

TCPL Consolidated financial statements2015171

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

		2015		2014
year ended December 31	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
(millions of Canadian $)
Bruce Power	Ranging to 20182	88	2	634	6
Other jointly owned entities	Ranging to 2040	139	24	104	14
		227	26	738	20

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

²  Except for one guarantee with no termination date.

27.CORPORATE RESTRUCTURING COSTS

At December 31, 2015, the Company had incurred $122 million pre-tax of corporate restructuring charges primarily related to severance, and recorded a provision of $87 million pre-tax related to planned severance costs in 2016 and expected losses under lease commitments. Of the total corporate restructuring charges of $209 million pre-tax, $157 million was recorded in Plant operating costs and other in the Consolidated statement of income which was partially offset by $58 million recorded in Revenues in the Consolidated statement of income related to costs that were recoverable through regulatory and tolling structures. In addition, $44 million was recorded as a Regulatory asset on the Consolidated balance sheet as it is expected to be recovered through regulatory and tolling structures in future periods and $8 million was capitalized to projects impacted by the corporate restructuring.

28.RELATED PARTY TRANSACTIONS

The following amounts are included in Due from affiliates:

		2015			2014
(millions of Canadian $)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
Discount Notes1	2016	2,376	0.9	%	2,597	1.3	%
Credit Facility2		100	2.7	%	245	3.0	%
		2,476			2,842

¹  Issued to TransCanada. Interest on the discount notes is equivalent to current commercial paper rates.

²  Issued to TransCanada. This facility is repayable on demand and bears interest at the Royal Bank of Canada prime rate per annum.

In 2015, Interest income included $29 million as a result of inter-corporate lending to TransCanada (2014 –$37 million; 2013 –$38 million).

At December 31, 2015, Accounts receivable included $13 million due from TransCanada (December 31, 2014 –$59 million).

The following amounts are included in Due to affiliates:

		2015			2014
(millions of Canadian $)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
Credit Facility1	2016	311	3.5	%	866	3.8	%
		311			866

¹  TransCanada has an unsecured $3.5 billion credit facility with a subsidiary of TCPL. Interest on this facility is charged at Reuters prime rate plus 75 basis points.

172 TCPL Consolidated financial statements2015

In 2015, Interest expense included $28 million of interest charges as a result of inter-corporate borrowing (2014 –$37 million; 2013 - $62 million).

At December 31, 2015, Accounts payable and other included $12 million due to TransCanada (December 31, 2014 –$16 million).

At December 31, 2015, Accrued interest included nil of interest payable to TransCanada (December 31, 2014 –$1 million).

In 2015, the Company made interest payments of $29 million to TransCanada (2014 –$37 million; 2013 –$62 million).

29.SUBSEQUENT EVENTS

Portland Natural Gas Transmission System

On January 1, 2016, TCPL completed the sale of a 49.9 per cent interest in PNGTS to TC PipeLines, LP for an aggregate purchase price of US$223 million.

Keystone XL legal proceeding

On January 6, 2016, TCPL filed a Notice of Intent to initiate a claim under Chapter 11 of North American Free Trade Agreement (NAFTA) in response to the denial of the U.S. Presidential permit for the Keystone XL Pipeline. Through the NAFTA claim, the Company is seeking to recover more than US$15 billion in costs and damages that it estimates it has suffered as a result of the U.S. Administration’s breach of its NAFTA obligations. This litigation is in a preliminary stage and the likelihood of success and resulting impact on the Company’s financial position or results of operations is unknown at this time.

U.S. Senior Notes Issue

On January 27, 2016, TCPL completed an offering of US$850 million, 4.875 per cent Senior Notes due January 15, 2026 and

US$400 million, 3.125 per cent Senior Notes due January 15, 2019.

Ironwood

On February 1, 2016, TCPL acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$657 million, before post-closing adjustments.

TCPL Consolidated financial statements2015173

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of TransCanada PipeLines Limited

We consent to the use of our report, dated February 10, 2016, with respect to the consolidated financial statements and effectiveness of internal control over financial reporting included in this annual report on Form 40-F.

We also consent to the incorporation by reference of such report in TransCanada PipeLines Limited’s Registration Statement No. 333-208588 on Form F-10.

/s/ KPMG LLP

Chartered Professional Accountants

February 11, 2016

Calgary, Canada

EX-31.1

Exhibit 31.1

Certifications

I, Russell K. Girling, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting.

5. The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated February 11, 2016

/s/ RUSSELL K. GIRLING

Russell K. Girling

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

Certifications

I, Donald R. Marchand, certify that:

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

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting.

5. The issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Dated February 11, 2016

/s/ DONALD R. MARCHAND

Donald R. Marchand

Executive Vice-President, Corporate Development and Chief Financial Officer

EX-32.1

Exhibit 32.1

TRANSCANADA PIPELINES LIMITED

450 - 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

I, Russell K. Girling, the Chief Executive Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Annual Report as filed on Form 40-F for the fiscal year ending December 31, 2015 with the Securities and Exchange Commission (the "Report"), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ RUSSELL K. GIRLING

Russell K. Girling

Chief Executive Officer

February 11, 2016

EX-32.2

Exhibit 32.2

TRANSCANADA PIPELINES LIMITED

450 - 1st Street S.W.

Calgary, Alberta, Canada

T2P 5H1

CERTIFICATION OF CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF SARBANES-OXLEY ACT OF 2002

I, Donald R. Marchand, the Chief Financial Officer of TransCanada PipeLines Limited (the "Company"), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify, in connection with the Company's Annual Report as filed on Form 40-F for the fiscal year ending December 31, 2015 with the Securities and Exchange Commission (the "Report"), that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ DONALD R. MARCHAND

Donald R. Marchand

Chief Financial Officer

February 11, 2016

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Document and Entity Information	12 Months Ended
	Dec. 31, 2015 shares
Document and Entity Information
Entity Registrant Name	TRANSCANADA PIPELINES LTD
Entity Central Index Key	0000099070
Document Type	40-F
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding	779,605,870
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	FY

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CONSOLIDATED STATEMENT OF INCOME - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues
Natural Gas Pipelines	CAD 5,383	CAD 4,913	CAD 4,497
Liquids Pipelines	1,879	1,547	1,124
Energy	4,038	3,725	3,176
Total Revenues	11,300	10,185	8,797
Income from Equity Investments (Note 8)	440	522	597
Operating and Other Expenses
Plant operating costs and other	3,250	2,973	2,674
Commodity purchases resold	2,237	1,836	1,317
Property taxes	517	473	445
Depreciation and amortization	1,765	1,611	1,485
Asset impairment charges (Note 7)	3,745
Total Operating and Other Expenses	11,514	6,893	5,921
(Loss)/Gain on Assets Held for Sale/Sold (Notes 6 and 25)	(125)	117
Financial Charges
Interest expense (Note 16)	1,398	1,235	1,046
Interest income and other	(192)	(128)	(72)
Total Financial Charges/(Income)	1,206	1,107	974
(Loss)/Income before Income Taxes	(1,105)	2,824	2,499
Income Tax Expense/(Recovery) (Note 15)
Current	137	146	43
Deferred	(102)	684	562
Total Income Tax Expense/(Recovery)	35	830	605
Net (Loss)/Income	(1,140)	1,994	1,894
Net Income attributable to non-controlling interests (Note 18)	6	151	105
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,843	1,789
Preferred share dividends		2	20
Net (Loss)/Income Attributable to Common Shares	CAD (1,146)	CAD 1,841	CAD 1,769

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CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net (Loss)/Income	CAD (1,140)	CAD 1,994	CAD 1,894
Other Comprehensive Income/(Loss), Net of Income Taxes
Foreign currency translation gains on net investment in foreign operations	813	517	383
Change in fair value of net investment hedges	(372)	(276)	(239)
Change in fair value of cash flow hedges	(57)	(69)	71
Reclassification to net income of gains and losses on cash flow hedges	88	(55)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	51	(102)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	32	18	23
Other comprehensive income/(loss) on equity investments	47	(204)	234
Other comprehensive income/(loss) (Note 21)	602	(171)	580
Comprehensive (Loss)/Income	(538)	1,823	2,474
Comprehensive income attributable to non-controlling interests	312	281	171
Comprehensive (Loss)/Income Attributable to Controlling Interests	(850)	1,542	2,303
Preferred share dividends		2	20
Comprehensive (Loss)/Income Attributable to Common Shares	CAD (850)	CAD 1,540	CAD 2,283

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CONSOLIDATED STATEMENT OF CASH FLOWS - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Generated from Operations
Net (Loss)/Income	CAD (1,140)	CAD 1,994	CAD 1,894
Depreciation and amortization	1,765	1,611	1,485
Asset impairment charges (Note 7)	3,745
Deferred income taxes (Note 15)	(102)	684	562
Income from equity investments (Note 8)	(440)	(522)	(597)
Distributed earnings received from equity investments (Note 8)	576	579	605
Employee post-retirement benefits expense, net of funding (Note 22)	44	37	50
Loss/(gain) on assets held for sale/sold (Notes 6 and 25)	125	(117)
Equity allowance for funds used during construction	(165)	(95)	(19)
Unrealized losses/(gains) on financial instruments	58	74	(35)
Other	47	22	32
Increase in operating working capital (Note 24)	(359)	(189)	(334)
Net cash provided by operations	4,154	4,078	3,643
Investing Activities
Capital expenditures (Note 4)	(3,918)	(3,489)	(4,264)
Capital projects in development (Note 4)	(511)	(848)	(488)
Contributions to equity investments (Note 8)	(493)	(256)	(163)
Acquisitions, net of cash acquired (Note 25)	(236)	(241)	(216)
Proceeds from sale of assets, net of transaction costs (Note 25)		196
Distributions in excess of equity earnings (Note 8)	226	159	128
Deferred amounts and other	324	335	(117)
Net cash used in investing activities	(4,608)	(4,144)	(5,120)
Financing Activities
Notes payable (repaid)/issued, net	(1,382)	544	(492)
Long-term debt issued, net of issue costs	5,045	1,403	4,253
Long-term debt repaid	(2,105)	(1,069)	(1,286)
Junior subordinated notes issued, net of issue costs	917
Advances to affiliates, net	(189)	(694)	(297)
Dividends on common shares	(1,446)	(1,345)	(1,286)
Dividends on preferred shares		(4)	(22)
Distributions paid to non-controlling interests	(224)	(174)	(146)
Common shares issued		1,115	899
Partnership units of subsidiary issued, net of issue costs	55	79	384
Preferred shares redeemed (Note 20)		(200)	(200)
Net cash provided by/(used in) financing activities	671	(345)	1,807
Effect of Foreign Exchange Rate Changes on Cash and Cash Equivalents	112		28
Increase/(Decrease) in Cash and Cash Equivalents	329	(411)	358
Cash and Cash Equivalents, Beginning of year	484	895	537
Cash and Cash Equivalents, End of year	CAD 813	CAD 484	CAD 895

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CONSOLIDATED BALANCE SHEET - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	CAD 813	CAD 484
Accounts receivable (Note 28)	1,401	1,372
Due from affiliates (Note 28)	2,476	2,842
Inventories	323	292
Other (Note 5)	1,353	1,018
Total Current Assets	6,366	6,008
Plant, Property and Equipment (Note 7)	44,817	41,774
Equity Investments (Note 8)	6,214	5,598
Regulatory Assets (Note 9)	1,184	1,297
Goodwill (Note 10)	4,812	4,034
Intangible and Other Assets (Note 11)	3,185	2,641
Restricted Investments	351	63
Total Assets	66,929	61,415
Current Liabilities
Notes payable (Note 12)	1,218	2,467
Accounts payable and other (Note 13 and 28)	3,014	2,891
Due to affiliates (Note 28)	311	866
Accrued interest	520	425
Current portion of long-term debt (Note 16)	2,547	1,797
Total Current Liabilities	7,610	8,446
Regulatory Liabilities (Note 9)	1,159	263
Other Long-Term Liabilities (Note 14)	1,260	1,052
Deferred Income Tax Liabilities (Note 15)	5,144	4,856
Long-Term Debt (Note 16)	29,037	22,960
Junior Subordinated Notes (Note 17)	2,422	1,160
Total Liabilities	46,632	38,737
EQUITY
Common shares, no par value (Note 19); Issued and outstanding: December 31, 2015 779 million shares; December 31, 2014 - 779 million shares	16,320	16,320
Additional paid-in capital	210	404
Retained earnings	2,989	5,606
Accumulated other comprehensive loss (Note 21)	(939)	(1,235)
Controlling interests	18,580	21,095
Non-controlling interests (Note 18)	1,717	1,583
Total Equity	20,297	22,678
Total Liabilities and Equity	CAD 66,929	CAD 61,415

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CONSOLIDATED BALANCE SHEET (Parenthetical) - shares shares in Millions	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Common shares issued (in shares)	779	779
Common shares outstanding (in shares)	779	779

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CONSOLIDATED STATEMENT OF EQUITY - CAD CAD in Millions	Total	Equity Attributable to Controlling Interests	Common Shares	Preferred Shares	Additional Paid-In Capital	Retained Earnings	Accumulated Other Comprehensive Loss	Equity Attributable to Non-Controlling Interests
Beginning balance at Dec. 31, 2012			CAD 14,306	CAD 389	CAD 400	CAD 4,657	CAD (1,448)
Increase (decrease) in equity
Proceeds from shares issued (Note 19)			899
Issuance of stock options, net of exercises					7
Dilution impact from TC PipeLines, LP units issued					29			CAD 384
Redemption of preferred shares				(195)	(5)
Net (loss)/income attributable to controlling interests	CAD 1,789					1,789
Common share dividends						(1,301)
Preferred share dividends						(20)
Other comprehensive income/(loss) (Note 21)	580						514
Ending balance at Dec. 31, 2013		CAD 20,021	15,205	194	431	5,125	(934)
Beginning balance at Dec. 31, 2012								1,036
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								93
Portland Natural Gas Transmission System	105							12
Other comprehensive income attributable to non-controlling interests								66
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					29			384
Decrease in TCPL's ownership of TC PipeLines, LP								(47)
Distributions declared to non-controlling interests								(146)
Other								19
Ending balance at Dec. 31, 2013								1,417
Issuance of TC PipeLines, LP units
Total Equity	21,438
Proceeds from shares issued (Note 19)			1,115
Issuance of stock options, net of exercises					7
Dilution impact from TC PipeLines, LP units issued					9			79
Redemption of preferred shares				CAD (194)	(6)
Impact of asset drop downs to TC PipeLines, LP (Note 25)					(37)
Net (loss)/income attributable to controlling interests	1,843					1,843
Common share dividends						(1,360)
Preferred share dividends						(2)
Other comprehensive income/(loss) (Note 21)	(171)						(301)
Ending balance at Dec. 31, 2014	21,095	21,095	16,320		404	5,606	(1,235)
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								136
Portland Natural Gas Transmission System	151							15
Other comprehensive income attributable to non-controlling interests								130
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					9			79
Decrease in TCPL's ownership of TC PipeLines, LP								(14)
Distributions declared to non-controlling interests								(180)
Ending balance at Dec. 31, 2014	1,583							1,583
Issuance of TC PipeLines, LP units
Total Equity	22,678
Issuance of stock options, net of exercises					13
Dilution impact from TC PipeLines, LP units issued					6			55
Impact of asset drop downs to TC PipeLines, LP (Note 25)					(213)
Net (loss)/income attributable to controlling interests	(1,146)					(1,146)
Common share dividends						(1,471)
Other comprehensive income/(loss) (Note 21)	602						296
Ending balance at Dec. 31, 2015	18,580	CAD 18,580	CAD 16,320		210	CAD 2,989	CAD (939)
Equity Attributable to Non-Controlling Interests
TC PipeLines, LP								(13)
Portland Natural Gas Transmission System	6							19
Other comprehensive income attributable to non-controlling interests								306
Issuance of TC PipeLines, LP units
Proceeds, net of issue costs					CAD 6			55
Decrease in TCPL's ownership of TC PipeLines, LP								(11)
Distributions declared to non-controlling interests								(222)
Ending balance at Dec. 31, 2015	1,717							CAD 1,717
Issuance of TC PipeLines, LP units
Total Equity	CAD 20,297

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DESCRIPTION OF TCPL'S BUSINESS

12 Months Ended

Dec. 31, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

DESCRIPTION OF TCPL'S BUSINESS

DESCRIPTION OF TCPL'S BUSINESS

TransCanada PipeLines Limited (TCPL or the Company) is a leading North American energy infrastructure company which operates in three business segments, Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services. The Company is a wholly-owned subsidiary of TransCanada Corporation (TransCanada).

Natural Gas Pipelines

The Natural Gas Pipelines segment consists of the Company's investments in 67,300 km (41,900 miles) of regulated natural gas pipelines and 250 Bcf of regulated natural gas storage facilities. These assets are located in Canada, the United States (U.S.) and Mexico.

Liquids Pipelines

The Liquids Pipelines segment consists of 4,247 km (2,639 miles) of wholly-owned and operated crude oil pipeline systems which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas.

Energy

The Energy segment primarily consists of the Company's investments in 19 electrical power generation plants and 2 non-regulated natural gas storage facilities. These include Canadian plants in Alberta, Ontario, Québec and New Brunswick and U.S. plants in New York, New England and Arizona.

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ACCOUNTING POLICIES

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

ACCOUNTING POLICIES

ACCOUNTING POLICIES

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

Basis of Presentation

The consolidated financial statements include the accounts of TCPL and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-controlling interests. TCPL uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TCPL records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates and Judgments

In preparing these financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to:

• fair value and depreciation rates of plant, property and equipment (Note 7);

• carrying value of regulatory assets and liabilities (Note 9);

• fair value of goodwill (Note 10);

• amortization rates and fair value of intangible assets (Note 11);

• carrying value of asset retirement obligations (Note 14);

• provisions for income taxes (Note 15);

• assumptions used to measure retirement and other post-retirement obligations (Note 22);

• fair value of financial instruments (Note 23); and

• provision for commitments, contingencies and guarantees (Note 26).

Actual results could differ from those estimates.

Regulation

In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB). In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls.Rate-regulatedaccounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TCPL's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of its liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System as the regulators' decisions regarding operations and tolls on that system generally do not have an impact on timing of recognition of revenues and expenses.

Revenue Recognition

Natural Gas Pipelines and Liquids Pipelines

Revenues from the Company's natural gas and liquids pipelines, with the exception of Canadian natural gas pipelines which are subject to RRA, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made.

Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are at times subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved ROE assumptions. Adjustments to revenue are recorded when the NEB decision is received.

The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final.

Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas or oil that it transports or stores for others.

Energy

Power

Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative Instruments and Hedging Activities section of this note.

Natural Gas Storage

Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues.

Cash and Cash Equivalents

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

Inventories

Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.

Plant, Property and Equipment

Natural Gas Pipelines

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

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

Liquids Pipelines

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

Energy

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

Corporate

Corporate Plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

Capitalized Project Costs

The Company capitalizes project costs once advancement to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest for non-regulated projects in development and AFUDC for regulated projects. Capital projects in development are included in Intangible and other assets. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's depreciation policies.

Project costs related to acquisitions are capitalized once the acquisition is probable.

Assets Held For Sale

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

Impairment of Long-Lived Assets

The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated price to sell is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the fair value of the asset.

Acquisitions and Goodwill

The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company initially assesses qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If TCPL concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value is less than carrying value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference.

Power Purchase Arrangements

A power purchase agreement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. Substantially all PPAs under which TCPL buys power are accounted for as operating leases. Initial payments for these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TCPL records the margin earned from the subleases as a component of Revenues.

Restricted Investments

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

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

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, NGTL System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

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

Asset Retirement Obligations

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

The Company has recorded ARO related to the non-regulated natural gas storage operations and certain power generation facilities. The scope and timing of asset retirements related to natural gas pipelines, liquids pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities.

Environmental Liabilities

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

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

Stock Options and Other Compensation Programs

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

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

Employee Post-Retirement Benefits

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

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

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

Foreign Currency Transactions and Translation

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

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

Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

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

Long-Term Debt Transaction Costs

The Company records Long-term debt transaction costs as other assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.

Guarantees

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

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ACCOUNTING CHANGES

12 Months Ended

Dec. 31, 2015

Accounting Changes and Error Corrections [Abstract]

ACCOUNTING CHANGES

ACCOUNTING CHANGES

Changes in Accounting Policies for 2015

Derivatives and Hedging

In August 2015, the Financial Accounting Standards Board (FASB) issued new guidance on the application of the normal purchases and normal sales scope exception to certain electricity contracts within nodal energy markets. The amendments in this update apply to entities that enter into contracts for the purchase or sale of electricity on a forward basis and arrange for transmission through or delivery to a location within a nodal energy market whereby one of the contracting parties incurs charges (or credits) for the transmission of that electricity based in part on locational marginal pricing differences payable to (or receivable from) an independent system operator. This new guidance was effective upon issuance, was applied prospectively and did not have a material impact on the Company's consolidated financial statements.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued new guidance which requires that deferred tax assets and liabilities be classified as non-current on the balance sheet. The new guidance is effective January 1, 2017, however, since early application is permitted, the Company elected to retrospectively apply this guidance effective January 1, 2015. Application of this new guidance will simplify the Company’s process in determining deferred tax amounts and simplify their presentation. The application of this amendment resulted in a reclassification of Deferred tax assets previously recorded in Other current assets, and Deferred tax liabilities previously recorded in Accounts payable and other to non-current Deferred income tax assets and liabilities. Prior year amounts have been reclassified to conform to current year presentation.

Reporting discontinued operations

In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance was applied prospectively from January 1, 2015 and there was no impact on the Company's consolidated financial statements as a result of applying this new standard.

Future Accounting Changes

Revenue from contracts with customers

In 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In July 2015, the FASB deferred the effective date of this new standard to January 1, 2018, with early adoption not permitted before January 1, 2017. There are two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application.

The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Extraordinary and unusual income statement items

In January 2015, the FASB issued new guidance on extraordinary and unusual income statement items. This update eliminates from GAAP the concept of extraordinary items. This new guidance is effective from January 1, 2016 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Consolidation

In February 2015, the FASB issued new guidance on consolidation analysis. This update requires that entities reevaluate whether they should consolidate certain legal entities and eliminates the presumption that a general partner should consolidate a limited partnership. This new guidance is effective from January 1, 2016 and will be applied retrospectively. The Company is currently evaluating the impact of the adoption of this guidance and has not yet determined the effect on its consolidated financial statements.

Imputation of interest

In April 2015, the FASB issued new guidance on simplifying the accounting for debt issuance costs. The amendments in this update require that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of the debt liability consistent with debt discounts or premiums. This new guidance is effective January 1, 2016 and will be applied retrospectively. The application of this amendment will result in a reclassification of debt issuance costs currently recorded in Intangible and other assets to an offset of their respective debt liabilities.

Inventory

In July 2015, the FASB issued new guidance on simplifying the measurement of inventory. The amendments in this update specify

that an entity should measure inventory within the scope of this update at the lower of cost and net realizable value. Net realizable

value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and

transportation. This new guidance is effective January 1, 2017 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

Business Combinations

In September 2015, the FASB issued guidance which replaces the requirement that an acquirer in a business combination account for measurement period adjustments retrospectively with a requirement that an acquirer recognize adjustments to the provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amended guidance requires that the acquirer record, in the same period’s financial statements as the adjustment was determined, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The new guidance is effective January 1, 2016 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.

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SEGMENTED INFORMATION

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

SEGMENTED INFORMATION

SEGMENTED INFORMATION

year ended December 31, 2015	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	5,383		1,879		4,038		—		11,300
Income from equity investments	179		—		261		—		440
Plant operating costs and other	(1,736	)	(478	)	(766	)	(270	)	(3,250	)
Commodity purchases resold	—		—		(2,237	)	—		(2,237	)
Property taxes	(349	)	(79	)	(89	)	—		(517	)
Depreciation and amortization	(1,132	)	(266	)	(336	)	(31	)	(1,765	)
Asset impairment charges	—		(3,686	)	(59	)	—		(3,745	)
Loss on assets held for sale	(125	)	—		—		—		(125	)
Segmented earnings/(losses)	2,220		(2,630	)	812		(301	)	101
Interest expense									(1,398	)
Interest income and other									192
Loss before income taxes									(1,105	)
Income tax expense									(35	)
Net loss									(1,140	)
Net income attributable to non-controlling interests									(6	)
Net loss attributable to controlling interests									(1,146	)
Preferred share dividends									—
Net loss attributable to common shares									(1,146	)
Capital spending
Capital expenditures	2,466		1,012		376		64		3,918
Capital projects in development	233		278		—		—		511
	2,699		1,290		376		64		4,429

year ended December 31, 2014	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	4,913		1,547		3,725		—		10,185
Income from equity investments	163		—		359		—		522
Plant operating costs and other	(1,501	)	(426	)	(919	)	(127	)	(2,973	)
Commodity purchases resold	—		—		(1,836	)	—		(1,836	)
Property taxes	(334	)	(62	)	(77	)	—		(473	)
Depreciation and amortization	(1,063	)	(216	)	(309	)	(23	)	(1,611	)
Gain on assets sold	9		—		108		—		117
Segmented earnings/(losses)	2,187		843		1,051		(150	)	3,931
Interest expense									(1,235	)
Interest income and other									128
Income before income taxes									2,824
Income tax expense									(830	)
Net income									1,994
Net income attributable to non-controlling interests									(151	)
Net income attributable to controlling interests									1,843
Preferred share dividends									(2	)
Net income attributable to common shares									1,841
Capital spending
Capital expenditures	1,768		1,469		206		46		3,489
Capital projects in development	368		480		—		—		848
	2,136		1,949		206		46		4,337

year ended December 31, 2013	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	4,497		1,124		3,176		—		8,797
Income from equity investments	145		—		452		—		597
Plant operating costs and other	(1,405	)	(328	)	(833	)	(108	)	(2,674	)
Commodity purchases resold	—		—		(1,317	)	—		(1,317	)
Property taxes	(329	)	(44	)	(72	)	—		(445	)
Depreciation and amortization	(1,027	)	(149	)	(293	)	(16	)	(1,485	)
Segmented earnings/(losses)	1,881		603		1,113		(124	)	3,473
Interest expense									(1,046	)
Interest income and other									72
Income before income taxes									2,499
Income tax expense									(605	)
Net income									1,894
Net income attributable to non-controlling interests									(105	)
Net income attributable to controlling interests									1,789
Preferred share dividends									(20	)
Net income attributable to common shares									1,769
Capital spending
Capital expenditures	1,776		2,286		152		50		4,264
Capital projects in development	245		243		—		—		488
	2,021		2,529		152		50		4,752

at December 31	2015	2014
(millions of Canadian $)
Total Assets
Natural Gas Pipelines	31,072	27,103
Liquids Pipelines	16,046	16,116
Energy	15,558	14,197
Corporate	4,253	3,999
	66,929	61,415

Geographic Information

year ended December 31	2015	2014	2013
(millions of Canadian $)
Revenues
Canada – domestic	3,877	3,956	4,659
Canada – export	1,292	1,314	997
United States	5,872	4,718	3,029
Mexico	259	197	112
	11,300	10,185	8,797

at December 31	2015	2014
(millions of Canadian $)
Plant, Property and Equipment
Canada	19,287	19,191
United States	21,899	20,098
Mexico	3,631	2,485
	44,817	41,774

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OTHER CURRENT ASSETS

12 Months Ended

Dec. 31, 2015

Other Assets [Abstract]

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS

at December 31		2014
(millions of Canadian $)	2015
Cash held as collateral	585	423
Fair value of derivative contracts (Note 23)	442	409
Regulatory assets (Note 9)	85	16
Assets held for sale (Note 6)	20	—
Other	221	170
	1,353	1,018

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ASSETS HELD FOR SALE

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE

On December 18, 2015, the Company entered into an agreement to sell TC Offshore LLC (TCO) to a third party and expects the sale to close in early 2016. As a result, at December 31, 2015, the related assets and liabilities were held for sale in the Natural Gas Pipelines segment and were recorded at their fair values less costs to sell. This resulted in a loss of $125 million pre-tax in 2015 which is included in (Loss)/gain on assets held for sale/sold in the Consolidated statement of income. TCO is a FERC regulated entity that operates as part of ANR. TCO does not represent a major line of business or geographical area of the Company, and therefore is not considered to be a discontinued operation as of December 31, 2015.

at December 31	2015
(millions of Canadian $)
Assets Held for Sale
Accounts receivable	4
Inventories	1
Other current assets	1
Plant, property and equipment	14
Total Assets Held for Sale (included in Other current assets, Note 5)	20
Liabilities Related to Assets Held for Sale
Accounts payable and other	38
Other long-term liabilities	1
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13)	39

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PLANT, PROPERTY AND EQUIPMENT

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

PLANT, PROPERTY AND EQUIPMENT

PLANT, PROPERTY AND EQUIPMENT

	2015			2014
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)
Natural Gas Pipelines
Canadian Mainline
Pipeline	9,164	5,966	3,198	9,045	5,712	3,333
Compression	3,433	2,220	1,213	3,423	2,100	1,323
Metering and other	499	192	307	458	180	278
	13,096	8,378	4,718	12,926	7,992	4,934
Under construction	257	—	257	135	—	135
	13,353	8,378	4,975	13,061	7,992	5,069
NGTL System
Pipeline	8,456	3,820	4,636	8,185	3,619	4,566
Compression	2,188	1,404	784	2,055	1,318	737
Metering and other	1,096	489	607	1,032	446	586
	11,740	5,713	6,027	11,272	5,383	5,889
Under construction	969	—	969	413	—	413
	12,709	5,713	6,996	11,685	5,383	6,302
ANR1
Pipeline	1,449	350	1,099	1,217	227	990
Compression	1,101	187	914	780	140	640
Metering and other	977	252	725	737	231	506
	3,527	789	2,738	2,734	598	2,136
Under construction	304	—	304	127	—	127
	3,831	789	3,042	2,861	598	2,263
Mexico
Pipeline	1,296	162	1,134	1,053	104	949
Compression	183	14	169	151	6	145
Metering and other	388	27	361	314	20	294
	1,867	203	1,664	1,518	130	1,388
Under construction	1,959	—	1,959	1,098	—	1,098
	3,826	203	3,623	2,616	130	2,486
Other Natural Gas Pipelines
GTN	2,278	765	1,513	1,842	588	1,254
Great Lakes	2,157	1,155	1,002	1,807	939	868
Foothills	1,606	1,162	444	1,671	1,180	491
Other2	2,223	572	1,651	1,800	363	1,437
	8,264	3,654	4,610	7,120	3,070	4,050
Under construction	71	—	71	34	—	34
	8,335	3,654	4,681	7,154	3,070	4,084
	42,054	18,737	23,317	37,377	17,173	20,204

Liquids Pipelines
Keystone
Pipeline	9,288	718	8,570	7,931	463	7,468
Pumping equipment	1,092	108	984	964	80	884
Tanks and other	3,034	228	2,806	2,282	144	2,138
	13,414	1,054	12,360	11,177	687	10,490
Under construction	1,826	—	1,826	4,438	—	4,438
	15,240	1,054	14,186	15,615	687	14,928
Energy
Natural Gas – Ravenswood	2,607	654	1,953	2,140	476	1,664
Natural Gas – Other3,4	3,361	1,164	2,197	3,214	971	2,243
Hydro, Wind and Solar5	2,417	476	1,941	2,194	359	1,835
Natural Gas Storage and Other	740	132	608	717	118	599
	9,125	2,426	6,699	8,265	1,924	6,341
Under construction	430	—	430	149	—	149
	9,555	2,426	7,129	8,414	1,924	6,490
Corporate	267	82	185	232	80	152
	67,116	22,299	44,817	61,638	19,864	41,774

¹  TCO is excluded from the ANR net book value at December 31, 2015 as it has been classified as an asset held for sale. Refer to Note 6 for further information.

²  Includes Bison, Portland Natural Gas Transmission System (PNGTS), North Baja, Tuscarora and Ventures LP.

³  Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $813 million and $142 million, respectively, at December 31, 2015 (2014 – $695 million and $103 million, respectively). Revenues of $93 million were recognized in 2015 (2014 – $81 million; 2013 – $78 million) through the sale of electricity under the related PPAs.

⁴  Includes Halton Hills, Coolidge, Bécancour, Ocean State Power, Mackay River and other natural gas-fired facilities.

⁵  Includes the acquisitions of four solar power facilities in 2014.

Keystone XL Impairment

At December 31, 2015, the Company evaluated its investment in Keystone XL and related projects, including the Keystone Hardisty Terminal (KHT), for impairment in connection with the November 6, 2015 denial of the U.S. Presidential permit. As a result of the analysis, the Company recognized a non-cash impairment charge of $3,686 million ($2,891 million after-tax) based on the excess of the carrying value over the estimated fair value of $621 million of these assets. The impairment charge includes $77 million ($56 million after-tax) for certain cancellation fees that will be incurred in the future if the project is ultimately abandoned.

at December 31, 2015	Estimated	Impairment charge
(millions of Canadian $)	Fair Value	Pre-tax	After-tax
Plant and equipment	463	1,460	1,391
Terminals, including KHT	158	274	219
Intangible assets	—	1,150	737
Capitalized interest	—	725	488
Future cancellation costs	—	77	56
	621	3,686	2,891

The estimated fair value of $463 million related to plant and equipment was based on the price that would be received on sale of the plant and equipment in its current condition. An independent third party valuation was utilized in the assessment of the fair value of these assets. Key assumptions used in the determination of selling price included an estimated two year disposal period and the current weak energy market conditions. The valuation considered a variety of potential selling prices that were based on the various markets that could be used in order to dispose of these assets.

The estimated $158 million fair value of the terminal assets, including KHT, was determined using a discounted cash flow approach as a measure of fair value. The expected cash flows were discounted using a risk-adjusted discount rate to determine the fair value. 

The valuation techniques above required the use of unobservable inputs. As a result, the fair value is classified within Level 3 of the fair value hierarchy. Refer to Note 23 for further information on the fair value hierarchy.

Energy Turbine Impairment

Following the evaluation of specific capital project opportunities in 2015, it was determined that the carrying value of certain Energy turbine equipment was not fully recoverable. These turbines had been previously purchased for a power development project that did not proceed. As a result, at December 31, 2015, the Company recognized a non-cash impairment charge of $59 million ($43 million after-tax). This impairment charge was based on the excess of the carrying value over the fair value of the turbines, which was determined based on a comparison to similar assets available for sale in the market.

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EQUITY INVESTMENTS

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

EQUITY INVESTMENTS

EQUITY INVESTMENTS

(millions of Canadian $)	Ownership   Interest at   December 31, 2015		Income / (Loss) from Equity Investments				Equity Investments
			year ended December 31				at December 31
			2015		2014	2013	2015	2014
Natural Gas Pipelines
Northern Border1,2			85		76	66	664	587
Iroquois	44.5	%	51		43	41	238	210
TQM	50.0	%	12		12	13	72	73
Other	Various		31		32	25	73	68
Liquids Pipelines
Grand Rapids	50.0	%	—		—	—	542	240
Canaport Energy East Marine Terminal	50.0	%	—		—	—	16	—
Energy
Bruce Power3,4	48.5	%	249		314	310	4,200	3,995
ASTC Power Partnership	50.0	%	(23	)	8	110	21	29
Portlands Energy	50.0	%	30		36	31	321	335
Other	Various		5		1	1	67	61
			440		522	597	6,214	5,598

¹  The results reflect a 50.0 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2015, TCPL had an ownership interest in TC PipeLines, LP of 28.0 per cent (2014 – 28.3 and 2013 – 28.9 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.0 per cent (2014 – 14.2 and 2013 – 14.5 per cent).

²  At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$117 million (2014 – US$117 million) due to the fair value assessment of assets at the time of acquisition.

³  As a result of TCPL's increased ownership in Bruce Power L.P. (Bruce B) and the merger of Bruce Power A L.P. (Bruce A) and Bruce B (to form Bruce Power) in December 2015, TCPL has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TCPL applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TCPL continues to apply equity accounting to Bruce Power. Refer to Note 25 for further information.

⁴  At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $973 million (2014 – $776 million) due to the fair value assessment of assets at the time of acquisitions.

Distributions received from equity investments for the year ended December 31, 2015 were $802 million (2014 – $738 million; 2013 – $733 million) of which $226 million (2014 – $159 million; 2013 – $128 million) were returns of capital and are included in Investing activities in the Consolidated statement of cash flows. The undistributed earnings from equity investments as at December 31, 2015 were $198 million (2014 – $551 million; 2013 – $754 million).

Contributions made to equity investments for the year ended December 31, 2015 were $493 million (2014 – $256 million; 2013 –$163 million) and are included in Equity investments in the Consolidated statement of cash flows.

Summarized Financial Information of Equity Investments

year ended December 31	2015		2014		2013
(millions of Canadian $)
Income
Revenues	4,337		4,814		4,989
Operating and other expenses	(3,254	)	(3,489	)	(3,536	)
Net income	1,046		1,264		1,390
Net income attributable to TCPL	440		522		597

at December 31	2015		2014
(millions of Canadian $)
Balance Sheet
Current assets	1,530		1,412
Non-current assets	13,190		12,260
Current liabilities	(1,370	)	(1,067	)
Non-current liabilities	(3,116	)	(3,255	)

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RATE-REGULATED BUSINESSES

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

RATE-REGULATED BUSINESSES

RATE-REGULATED BUSINESSES

TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain Canadian liquids pipelines currently in development. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities.

Canadian Regulated Operations

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

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

Canadian Mainline

In March 2015, TCPL filed a compliance filing with the NEB in response to the RH-001-2014 Decision on TCPL's 2015-2030 Tolls Application (the NEB 2014 Decision) and is required to file a toll review for the 2018 to 2020 period prior to December 31, 2017. In June 2015, the NEB approved the applied-for compliance tolls as filed and these tolls became effective on July 1, 2015.

The NEB's 2014 Decision acknowledged that an off-ramp had been reached on the NEB 2013 Decision (described below) and approved fixed tolls for 2015 to 2020 as well as certain parameters for a toll setting methodology to 2030. Features of the settlement reached with shippers as approved in the NEB 2014 Decision include an ROE of 10.1 per cent on deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TCPL contribution to reduce the revenue requirement. Toll stabilization is achieved through the continued use of deferral accounts, namely the Long-term adjustment account (LTAA) and the Bridging amortization account, to capture the surplus or the shortfall between the Company's revenues and cost of service for each year over the six-year fixed toll term of the NEB 2014 Decision.

In March 2013, the Company received a decision from the NEB which set tolls for 2013 through 2017 at competitive levels, fixing tolls for some services and providing unlimited pricing discretion for others (the NEB 2013 Decision). The decision established an ROE of 11.5 per cent on deemed common equity of 40 per cent and included mechanisms to achieve the fixed tolls through the use of a LTAA as well as the establishment of a Tolls Stabilization Account (TSA) to capture the surplus or the shortfall between revenues and cost of service for each year over the five-year term of the decision. In addition, the decision provided an opportunity to generate incentive earnings by increasing revenues and reducing costs. The NEB also identified certain circumstances that would require a new tolls application prior to the end of the five-year term. One of those circumstances occurred in 2013 when the TSA balance became positive. In December 2013, TCPL filed the 2015-2030 Tolls Application with the NEB that addressed tolls moving forward including continuation of the NEB 2013 Decision tolls for 2014.

NGTL System

In February 2015, the NEB approved the NGTL System’s 2015 Revenue Requirement Settlement. The terms of the one year settlement include ROE of 10.1 per cent on 40 per cent deemed equity, a continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed annual operating, maintenance and administration (OM&A) cost amount that was based on an escalation of 2014 actual costs.

The NGTL System’s 2014 results reflect the terms of the 2013-2014 Revenue Requirement Settlement Application. This settlement had fixed annual OM&A costs and a 10.1 per cent ROE on deemed common equity of 40 per cent. Any variance between fixed OM&A costs in the settlement and actual costs accrued to TCPL. The settlement also included a composite depreciation rate of 3.12 per cent in 2014.

Energy East

Energy East is currently in the development stage, awaiting regulatory approval from the NEB. Tolls will be designed to provide for cost recovery including return of and on capital as approved by the NEB.

Other Canadian Pipelines

The Foothills operating model for 2014 and 2015 provides for recovery of all revenue requirement components on a flow-through basis. TQM operates under a model consisting of fixed and flow-through revenue requirement components for 2014 through 2016. Any variances between actual costs and those included in the fixed component accrue to TQM.

U.S. Regulated Operations

TCPL's U.S. natural gas pipelines are "natural gas companies" operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.

ANR

ANR's natural gas transportation and storage services are provided under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and allow ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC that was effective for all periods presented, beginning in 1997. On January 29, 2016, ANR Pipeline Company filed an application with the FERC under section 4 of the NGA to establish new rates expected to be effective, subject to refund, on August 1, 2016.

ANR Storage Company rates were established pursuant to a settlement approved by the FERC in August 2012 and ANR Storage Company is required to file for new rates to be effective no later than July 1, 2016.

TCO, another ANR-related regulated entity, began operating under FERC-approved tariff rates on November 1, 2012. As at December 31, 2015, TCO assets were classified as Assets held for sale. Refer to Note 6 for more information.

Other U.S. Natural Gas Pipelines

GTN, Great Lakes and Bison are regulated by the FERC and operate in accordance with FERC-approved tariffs that establish maximum and minimum rates for various services. Each pipeline is permitted to discount or negotiate these rates on a non-discriminatory basis.

GTN’s rates were established pursuant to a settlement approved by the FERC in January 2012. On June 30, 2015, FERC approved GTN’s new settlement with its shippers which satisfies GTN’s obligations from the 2012 settlement for new rates to be in effect on January 1, 2016, and reduced rates on the mainline by three per cent on July 1, 2015.  In January 2016, GTN’s rates will decrease a further 10 percent and will continue in effect through December 31, 2019. Unless superseded by a subsequent rate case or settlement, GTN’s rates will decrease an additional eight per cent for the period January 1, 2020 through December 31, 2021 when GTN will be required to establish new rates. 

Great Lakes operates under rates established pursuant to a settlement approved by the FERC in November 2013. Under the settlement, Great Lakes is required to file for new rates to be effective no later than January 1, 2018.

Bison continues to operate under the rates approved by FERC in connection with Bison's initial construction and has no requirement to file a new rate proceeding.

Mexico Regulated Operations

TCPL's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. In 2014, TCPL began using RRA for all natural gas pipelines in Mexico. The rates were established based on CRE approved negotiated contracts.

Regulatory Assets and Liabilities

at December 31	2015	2014	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)
Regulatory Assets
Deferred income taxes1	848	1,001	n/a
Operating and debt-service regulatory assets2	47	4	1
Pensions and other post retirement benefits3	210	236	n/a
Foreign exchange on long-term debt5	54	—	1-14
Other4	110	72	n/a
	1,269	1,313
Less: Current portion included in Other current assets (Note 5)	85	16
	1,184	1,297
Regulatory Liabilities
Foreign exchange on long-term debt5	—	42	1-14
Operating and debt-service regulatory liabilities2	32	21	1
ANR-related post-employment and retirement benefits other than pension6	147	117	n/a
Long term adjustment account7	231	64	45
Pipeline abandonment costs8	285	—	n/a
Bridging amortization account9	456	—	15
Other4	52	49	n/a
	1,203	293
Less: Current portion included in Accounts payable and other (Note 13)	44	30
	1,159	263

¹  These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.

²  Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. Pre-tax operating results in 2015 would have been $32 million lower (2014 – $28 million higher; 2013 – $76 million lower) had these amounts not been recorded as Regulatory assets and liabilities.

³  These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. The balances are excluded from the rate base and do not earn a return on investment. Pre-tax operating results in 2015 would have been $26 million higher (2014 – $46 million lower; 2013 – $171 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁴  Pre-tax operating results in 2015 would have been $35 million lower (2014 – $2 million higher; 2013 – $2 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁵  Foreign exchange on long-term debt of the NGTL System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, GAAP would have required the inclusion of these unrealized gains or losses in Net income.

⁶  Under the terms of ANR’s last rate settlement, ANR will be required to make refunds to its customers, pursuant to a refund plan to be approved by FERC in a future rate proceeding, of those amounts in the post-retirement benefit trust fund that have not been used to pay benefits to its employees. This regulatory liability represents the difference between the amount collected in rates and the amount of post-retirement benefits expense. ANR anticipates that the resolution of this liability will be determined through the section 4 rate case ANR filed with the FERC on January 29, 2016.  Since the timing of the rate case conclusion is uncertain, a settlement period cannot be determined at this time. Pre-tax operating results in 2015 would have been $30 million higher (2014 – $13 million higher; 2013 – $16 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁷  Pre-tax operating results in 2015 would have been $167 million higher (2014 – $418 million higher; 2013 – $247 million lower) had these amounts not been recorded as regulatory liabilities.

⁸  Effective January 1, 2015, NEB regulated pipelines including the Mainline, NGTL System, Foothills, Keystone and TQM are required to collect and set-aside funds received from customers to be used for future pipeline abandonment activities. Funds are collected through a surcharge mechanism, set-aside in trust accounts, and the obligation to use these funds for future pipeline abandonment activities is recorded as a regulatory liability. Pre-tax operating results in 2015 would have been $285 million higher (2014 –nil; 2013 –nil) had these amounts not been recorded as regulatory liabilities.

⁹  Pre-tax operating results in 2015 would have been $456 million higher (2014 – nil; 2013 –nil) had these amounts not been recorded as regulatory liabilities.

Allowance for Funds Used During Construction

The total amount of debt and equity AFUDC included in the Consolidated statement of income was $295 million in 2015 (2014 – $136 million; 2013 – $37 million).

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GOODWILL

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

GOODWILL

GOODWILL

The Company has recorded the following Goodwill on its acquisitions in the U.S.:

(millions of Canadian $)	Natural Gas Pipelines	Energy	Total
Balance at January 1, 2014	2,816	880	3,696
Foreign exchange rate changes	258	80	338
Balance at December 31, 2014	3,074	960	4,034
Foreign exchange rate changes	593	185	778
Balance at December 31, 2015	3,667	1,145	4,812

At December 31, 2015, TCPL’s Goodwill included US$573 million (2014 - US$573 million) related to the Great Lakes natural gas transportation business. TCPL's share of this Goodwill (net of non-controlling interests) was US$386 million (2014 – US$243 million). The increase in TCPL's share is a result of the impairment charge of US$199 million recorded by TC PipeLines, LP on its equity method goodwill related to Great Lakes. On a consolidated basis, TCPL’s carrying value of its investment in Great Lakes is proportionately lower compared to the 46.45% owned through TC PipeLines, LP. As a result, the estimated fair value of Great Lakes exceeded TCPL's consolidated carrying value of the investment and no impairment was recorded in 2015.

The estimated fair value of Great Lakes exceeded its carrying value by less than 10 per cent. The fair value of this reporting unit was measured by using a discounted cash flow analysis. Assumptions regarding Great Lakes’ ability to realize long-term value in the North American energy market have been adversely impacted by the changing natural gas flows in its market region as well as a change in the Company's view of other strategic alternatives to increase utilization of Great Lakes. As a result, the Company reduced forecasted cash flows from the reporting unit for the next ten years as compared to those utilized in previous impairment tests. There is a risk that continued reductions in future cash flow forecasts and adverse changes in other key assumptions could result in a future impairment of a portion of the Goodwill balance relating to Great Lakes.

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INTANGIBLE AND OTHER ASSETS

12 Months Ended

Dec. 31, 2015

INTANGIBLES AND OTHER ASSETS

INTANGIBLES AND OTHER ASSETS

INTANGIBLE AND OTHER ASSETS

at December 31	2015	2014
(millions of Canadian $)
Capital projects in development	1,814	1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances1	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	9	181
Other	797	628
	3,185	2,641

¹  TCPL held a note receivable from the seller of Ravenswood of $213 million (US$154 million) and $213 million (US$184 million) as at December 31, 2015 and at December 31, 2014, which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other current assets was $55 million (US$40 million) at December 31, 2015 and $46 million (US$40 million) at December 31, 2014.

The following amounts related to PPAs are included in Intangible and other assets:

	2015			2014
at December 31	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
(millions of Canadian $)
Sheerness (expires 2020)	585	390	195	585	351	234
Sundance A (expires 2017)	225	200	25	225	187	38
	810	590	220	810	538	272

Amortization expense for these PPAs was $52 million for the year ended December 31, 2015 (2014 and 2013 – $52 million). The expected annual amortization expense for 2016 and 2017 is $52 million, and $39 million for 2018 to 2020.

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NOTES PAYABLE

12 Months Ended

Dec. 31, 2015

Short-term Debt [Abstract]

NOTES PAYABLE

NOTES PAYABLE

	2015			2014
(millions of Canadian $, unless otherwise noted)	Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31
Canadian	697	0.8	%	1,540	1.2	%
U.S. (2015 – US$376; 2014 – US$800)	521	1.1	%	927	0.7	%
	1,218			2,467

At December 31, 2015, Notes payable consists of commercial paper issued by TCPL, TransCanada American Investments Ltd. (TAIL), and TransCanada Power Marketing Ltd. (TCPM). In November 2015, the TAIL credit facility was increased to US$1.5 billion from US$1.0 billion and, subsequently, TAIL and TCPM became co-borrowers under the facility and co-issuers under the related commercial paper program. At the same time, the TCPL USA credit facility was reduced from the US$1.0 billion to US$0.5 billion. In December 2015, a new US$1.0 billion credit facility and related commercial paper program was initiated for TCPL.

At December 31, 2015, total committed revolving and demand credit facilities of $8.9 billion (2014 – $6.7 billion) were available. When drawn, interest on these lines of credit is charged at prime rates of Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:

					year ended December 31
at December 31, 2015					2015	2014	2013
Amount	Unused Capacity	Borrower	Description	Matures	Cost to maintain
					(millions of Canadian $)
$3 billion	$3 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2020	6	6	4
US$1 billion	US$1 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2016	—	—	—
US$0.5 billion	US$0.5 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL	December 2016	3	2	1
US$1.5 billion	US$1.5 billion	TAIL/TCPM	Committed, syndicated, revolving, extendible TAIL/TCPM credit facility, guaranteed by TCPL	December 2016	2	1	—
$1.7 billion	$0.7 billion	TCPL/TCPL USA	Supports the issuance of letters of credit and provides additional liquidity	Demand	—	—	—

At December 31, 2015, the Company's operated affiliates had an additional $0.6 billion (2014 – $0.4 billion) of undrawn capacity on committed credit facilities.

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ACCOUNTS PAYABLE AND OTHER

12 Months Ended

Dec. 31, 2015

Payables and Accruals [Abstract]

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER

at December 31	2015	2014
(millions of Canadian $)
Trade payables	1,506	1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	370	345
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39	—
Other	129	143
	3,014	2,891

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OTHER LONG-TERM LIABILITIES

12 Months Ended

Dec. 31, 2015

Deferred Costs, Noncurrent [Abstract]

OTHER LONG-TERM LIABILITIES

OTHER LONG-TERM LIABILITIES

at December 31	2015	2014
(millions of Canadian $)
Fair value of derivative contracts (Note 23)	625	411
Employee post-retirement benefits (Note 22)	380	444
Asset retirement obligations	109	98
Guarantees (Note 26)	26	20
Other	120	79
	1,260	1,052

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INCOME TAXES

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

Provision for Income Taxes

year ended December 31	2015		2014	2013
(millions of Canadian $)
Current
Canada	45		104	27
Foreign	92		42	16
	137		146	43
Deferred
Canada	33		307	239
Foreign	(135	)	377	323
	(102	)	684	562
Income Tax Expense	35		830	605

Geographic Components of Income

year ended December 31	2015		2014	2013
(millions of Canadian $)
Canada	(623	)	1,146	1,201
Foreign	(482	)	1,678	1,298
(Loss)/Income Before Income Taxes	(1,105	)	2,824	2,499

Reconciliation of Income Tax Expense

year ended December 31	2015		2014		2013
(millions of Canadian $)
(Loss)/Income before income taxes	(1,105	)	2,824		2,499
Federal and provincial statutory tax rate	26.0	%	25.0	%	25.0	%
Expected income tax (recovery)/expense	(287	)	706		625
Income tax differential related to regulated operations	159		129		(13	)
Higher effective foreign tax rates	14		25		33
Income from equity investments and non-controlling interests	(56	)	(38	)	(28	)
Tax rate and legislative changes	34		—		(25	)
Asset impairment charges1	170		—		—
Other	1		8		13
Actual Income Tax Expense	35		830		605

¹  The asset impairment impact is net of $311 million attributed to higher foreign tax rates.

Deferred Income Tax Assets and Liabilities

at December 31	2015	2014
(millions of Canadian $)
Deferred Income Tax Assets
Difference in accounting and tax bases of impaired assets	916	—
Tax loss and credit carryforwards	1,325	1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	132	146
	3,304	1,970
Less: Valuation allowance1	1,060	125
	2,244	1,845
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,441	5,548
Equity investments	656	648
Taxes on future revenue requirement	227	253
Other	55	71
	7,379	6,520
Net Deferred Income Tax Liabilities	5,135	4,675

¹  In 2015, an increase to the valuation allowance of $935 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt and unrealized losses on certain impaired assets will not be realized in the future.

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

at December 31	2015	20141
(millions of Canadian $)
Deferred Income Tax Assets
Intangible and other assets (Note 11)	9	181
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,856
Net Deferred Income Tax Liabilities	5,135	4,675

¹  As a result of retrospectively applying guidance on the presentation of deferred taxes on the Consolidated balance sheet on January 1, 2015, the Company reclassified its December 31, 2014 current Deferred income tax assets of $427 million, and current Deferred income tax liabilities of $4 million to its non-current Deferred income tax assets and liabilities.

At December 31, 2015, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,276 million (2014 – $1,131 million) for federal and provincial purposes in Canada, which expire from 2026 to 2035. The Company also has Ontario minimum tax credits of $57 million (2014 – $50 million), which expire from 2016 to 2035.

At December 31, 2015, the Company has recognized the benefit of unused net operating loss carryforwards of US$1,617 million (2014 – US$2,267 million) for federal purposes in the U.S., which expire from 2029 to 2034. The Company also has alternative minimum tax credits of US$41 million (2014 – US$26 million).

Unremitted Earnings of Foreign Investments

Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2015 by approximately$308 million (2014 – $236 million) if there had been a provision for these taxes.

Income Tax Payments

Income tax payments of $164 million, net of refunds, were made in 2015 (2014 – payments, net of refunds, of $109 million; 2013 – payments, net of refunds, of $206 million).

Reconciliation of Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:

at December 31	2015		2014		2013
(millions of Canadian $)
Unrecognized tax benefit at beginning of year	13		19		45
Gross increases – tax positions in prior years	2		2		3
Gross decreases – tax positions in prior years	(2	)	(8	)	(28	)
Gross increases – tax positions in current year	1		1		2
Lapses of statute of limitations	(1	)	(1	)	(3	)
Unrecognized Tax Benefit at End of Year	13		13		19

TCPL recognized a favourable income tax adjustment of approximately $25 million due to the enactment of certain Canadian federal tax legislation in June 2013.

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

TCPL and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2007. Substantially all material U.S. federal, state and local income tax matters have been concluded for years through 2010.

TCPL's practice is to recognize interest and penalties related to income tax uncertainties in Income tax expense. Income tax expense for the year ended December 31, 2015 reflects a $1 million reversal of Interest expense and nil for penalties (2014 – nil for Interest expense and nil for penalties; 2013 – nil for Interest expense and nil for penalties). At December 31, 2015, the Company had $4 million accrued for Interest expense and nil accrued for penalties (December 31, 2014 –$5 million accrued for Interest expense and nil accrued for penalties).

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LONG-TERM DEBT

12 Months Ended

Dec. 31, 2015

Long-term Debt, Unclassified [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

		2015			2014
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate1		Outstanding at December 31	Interest Rate1
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
Debentures
Canadian	2017 to 2020	599	10.7	%	749	10.9	%
U.S. (2015 and 2014 – US$400)	2021	554	9.9	%	464	9.9	%
Medium-Term Notes
Canadian	2016 to 2041	5,192	5.3	%	4,048	5.7	%
Senior Unsecured Notes
U.S. (2015 – US$14,723; 2014 – US$13,526)	2016 to 2045	20,340	4.8	%	15,655	5.0	%
		26,685			20,916
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian2	2016 to 2024	325	11.5	%	325	11.5	%
U.S. (2015 and 2014 – US$200)	2023	277	7.9	%	232	7.9	%
Medium-Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2015 and 2014 – US$33)	2026	45	7.5	%	38	7.5	%
		1,151			1,099
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2015 and 2014 – US$432)	2021 to 2025	598	8.9	%	502	8.9	%
GAS TRANSMISSION NORTHWEST LLC
Unsecured Term Loan
U.S. (2015 – US$75)	2019	104	1.4	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$250; 2014 – US$325)	2020 to 2035	346	5.6	%	377	5.5	%
		450			377
TC PIPELINES, LP
Unsecured Loan
U.S. (2015 – US$200; 2014 – US$330)	2017	277	1.6	%	383	1.4	%
Unsecured Term Loan Facility
U.S. (2015 and 2014 – US$500)	2018	692	1.6	%	580	1.4	%
Unsecured Term Loan
U.S. (2015 – US$170)	2018	235	1.6	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$698; 2014 – US$350)	2021 to 2025	967	4.7	%	405	4.7	%
		2,171			1,368
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2015 – US$297; 2014 – US$316)	2018 to 2030	411	7.8	%	367	7.8	%

TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. (2015 – US$16; 2014 – US$20)	2017	22	4.0	%	23	4.0	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes3
U.S. (2015 – US$69; 2014 – US$90)	2018	96	6.1	%	105	6.1	%
		31,584			24,757
Less: Current portion of Long-term debt		2,547			1,797
		29,037			22,960

¹  Interest rates are the effective interest rates except for those pertaining to Long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.

²  Debentures issued by NGTL in the amount of $225 million have retraction provisions that entitle the holders to periodically require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made in 2015 or 2014.

³  Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

Principal Repayments

At December 31, 2015, principal repayments on the Long-term debt of the Company for the next five years are approximately as follows:

(millions of Canadian $)	2016	2017	2018	2019	2020
Principal repayments on Long-term debt	2,547	2,150	3,379	1,228	1,801

Long-Term Debt Issued

The Company issued Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)
Company	Issue date	Type	Maturity date	Amount	Interest Rate
TRANSCANADA PIPELINES LIMITED
	November 2015	Senior Unsecured Notes	November 2017	US 1,000	1.625	%
	October 2015	Medium-Term Notes	November 2041	400	4.55	%
	July 2015	Medium-Term Notes	July 2025	750	3.30	%
	March 2015	Senior Unsecured Notes	March 2045	US 750	4.60	%
	January 2015	Senior Unsecured Notes	January 2018	US 500	1.875	%
	January 2015	Senior Unsecured Notes	January 2018	US 250	Floating
	February 2014	Senior Unsecured Notes	March 2034	US 1,250	4.63	%
	October 2013	Senior Unsecured Notes	October 2023	US 625	3.75	%
	October 2013	Senior Unsecured Notes	October 2043	US 625	5.00	%
	July 2013	Senior Unsecured Notes	June 2016	US 500	Floating
	July 2013	Medium-Term Notes	July 2023	450	3.69	%
	July 2013	Medium-Term Notes	November 2041	300	4.55	%
	January 2013	Senior Unsecured Notes	January 2016	US 750	0.75	%
TC PIPELINES, LP
	September 2015	Unsecured Term Loan	October 2018	US 170	Floating
	March 2015	Senior Unsecured Notes	March 2025	US 350	4.375	%
	July 2013	Unsecured Term Loan Facility	July 2018	US 500	Floating
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Unsecured Term Loan	June 2019	US 75	Floating

Long-Term Debt Retired

The Company retired Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)
Company	Retirement date	Type	Amount	Interest Rate
TRANSCANADA PIPELINES LIMITED
	August 2015	Debentures	150	11.90	%
	June 2015	Senior Unsecured Notes	US 500	3.40	%
	March 2015	Senior Unsecured Notes	US 500	0.875	%
	January 2015	Senior Unsecured Notes	US 300	4.875	%
	June 2014	Debentures	125	11.10	%
	February 2014	Medium-Term Notes	300	5.05	%
	January 2014	Medium-Term Notes	450	5.65	%
	August 2013	Senior Unsecured Notes	US 500	5.05	%
	June 2013	Senior Unsecured Notes	US 350	4.00	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Senior Unsecured Notes	US 75	5.09	%
NOVA GAS TRANSMISSION LTD.
	June 2014	Debentures	53	11.20	%

Interest Expense

Interest expense over the three years ended December 31 was as follows:

year ended December 31	2015		2014		2013
(millions of Canadian $)
Interest on Long-term debt	1,487		1,317		1,216
Interest on Junior subordinated notes (Note 17)	116		70		65
Interest on short-term debt	44		52		73
Capitalized interest	(280	)	(259	)	(287	)
Amortization and other financial charges1	31		55		(21	)
	1,398		1,235		1,046

¹  Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates.

The Company made interest payments of $1,295 million in 2015 (2014 – $1,160 million; 2013 – $1,047 million) on Long-term debt, Junior subordinated notes and Notes payable, net of interest capitalized.

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JUNIOR SUBORDINATED NOTES

12 Months Ended

Dec. 31, 2015

Junior Subordinated Notes [Abstract]

JUNIOR SUBORDINATED NOTES

JUNIOR SUBORDINATED NOTES

		2015			2014
Outstanding loan amount	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
U.S. (2015 and 2014 – US$1,000)1	2067	1,384	6.4	%	1,160	6.5	%
U.S. (2015 – US$750)1	2075	1,038	5.3	%	—	—
		2,422			1,160

¹  The Junior subordinated notes are subordinated in right of payment to existing and future senior indebtedness or other obligations of TCPL.

Junior subordinated notes of US$1.0 billion mature in May 2067 and bear interest at 6.35 per cent per annum until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three-month London Interbank Offered Rate (LIBOR) plus 2.21 per cent. The Company has the option to defer payment of interest for periods of up to 10 years without giving rise to a default or permitting acceleration of payment under the terms of the Junior subordinated notes, however, the Company would be prohibited from paying dividends during any such deferral period. The Junior subordinated notes are callable at the Company's option at any time on or after May 15, 2017 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. The Junior subordinated notes are callable earlier, in whole or in part, upon the occurrence of certain events and at the Company's option at an amount equal to the greater of 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with their terms.

In May 2015, TransCanada Trust (the Trust), a financing trust subsidiary wholly-owned by TCPL, issued US$750 million Trust Notes - Series 2015-A (Trust Notes) to third party investors at a fixed interest rate of 5.625 per cent for the first 10 years converting to a floating rate thereafter. All of the proceeds of the issuance by the Trust were loaned to TCPL for US$750 million of Junior subordinated notes of TCPL at a rate of 5.875 per cent, including a 0.25 per cent administration charge. The rate will reset commencing May 2025 until May 2045 to the three month LIBOR plus 3.778 per cent per annum; from May 2045 to May 2075 the interest rate will reset to the three month LIBOR plus 4.528 per cent per annum. The Junior subordinated notes of TCPL are callable at TCPL's option at any time on or after May 20, 2025 at 100 per cent of the principal amount plus accrued and unpaid interest to the date of redemption. While the obligations of the Trust are fully and unconditionally guaranteed by TCPL on a subordinated basis, the Trust is not consolidated in TCPL's financial statements because TCPL does not have a variable interest in the Trust and the only substantive assets of the Trust are receivables from TCPL.

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

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NON-CONTROLLING INTERESTS

12 Months Ended

Dec. 31, 2015

Noncontrolling Interest [Abstract]

NON-CONTROLLING INTERESTS

NON-CONTROLLING INTERESTS

The Company's Non-controlling interests included in the Consolidated balance sheet are as follows:

at December 31	2015	2014
(millions of Canadian $)
Non-controlling interest in TC PipeLines, LP	1,590	1,479
Non-controlling interest in PNGTS	127	104
	1,717	1,583

The Company's Non-controlling interests included in the Consolidated statement of income are as follows:

year ended December 31	2015		2014	2013
(millions of Canadian $)
Non-controlling interest in TC PipeLines, LP	(13	)	136	93
Non-controlling interest in PNGTS	19		15	12
	6		151	105

During 2015, the Non-controlling interest in TC PipeLines, LP increased from 71.7 per cent to 72.0 per cent due to periodic issuances of common units in TC PipeLines, LP to non-controlling interests. In 2014, the Non-controlling interest in TC PipeLines, LP ranged between 71.1 per cent and 71.7 per cent and, in 2013, between 66.7 per cent and 71.1 per cent.

At December 31, 2015, TC PipeLines, LP recorded an impairment charge of US$199 million related to its equity investment in Great Lakes. The Non-controlling interest's share of this charge was US$143 million and is included in the $13 million Non-controlling interest in TC PipeLines, LP in the Consolidated statement of income.

The Non-controlling interest in PNGTS as at December 31, 2015 represented the 38.3 per cent interest held by third parties (2014 and 2013 – 38.3 per cent).

In 2015, TCPL received fees of $4 million from TC PipeLines, LP (2014 and 2013 – $3 million) and $11 million from PNGTS (2014 – $8 million; 2013 – $7 million) for services provided.

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COMMON SHARES

12 Months Ended

Dec. 31, 2015

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

COMMON SHARES

COMMON SHARES

	Number of Shares	Amount
	(thousands)	(millions of Canadian $)
Outstanding at January 1, 2013	738,381	14,306
Issuance of common shares for cash	18,733	899
Outstanding at December 31, 2013	757,114	15,205
Issuance of common shares for cash	22,365	1,115
Outstanding at December 31, 2014	779,479	16,320
Outstanding at December 31, 2015	779,479	16,320

Common Shares Issued and Outstanding

The Company is authorized to issue an unlimited number of common shares without par value.

Restrictions on Dividends

Certain terms of the Company's debt instruments can limit the amount of dividends the Company can pay on preferred and common shares. At December 31, 2015 these terms limit the company from paying dividends in excess of $4.1 billion (2014 – $8.7 billion; 2013 – $1.3 billion). Under the agreements, TCPL can adjust this limit throughout the year if required, at is sole discretion, without incurring significant costs.

Stock Option Plan

Certain key employees, including officers, are granted stock options from TransCanada to purchase common shares at the market price on the grant date. Stock options vest equally over three years, beginning on the first anniversary of the grant date, and expire after seven years.

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

year ended December 31	2015		2014		2013
Expected life (years)	5.8		6.0		6.0
Interest rate	1.1	%	1.8	%	1.7	%
Volatility1	18	%	17	%	18	%
Dividend yield	3.7	%	3.8	%	3.7	%
Forfeiture rate	5	%	5	%	15	%

¹  Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

The amount expensed for stock options, with a corresponding increase in Additional paid-in capital, was $11 million in 2015 (2014 – $9 million; 2013 – $6 million).

The following table summarizes additional stock option information:

year ended December 31	2015	2014	2013
(millions of Canadian $, unless otherwise noted)
Total intrinsic value of options exercised	37	68	25
Fair value of options that have vested	91	95	64
Total options vested	2.0 million	1.7 million	1.3 million

As at December 31, 2015, the aggregate intrinsic value of the total options exercisable was $23 million and the total intrinsic value of options outstanding was $23 million.

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PREFERRED SHARES

12 Months Ended

Dec. 31, 2015

Preferred Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

PREFERRED SHARES

PREFERRED SHARES

In March 2014, TCPL redeemed all of the 4 million outstanding Series Y preferred shares at a redemption price of $50 per share for a gross payment of $200 million.

In October 2013, TCPL redeemed all of the 4 million outstanding Series U preferred shares at a redemption price of $50 per share for a gross payment of $200 million.

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OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMMULATED OTHER COMPREHENSIVE LOSS

OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS

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

year ended December 31, 2015	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	798		15		813
Change in fair value of net investment hedges	(505	)	133		(372	)
Change in fair value of cash flow hedges	(92	)	35		(57	)
Reclassification to net income of gains and losses on cash flow hedges	144		(56	)	88
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	74		(23	)	51
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	41		(9	)	32
Other comprehensive income on equity investments	62		(15	)	47
Other Comprehensive Income	522		80		602

year ended December 31, 2014	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	462		55		517
Change in fair value of net investment hedges	(373	)	97		(276	)
Change in fair value of cash flow hedges	(118	)	49		(69	)
Reclassification to net income of gains and losses on cash flow hedges	(95	)	40		(55	)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(146	)	44		(102	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	25		(7	)	18
Other comprehensive loss on equity investments	(272	)	68		(204	)
Other Comprehensive Loss	(517	)	346		(171	)

year ended December 31, 2013	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	269		114		383
Change in fair value of net investment hedges	(323	)	84		(239	)
Change in fair value of cash flow hedges	121		(50	)	71
Reclassification to net income of gains and losses on cash flow hedges	60		(19	)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	96		(29	)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	34		(11	)	23
Other comprehensive income on equity investments	313		(79	)	234
Other Comprehensive Income	570		10		580

The changes in AOCI by component are as follows:

	Currency Translation Adjustments		Cash Flow Hedges		Pension and Other Post-Retirement Benefit Plan Adjustments		Equity Investments		Total1
AOCI balance at January 1, 2013	(707	)	(116	)	(287	)	(338	)	(1,448	)
Other comprehensive income before reclassifications2	78		71		67		219		435
Amounts reclassified from accumulated other comprehensive loss	—		41		23		15		79
Net current period other comprehensive income	78		112		90		234		514
AOCI balance at December 31, 2013	(629	)	(4	)	(197	)	(104	)	(934	)
Other comprehensive income/(loss) before reclassifications2	111		(69	)	(102	)	(206	)	(266	)
Amounts reclassified from accumulated other comprehensive loss	—		(55	)	18		2		(35	)
Net current period other comprehensive income/(loss)	111		(124	)	(84	)	(204	)	(301	)
AOCI balance at December 31, 2014	(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income/(loss) before reclassifications2	135		(57	)	51		33		162
Amounts reclassified from accumulated other comprehensive loss3	—		88		32		14		134
Net current period other comprehensive income	135		31		83		47		296
AOCI balance at December 31, 2015	(383	)	(97	)	(198	)	(261	)	(939	)

¹  All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

²  Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $306 million in 2015 (2014 – $130 million gains; 2013 – $66 million gains).

³  Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $83 million ($51 million, net of tax) at December 31, 2015. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

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

	Amounts Reclassified From Accumulated Other Comprehensive Loss1						Affected Line Item in the Consolidated Statement of Income
year ended December 31	2015		2014		2013
(millions of Canadian $)
Cash flow hedges
Commodities	(128	)	111		(44	)	Revenues (Energy)
Interest	(16	)	(16	)	(16	)	Interest expense
	(144	)	95		(60	)	Total before tax
	56		(40	)	19		Income tax expense/(recovery)
	(88	)	55		(41	)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial loss and past service cost	(41	)	(25	)	(34	)	2
	9		7		11		Income tax recovery
	(32	)	(18	)	(23	)	Net of tax
Equity investments
Equity income	(19	)	(2	)	(20	)	Income from equity investments
	5		—		5		Income tax recovery
	(14	)	(2	)	(15	)	Net of tax

¹  All amounts in parentheses indicate expenses to the Consolidated statement of income.

²  These Accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 22 for further information.

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EMPLOYEE POST-RETIREMENT BENEFITS

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

EMPLOYEE POST-RETIREMENT BENEFITS

EMPLOYEE POST-RETIREMENT BENEFITS

The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining service life of employees, which is approximately nine years at December 31, 2015 (2014 and 2013 – nine years).

The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Net actuarial gains or losses are amortized out of AOCI over the expected average remaining life expectancy of former employees, which was approximately 12 years at December 31, 2015 (2014 – 12 years; 2013 – 11 years). In 2015, the Company expensed $41 million (2014 – $37 million; 2013 – $29 million) for the savings and DC Plans.

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

year ended December 31	2015	2014	2013
(millions of Canadian $)
DB Plans	96	73	79
Other post-retirement benefit plans	6	6	6
Savings and DC Plans	41	37	29
	143	116	114

Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. As such, in addition to the cash contributions noted above, the Company provided a $33 million letter of credit to the Canadian DB Plan in 2015 (2014 – $47 million; 2013 – $59 million), resulting in a total of $214 million provided to the Canadian DB Plan under letters of credit at December 31, 2015.

The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2015 and the next required valuation will be as at January 1, 2016.

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Change in Benefit Obligation1
Benefit obligation – beginning of year	2,658		2,224		216		191
Service cost	108		85		3		2
Interest cost	115		113		10		10
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Actuarial (gain)/loss	(57	)	302		(11	)	14
Foreign exchange rate changes	81		32		14		6
Benefit obligation – end of year	2,780		2,658		225		216
Change in Plan Assets
Plan assets at fair value – beginning of year	2,398		2,152		39		35
Actual return on plan assets	160		246		(1	)	2
Employer contributions2	96		73		6		6
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Foreign exchange rate changes	62		25		8		3
Plan assets at fair value – end of year	2,591		2,398		45		39
Funded Status – Plan Deficit	(189	)	(260	)	(180	)	(177	)

¹  The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation

²  Excludes $214 million in letters of credit provided to the Canadian DB Plans for funding purposes (2014 – $181 million).

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Intangible and other assets (Note 11)	—		—		18		14
Accounts payable and other	—		—		(7	)	(7	)
Other long-term liabilities (Note 14)	(189	)	(260	)	(191	)	(184	)
	(189	)	(260	)	(180	)	(177	)

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Projected benefit obligation1	(2,780	)	(2,658	)	(198	)	(191	)
Plan assets at fair value	2,591		2,398		—		—
Funded Status – Plan Deficit	(189	)	(260	)	(198	)	(191	)

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

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

at December 31	2015		2014
(millions of Canadian $)
Accumulated benefit obligation	(2,600	)	(2,437	)
Plan assets at fair value	2,591		2,398
Funded Status – Plan Deficit	(9	)	(39	)

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

at December 31	2015		2014
(millions of Canadian $)
Accumulated benefit obligation	(807	)	(715	)
Plan assets at fair value	680		597
Funded Status – Plan Deficit	(127	)	(118	)

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

	Percentage of Plan Assets				Target Allocations
at December 31	2015		2014		2015
Debt securities	34	%	31	%	25% to 35%
Equity securities	66	%	69	%	50% to 70%
Alternatives	—		—		5 % to 15%
	100	%	100	%

Debt and equity securities include the Company's debt and common shares as follows:

at December 31			Percentage of Plan Assets
(millions of Canadian $)	2015	2014	2015		2014
Debt securities	2	1	0.1	%	0.1	%
Equity securities	4	1	0.1	%	0.1	%

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

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

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

at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2015	2014	2015	2014	2015	2014	2015	2014	2015	2014
Asset Category
Cash and Cash Equivalents	44	20	2	—	—	—	46	20	2	1
Equity Securities:
Canadian	317	361	147	142	—	—	464	503	17	21
U.S.	589	516	40	35	—	—	629	551	24	23
International	38	218	300	147	—	—	338	365	13	15
Global	—	—	154	141	—	—	154	141	6	6
Emerging	7	7	143	80	—	—	150	87	6	3
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	206	218	—	—	206	218	8	9
Provincial	—	—	202	180	—	—	202	180	8	7
Municipal	—	—	7	7	—	—	7	7	—	—
Corporate	—	—	113	76	—	—	113	76	4	3
U.S. Bonds:
State	—	—	50	47	—	—	50	47	2	2
Corporate	—	—	57	59	—	—	57	59	2	2
International:
Corporate	—	—	25	14	—	—	25	14	1	1
Mortgage backed	—	—	58	39	—	—	58	39	2	2
Other Investments:
Private equity funds	—	—	—	—	14	13	14	13	—	—
Funds held on deposit	123	117	—	—	—	—	123	117	5	5
	1,118	1,239	1,504	1,185	14	13	2,636	2,437	100	100

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

(millions of Canadian $, pre-tax)	Private Equity Funds
Balance at December 31, 2013	18
Purchases and sales	(7	)
Realized and unrealized gains	2
Balance at December 31, 2014	13
Purchases and sales	(1	)
Realized and unrealized gains	2
Balance at December 31, 2015	14

The Company's expected funding contributions in 2016 are approximately $70 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $37 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $33 million letter of credit to the Canadian DB Plan for the funding of solvency requirements.

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

(millions of Canadian $)	Pension Benefits	Other Post- Retirement Benefits
2016	129	8
2017	133	9
2018	138	9
2019	142	9
2020	146	10
2021 to 2025	808	51

The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2015. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.

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

	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2015		2014		2015		2014
Discount rate	4.20	%	4.15	%	4.40	%	4.20	%
Rate of compensation increase	0.50	%	3.15	%	—	%	—	%

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

	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2015		2014		2013		2015		2014		2013
Discount rate	4.15	%	4.95	%	4.35	%	4.20	%	5.00	%	4.35	%
Expected long-term rate of return on plan assets	6.95	%	6.90	%	6.70	%	4.60	%	4.60	%	4.60	%
Rate of compensation increase	3.15	%	3.15	%	3.15	%	—		—		—

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

A seven per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2016 measurement purposes. The rate was assumed to decrease gradually to five per cent by 2021 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:

(millions of Canadian $)	Increase	Decrease
Effect on total of service and interest cost components	1	(1	)
Effect on post-retirement benefit obligation	14	(12	)

The Company's net benefit cost recognized is as follows:

at December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2013		2015		2014		2013
Service cost	108		85		84		3		2		2
Interest cost	115		113		96		10		10		7
Expected return on plan assets	(155	)	(139	)	(120	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	35		21		30		3		2		2
Amortization of past service cost	2		2		2		1		—		—
Amortization of regulatory asset	23		18		30		1		1		1
Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
Net Benefit Cost Recognized	128		100		122		18		15		12

Pre-tax amounts recognized in AOCI were as follows:

	2015		2014		2013
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)
Net loss	247	28	348	39	236	32
Prior service cost	—	—	2	1	3	1
	247	28	350	40	239	33

The estimated net loss for the DB Plans and for the other post-retirement benefit plans that will be amortized from AOCI into net periodic benefit cost in 2016 is $21 million and $3 million respectively.

Pre-tax amounts recognized in OCI were as follows:

	2015				2014				2013
at December 31	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
(millions of Canadian $)
Amortization of net loss from AOCI to OCI	(34	)	(4	)	(21	)	(2	)	(30	)	(2	)
Amortization of prior service costs from AOCI to OCI	(2	)	(1	)	(2	)	—		(2	)	—
Funded status adjustment	(67	)	(7	)	137		9		(96	)	—
	(103	)	(12	)	114		7		(128	)	(2	)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

12 Months Ended

Dec. 31, 2015

Risk Management and Financial Instruments [Abstract]

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Risk Management Overview

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

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

Market Risk

The Company constructs and invests in energy infrastructure projects, purchases and sells commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds.

The Company uses derivatives as part of its overall risk management strategy to assist in managing the exposure to market risk that results from these activities. These derivative contracts may consist of the following:

• Forwards and futures contracts – contractual agreements to purchase or sell a specific financial instrument or commodity at a specified price and date in the future. TCPL enters into foreign exchange and commodity forwards and futures to manage the impact of changes in foreign exchange rates and commodity prices.

• Swaps – contractual agreements between two parties to exchange streams of payments over time according to specified terms. The Company enters into interest rate, cross-currency and commodity swaps to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

• Options – contractual agreements that convey the right, but not the obligation of the purchaser to buy or sell a specific amount of a financial instrument or commodity at a fixed price, either at a fixed date or at any time within a specified period. The Company enters into option agreements to manage the impact of changes in interest rates, foreign exchange rates and commodity prices.

Commodity Price Risk

The Company is exposed to commodity price movements as part of its normal business operations. A number of strategies are used to manage these exposures, including the following:

• Subject to its overall risk management strategy, the Company commits a portion of its expected power supply to fixed-price medium-term or long-term sales contracts, while reserving an amount of unsold supply to manage operational and price risks in its asset portfolio.

• The Company purchases a portion of the natural gas required for its power plants or enters into contracts that base the sale price of electricity on the cost of natural gas, effectively locking in a margin.

• The Company's power sales commitments are fulfilled through power generation or through purchased contracts, thereby reducing the Company's exposure to fluctuating commodity prices.

• The Company enters into offsetting or back-to-back positions using derivative instruments to manage price risk exposure in power and natural gas commodities created by certain fixed and variable pricing arrangements for different pricing indices and delivery points.

Natural Gas Storage Commodity Price Risk

TCPL manages its exposure to seasonal natural gas price spreads in its non-regulated Natural Gas Storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TCPL simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Unrealized gains and losses on fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement.

Foreign Exchange and Interest Rate Risk

Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates.

A portion of TCPL's earnings from its Natural Gas Pipelines, Liquids Pipelines and Energy segments are generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TCPL's net income. As the Company’s U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases; some of this foreign exchange impact is partially offset by interest expense on U.S. dollar-denominated debt of the Company's foreign operations and by using foreign exchange derivatives.

The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to other U.S. dollar-denominated transactions including those that may arise on some of the Company’s regulated assets. The realized gains and losses on these derivatives are deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers.

TCPL has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk.

Net Investment in Foreign Operations

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

U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge

at December 31	2015	2014
(millions of Canadian $, unless otherwise noted)
Carrying value	23,000 (US 16,600)	17,000 (US 14,700)
Fair value	23,800 (US 17,200)	19,000 (US 16,400)

Derivatives Designated as a Net Investment Hedge

	2015				2014
at December 31	Fair Value1		Notional or Principal Amount		Fair Value1		Notional or Principal Amount
(millions of Canadian $, unless otherwise noted)
U.S. dollar cross-currency interest rate swaps (maturing 2016 to 2019)2	(730	)	US	3,150	(431	)	US	2,900
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	50		US	1,800	(28	)	US	1,400
	(680	)	US	4,950	(459	)	US	4,300

¹  Fair values equal carrying values.

²  In 2015, net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements are included in Interest expense.

Counterparty Credit Risk

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

The Company manages its exposure to this potential loss by using recognized credit management techniques, including:

• Dealing with creditworthy counterparties – a significant amount of the Company’s credit exposure is with investment grade counterparties or, if not, is generally partially supported by financial assurances from investment grade parties

• Setting limits on the amount TCPL can transact with any one counterparty – the Company monitors and manages the concentration of risk exposure with any one counterparty, and reduces the exposure when necessary and when it is allowed under the terms of the contracts

• Using contract netting arrangements and obtaining financial assurances such as guarantees, letters of credit or cash when deemed necessary.

There is no guarantee that these techniques will protect the Company from material losses.

TCPL's maximum counterparty credit exposure with respect to financial instruments at December 31, 2015, without taking into account security held, consisted of accounts receivable, available for sale assets recorded at fair value, the fair value of derivative assets, notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2015, there were no significant amounts past due or impaired, and there were no significant credit losses during the year.

The Company had a credit risk concentration due from a counterparty of $248 million (US$179 million) and $258 million (US$222 million) at December 31, 2015 and 2014, respectively. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.

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

Fair Value of Non-Derivative Financial Instruments

The fair value of the Company's Notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of Long-term debt and Junior subordinated notes is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.

Available for sale assets are recorded at fair value which is calculated using quoted market prices where available. Certain non-derivative financial instruments included in Cash and cash equivalents, Accounts receivable, Due from affiliates, Intangible and other assets, Notes payable, Accounts payable and other, Due to affiliates, Accrued interest and Other long-term liabilities have carrying amounts that approximate their fair value due to the nature of the item or the short time to maturity and would also be classified in Level II of the fair value hierarchy.

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

Balance Sheet Presentation of Non-Derivative Financial Instruments

The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy:

	2015				2014
at December 31	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions of Canadian $)
Notes receivable1	214		265		213		263
Current and Long-term debt2,3 (Note 16)	(31,584	)	(34,309	)	(24,757	)	(28,713	)
Junior subordinated notes (Note 17)	(2,422	)	(2,011	)	(1,160	)	(1,157	)
	(33,792	)	(36,055	)	(25,704	)	(29,607	)

¹  Notes receivable are included in Other current assets and Intangible and other assets on the Consolidated balance sheet.

²  Long-term debt is recorded at amortized cost, except for US$850 million (2014 – US$400 million) that is attributed to hedged risk and recorded at fair value.

³  Consolidated Net income in 2015 included gains of $2 million (2014 – losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of Long-term debt at December 31, 2015 (2014 – US$400 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Available for Sale Assets Summary

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

	2015		2014
at December 31	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2
(millions of Canadian $)
Fair values
Fixed income securities (maturing within 5 years)	—	90	—	75
Fixed income securities (maturing after 10 years)	261	—	—	—
	261	90	—	75

¹  Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company would record these gains and losses as regulatory assets or liabilities. In 2015 and 2014, there were no net realized or unrealized gains or losses on LMCI restricted investments.

²  Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. In 2015 and 2014, there were no net realized or unrealized gains or losses on other restricted investments.

Fair Value of Derivative Instruments

The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of commodity derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. The fair value of options has been calculated using the Black-Scholes pricing model. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.

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

Balance Sheet Presentation of Derivative Instruments

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2015 is as follows:

at December 31, 2015	Cash Flow Hedges1		Fair Value Hedges1		Net Investment Hedges1		Held for Trading1		Total Fair Value of Derivative Instruments
(millions of Canadian $)
Other current assets (Note 5)
Commodities2	46		—		—		326		372
Foreign exchange	—		—		65		2		67
Interest rate	—		1		—		2		3
	46		1		65		330		442
Intangible and other assets (Note 11)
Commodities2	11		—		—		126		137
Foreign exchange	—		—		29		—		29
Interest rate	—		2		—		—		2
	11		2		29		126		168
Total Derivative Assets	57		3		94		456		610
Accounts payable and other (Note 13)
Commodities2	(112	)	—		—		(443	)	(555	)
Foreign exchange	—		—		(313	)	(54	)	(367	)
Interest rate	(1	)	(1	)	—		(2	)	(4	)
	(113	)	(1	)	(313	)	(499	)	(926	)
Other long-term liabilities (Note 14)
Commodities2	(31	)	—		—		(131	)	(162	)
Foreign exchange	—		—		(461	)	—		(461	)
Interest rate	(1	)	(1	)	—		—		(2	)
	(32	)	(1	)	(461	)	(131	)	(625	)
Total Derivative Liabilities	(145	)	(2	)	(774	)	(630	)	(1,551	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power and natural gas.

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2014 is as follows:

at December 31, 2014	Cash Flow Hedges1		Fair Value Hedges1	Net Investment Hedges1		Held for Trading1		Total Fair Value of Derivative Instruments
(millions of Canadian $)
Other current assets (Note 5)
Commodities2	39		—	—		359		398
Foreign exchange	—		—	5		1		6
Interest rate	—		2	—		3		5
	39		2	5		363		409
Intangible and other assets (Note 11)
Commodities2	18		—	—		72		90
Foreign exchange	—		—	1		—		1
Interest rate	—		1	—		1		2
	18		1	1		73		93
Total Derivative Assets	57		3	6		436		502
Accounts payable and other (Note 13)
Commodities2	(136	)	—	—		(422	)	(558	)
Foreign exchange	—		—	(155	)	(32	)	(187	)
Interest rate	(1	)	—	—		(3	)	(4	)
	(137	)	—	(155	)	(457	)	(749	)
Other long-term liabilities (Note 14)
Commodities2	(27	)	—	—		(72	)	(99	)
Foreign exchange	—		—	(310	)	—		(310	)
Interest rate	(1	)	—	—		(1	)	(2	)
	(28	)	—	(310	)	(73	)	(411	)
Total Derivative Liabilities	(165	)	—	(465	)	(530	)	(1,160	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power and natural gas.

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

Notional and Maturity Summary

The following tables present the maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations:

at December 31, 2015	Power	Natural Gas	Foreign Exchange	Interest
Purchases1	70,331	133	—	—
Sales1	54,382	70	—	—
Millions of dollars	—	—	US 1,476	US 1,100
Maturity dates	2016–2020	2016–2020	2016	2016–2019

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

at December 31, 2014	Power	Natural Gas	Foreign Exchange	Interest
Purchases1	53,217	60	—	—
Sales1	39,429	38	—	—
Millions of dollars	—	—	US 1,374	US 650
Maturity dates	2015–2019	2015–2020	2015	2015–2018

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

Unrealized and Realized (Losses)/Gains of Derivative Instruments

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

year ended December 31	2015		2014
(millions of Canadian $)
Derivative instruments held for trading1
Amount of unrealized losses in the year
Commodities	(37	)	(40	)
Foreign exchange	(21	)	(20	)
Amount of realized losses in the year
Commodities	(151	)	(28	)
Foreign exchange	(112	)	(28	)
Derivative instruments in hedging relationships2,3
Amount of realized (losses)/gains in the year
Commodities	(179	)	130
Interest rate	8		4

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 derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively.

²  In 2015, net realized gains on fair value hedges were $11 million (2014 – gains of $7 million) and were included in Interest expense.

³  In 2015 and 2014, 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.

Derivatives in Cash Flow Hedging Relationships

The components of OCI (Note 21) related to derivatives in cash flow hedging relationships are as follows:

year ended December 31	2015		2014
(millions of Canadian $, pre-tax)
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Commodities	(92	)	(128	)
Foreign exchange	—		10
	(92	)	(118	)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net income (effective portion)1
Commodities2	128		(111	)
Interest rate3	16		16
	144		(95	)
Losses on derivative instruments recognized in Net income (ineffective portion)
Commodities2	—		(13	)

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

²  Reported within Revenues on the Consolidated statement of income.

³  Reported within Interest expense on the Consolidated statement of income.

Offsetting of Derivative Instruments

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

at December 31, 2015	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
	(1,551	)	512		(1,039	)

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

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2014:

at December 31, 2014	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	488		(387	)	101
Foreign exchange	7		(7	)	—
Interest rate	7		(1	)	6
	502		(395	)	107
Derivative - Liability
Commodities	(657	)	387		(270	)
Foreign exchange	(497	)	7		(490	)
Interest rate	(6	)	1		(5	)
	(1,160	)	395		(765	)

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

With respect to the derivative instruments presented above as at December 31, 2015, the Company had provided cash collateral of $482 million (2014 – $459 million) and letters of credit of $41 million (2014 – $26 million) to its counterparties. The Company held nil (2014 – $1 million) in cash collateral and $2 million (2014 – $1 million) in letters of credit from counterparties on asset exposures at December 31, 2015.

Credit Risk Related Contingent Features of Derivative Instruments

Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade.

Based on contracts in place and market prices at December 31, 2015, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $32 million (2014 – $15 million), for which the Company has provided collateral in the normal course of business of nil (2014 – nil). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2015, the Company would have been required to provide additional collateral of $32 million (2014 – $15 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.

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

Fair Value Hierarchy

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

Levels	How fair value has been determined
Level I	Quoted prices in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level II	Valuation based on the extrapolation of inputs, other than quoted prices included within Level I, for which all significant inputs are observable directly or indirectly. Inputs include published exchange rates, interest rates, interest rate swap curves, yield curves and broker quotes from external data service providers. This category includes interest rate and foreign exchange derivative assets and liabilities where fair value is determined using the income approach and commodity derivatives where fair value is determined using the market approach. Transfers between Level I and Level II would occur when there is a change in market circumstances.
Level III	Valuation of assets and liabilities are measured using a market approach based on extrapolation of inputs that are unobservable or where observable data does not support a significant portion of the fair value of the derivatives. This category includes long-dated commodity transactions in certain markets where liquidity is low and inputs may include long-term broker quotes. Valuation of options is based on the Black-Scholes pricing model. Long-term electricity prices may also be estimated using a third-party modeling tool which takes into account physical operating characteristics of generation facilities in the markets in which the Company operates. Model inputs include market fundamentals such as fuel prices, power supply additions and retirements, power demand, seasonal hydro conditions and transmission constraints. Long-term North American natural gas prices might be estimated on a view of future natural gas supply and demand, as well as exploration and development costs. Significant decreases in fuel prices or demand for electricity or natural gas, increases in the supply of electricity or natural gas, or a small number of transactions in markets with lower liquidity are expected to or may result in a lower fair value measurement of contracts included in Level III. Assets and liabilities measured at fair value can fluctuate between Level II and Level III depending on the proportion of the value of the contract that extends beyond the time frame for which significant inputs are considered to be observable. As contracts near maturity and observable market data becomes available, they are transferred out of Level III and into Level II.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015, are categorized as follows:

at December 31, 2015	Quoted Prices in Active Markets Level I1		Significant Other Observable Inputs Level II1		Significant Unobservable Inputs Level III1		Total
(millions of Canadian $)
Derivative Instrument Assets:
Commodities	34		462		13		509
Foreign exchange	—		96		—		96
Interest rate	—		5		—		5
Derivative Instrument Liabilities:
Commodities	(102	)	(611	)	(4	)	(717	)
Foreign exchange	—		(828	)	—		(828	)
Interest rate	—		(6	)	—		(6	)
	(68	)	(882	)	9		(941	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:

at December 31, 2014	Quoted Prices in Active Markets Level I1		Significant Other Observable Inputs Level II1		Significant Unobservable Inputs Level III1		Total
(millions of Canadian $)
Derivative Instrument Assets:
Commodities	40		441		7		488
Foreign exchange	—		7		—		7
Interest rate	—		7		—		7
Derivative Instrument Liabilities:
Commodities	(86	)	(568	)	(3	)	(657	)
Foreign exchange	—		(497	)	—		(497	)
Interest rate	—		(6	)	—		(6	)
	(46	)	(616	)	4		(658	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2014.

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

(millions of Canadian $, pre-tax)	2015		2014
Balance at beginning of year	4		1
Transfers out of Level III	5		—
Total gains included in Net income	3		3
Sales	(2	)	—
Settlements	(1	)	—
Balance at end of year1	9		4

¹  Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2015 of $7 million (2014 – $3 million).

A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $2 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2015.

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CHANGES IN OPERATING WORKING CAPITAL

12 Months Ended

Dec. 31, 2015

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL

CHANGES IN OPERATING WORKING CAPITAL

year ended December 31	2015		2014		2013
(millions of Canadian $)
Increase in Accounts receivable	(20	)	(205	)	(60	)
Increase in Inventories	(3	)	(27	)	(30	)
(Increase)/decrease in Other current assets	(268	)	(386	)	40
(Decrease)/increase in Accounts payable and other	(159	)	393		(291	)
Increase in Accrued interest	91		36		7
Increase in Operating Working Capital	(359	)	(189	)	(334	)

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ACQUISITIONS AND DISPOSITIONS

12 Months Ended

Dec. 31, 2015

Business Combinations [Abstract]

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

Natural Gas Pipelines

TC PipeLines, LP

On April 1, 2015, TCPL completed the sale of its remaining 30 per cent interest in Gas Transmission Northwest LLC (GTN) to TC PipeLines, LP for an aggregate purchase price of US$457 million. Proceeds were comprised of US$264 million in cash, the assumption of US$98 million in proportional GTN LLC debt and US$95 million of new Class B units of TC PipeLines, LP.

On October 1, 2014, TCPL completed the sale of its remaining 30 per cent interest in Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$215 million.

In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at a price of US$43.85 per unit, resulting in gross proceeds of approximately US$388 million and net proceeds of US$373 million after unit issuance costs. TCPL contributed approximately US$8 million to maintain its two per cent general partnership interest and did not purchase any other units. Upon completion of this offering, TCPL's ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent and an after-tax dilution gain of $29 million ($47 million pre-tax) was recorded in Additional paid-in capital.

In July 2013, TCPL completed the sale of a 45 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million for the assumption of 45 per cent of GTN LLC debt outstanding, plus normal closing adjustments. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.

Gas Pacifico/INNERGY

On November 26, 2014, TCPL sold its 30 per cent equity investments in Gas Pacifico and INNERGY for aggregate gross proceeds of $9 million and recognized a gain of $9 million ($8 million after-tax).

Energy

Bruce Power

On December 3, 2015, TCPL exercised its option to acquire an additional 14.89 per cent ownership interest in Bruce B from the Ontario Municipal Employees Retirement System (OMERS) for $236 million, increasing its ownership interest to 46.5 per cent. The difference between the purchase price and the underlying carrying value of Bruce B is primarily related to the estimated fair value of the amended agreement with Ontario's Independent Electricity System Operator to extend the operating life of the Bruce Power facility to 2064. On December 4, 2015, Bruce B and Bruce A merged to form a single limited partnership (Bruce Power). This merger was accounted for as a transaction between entities under common control whereby the assets and liabilities of Bruce A and Bruce B were combined at their carrying values. Upon completion of the merger, TCPL applied equity accounting to its 48.5 per cent ownership interest in Bruce Power. Prior to the acquisition, TCPL applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B.

Ontario Solar

As part of a purchase agreement with Canadian Solar Solutions Inc. signed in 2011, TCPL completed the acquisition of four Ontario solar facilities for $241 million in 2014. In 2013, TCPL completed the acquisition of four solar facilities for $216 million. The Company's total investment in the eight solar facilities is $457 million. All power produced by the solar facilities is sold under 20-year PPAs with the Ontario Power Authority.

Cancarb

On April 15, 2014, TCPL sold Cancarb Limited and its related power generation for aggregate gross proceeds of $190 million and recognized a gain of $108 million ($99 million after-tax).

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COMMITMENTS, CONTINGENCIES AND GUARANTEES

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, CONTINGENCIES AND GUARANTEES

COMMITMENTS, CONTINGENCIES AND GUARANTEES

Commitments

Operating Leases

Future annual payments under the Company's operating leases for various premises, services and equipment as well as fixed payments on Alberta PPAs, net of sublease receipts, are approximately as follows:

year ended December 31	Minimum Lease Payments	Amounts Recoverable under Sub-leases	Net Payments
(millions of Canadian $)
2016	354	46	308
2017	355	45	310
2018	270	26	244
2019	248	24	224
2020	185	20	165
2021 and thereafter	311	1	310
	1,723	162	1,561

The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to 25 years. Net rental expense on operating leases in 2015 was $131 million (2014 – $114 million; 2013 – $98 million).

TCPL's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Fixed payments under these PPAs have been included in the above operating leases table. Variable payments have been excluded as these payments are dependent upon plant availability and other factors. TCPL's share of payments under the PPAs in 2015 was $348 million (2014 – $391 million; 2013 – $242 million). The generating capacities and expiry dates of the PPAs are as follows:

	MW	Expiry Date
Sundance A	560	December 31, 2017
Sheerness	756	December 31, 2020

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

Other Commitments

Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts.

At December 31, 2015, TCPL was committed to Natural Gas Pipelines capital expenditures totaling approximately $0.9 billion (2014 – $0.9 billion), primarily related to construction costs related to the NGTL System, Mexican and other natural gas pipeline projects.

At December 31, 2015, the Company was committed to Liquids Pipelines capital expenditures totaling approximately $0.8 billion (2014 – $1.8 billion), primarily related to construction costs of Grand Rapids and Northern Courier.

At December 31, 2015, the Company was committed to Energy capital expenditures totaling approximately $0.6 billion (2014 – $0.2 billion), related to capital costs of the Napanee Generating Station. The Company also entered into an agreement to acquire the Ironwood natural gas fired, combined cycle power plant for US$657 million, before post-closing adjustments.

Contingencies

TCPL is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2015, the Company had accrued approximately $32 million (2014 – $31 million; 2013 – $32 million) related to operating facilities, which represents the present value of the estimated future amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.

TCPL and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions, other than the Keystone XL legal proceeding described in Note 29, will not have a material impact on the Company's consolidated financial position or results of operations.

Guarantees

TCPL and its joint venture partner on Bruce Power, OMERS, have each severally guaranteed certain contingent financial obligations of Bruce Power related to a lease agreement and contractor and supplier services. The Company's exposure under certain of these guarantees is unlimited.

In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. For certain of these entities, any payments made by TCPL under these guarantees in excess of its ownership interest are to be reimbursed by its partners.

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

		2015		2014
year ended December 31	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
(millions of Canadian $)
Bruce Power	Ranging to 20182	88	2	634	6
Other jointly owned entities	Ranging to 2040	139	24	104	14
		227	26	738	20

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

²  Except for one guarantee with no termination date.

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CORPORATE RESTRUCTURING COSTS

12 Months Ended

Dec. 31, 2015

Restructuring and Related Activities [Abstract]

CORPORATE RESTRUCTURING COSTS

CORPORATE RESTRUCTURING COSTS

At December 31, 2015, the Company had incurred $122 million pre-tax of corporate restructuring charges primarily related to severance, and recorded a provision of $87 million pre-tax related to planned severance costs in 2016 and expected losses under lease commitments. Of the total corporate restructuring charges of $209 million pre-tax, $157 million was recorded in Plant operating costs and other in the Consolidated statement of income which was partially offset by $58 million recorded in Revenues in the Consolidated statement of income related to costs that were recoverable through regulatory and tolling structures. In addition, $44 million was recorded as a Regulatory asset on the Consolidated balance sheet as it is expected to be recovered through regulatory and tolling structures in future periods and $8 million was capitalized to projects impacted by the corporate restructuring.

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RELATED PARTY TRANSACTIONS

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS

The following amounts are included in Due from affiliates:

		2015			2014
(millions of Canadian $)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
Discount Notes1	2016	2,376	0.9	%	2,597	1.3	%
Credit Facility2		100	2.7	%	245	3.0	%
		2,476			2,842

¹  Issued to TransCanada. Interest on the discount notes is equivalent to current commercial paper rates.

²  Issued to TransCanada. This facility is repayable on demand and bears interest at the Royal Bank of Canada prime rate per annum.

In 2015, Interest income included $29 million as a result of inter-corporate lending to TransCanada (2014 –$37 million; 2013 –$38 million).

At December 31, 2015, Accounts receivable included $13 million due from TransCanada (December 31, 2014 –$59 million).

The following amounts are included in Due to affiliates:

		2015			2014
(millions of Canadian $)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
Credit Facility1	2016	311	3.5	%	866	3.8	%
		311			866

¹  TransCanada has an unsecured $3.5 billion credit facility with a subsidiary of TCPL. Interest on this facility is charged at Reuters prime rate plus 75 basis points.

In 2015, Interest expense included $28 million of interest charges as a result of inter-corporate borrowing (2014 –$37 million; 2013 - $62 million).

At December 31, 2015, Accounts payable and other included $12 million due to TransCanada (December 31, 2014 –$16 million).

At December 31, 2015, Accrued interest included nil of interest payable to TransCanada (December 31, 2014 –$1 million).

In 2015, the Company made interest payments of $29 million to TransCanada (2014 –$37 million; 2013 –$62 million).

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SUBSEQUENT EVENTS

12 Months Ended

Dec. 31, 2015

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS

Portland Natural Gas Transmission System

On January 1, 2016, TCPL completed the sale of a 49.9 per cent interest in PNGTS to TC PipeLines, LP for an aggregate purchase price of US$223 million.

Keystone XL legal proceeding

On January 6, 2016, TCPL filed a Notice of Intent to initiate a claim under Chapter 11 of North American Free Trade Agreement (NAFTA) in response to the denial of the U.S. Presidential permit for the Keystone XL Pipeline. Through the NAFTA claim, the Company is seeking to recover more than US$15 billion in costs and damages that it estimates it has suffered as a result of the U.S. Administration’s breach of its NAFTA obligations. This litigation is in a preliminary stage and the likelihood of success and resulting impact on the Company’s financial position or results of operations is unknown at this time.

U.S. Senior Notes Issue

On January 27, 2016, TCPL completed an offering of US$850 million, 4.875 per cent Senior Notes due January 15, 2026 and

US$400 million, 3.125 per cent Senior Notes due January 15, 2019.

Ironwood

On February 1, 2016, TCPL acquired the Ironwood natural gas fired, combined cycle power plant in Lebanon, Pennsylvania, with a capacity of 778 MW, for US$657 million, before post-closing adjustments.

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ACCOUNTING POLICIES (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

The consolidated financial statements include the accounts of TCPL and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-controlling interests. TCPL uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TCPL records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates and Judgments

Use of Estimates and Judgments

In preparing these financial statements, TCPL is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and judgments used in the preparation of the consolidated financial statements include, but are not limited to:

• fair value and depreciation rates of plant, property and equipment (Note 7);

• carrying value of regulatory assets and liabilities (Note 9);

• fair value of goodwill (Note 10);

• amortization rates and fair value of intangible assets (Note 11);

• carrying value of asset retirement obligations (Note 14);

• provisions for income taxes (Note 15);

• assumptions used to measure retirement and other post-retirement obligations (Note 22);

• fair value of financial instruments (Note 23); and

• provision for commitments, contingencies and guarantees (Note 26).

Actual results could differ from those estimates.

Regulation

Regulation

In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB). In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls.Rate-regulatedaccounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TCPL's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TCPL's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of its liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System as the regulators' decisions regarding operations and tolls on that system generally do not have an impact on timing of recognition of revenues and expenses.

Revenue Recognition

Revenue Recognition

Natural Gas Pipelines and Liquids Pipelines

Revenues from the Company's natural gas and liquids pipelines, with the exception of Canadian natural gas pipelines which are subject to RRA, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made.

Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are at times subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved ROE assumptions. Adjustments to revenue are recorded when the NEB decision is received.

The Company's U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized using management's best estimate based on the facts and circumstances of the proceeding. Any allowances that are recognized during the proceeding process are refunded or retained at the time a regulatory decision becomes final.

Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas or oil that it transports or stores for others.

Energy

Power

Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative Instruments and Hedging Activities section of this note.

Natural Gas Storage

Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues.

Cash and Cash Equivalents

Cash and Cash Equivalents

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

Inventories

Inventories

Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.

Plant, Property and Equipment and Capitalized Project Costs

Plant, Property and Equipment

Natural Gas Pipelines

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

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

Liquids Pipelines

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

Energy

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

Corporate

Corporate Plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.

Capitalized Project Costs

The Company capitalizes project costs once advancement to a construction stage is probable or costs are otherwise likely to be recoverable. The Company also capitalizes interest for non-regulated projects in development and AFUDC for regulated projects. Capital projects in development are included in Intangible and other assets. These represent larger projects that generally require regulatory or other approvals before physical construction can begin. Once approvals are received, projects are moved to Plant, property and equipment under construction. When the asset is ready for its intended use and available for operations, capitalized project costs are depreciated in accordance with the Company's depreciation policies.

Project costs related to acquisitions are capitalized once the acquisition is probable.

Assets Held For Sale and Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

The Company reviews long-lived assets, such as Plant, property and equipment and Intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows or the estimated price to sell is less than the carrying value of an asset, an impairment loss is recognized for the excess of the carrying value over the fair value of the asset.

Assets Held For Sale

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

Acquisitions and Goodwill

Acquisitions and Goodwill

The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company initially assesses qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired. If TCPL concludes that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its carrying value, which includes goodwill. If the fair value is less than carrying value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference.

Power Purchase Arrangements

Power Purchase Arrangements

A power purchase agreement (PPA) is a long-term contract for the purchase or sale of power on a predetermined basis. Substantially all PPAs under which TCPL buys power are accounted for as operating leases. Initial payments for these PPAs were recognized in Intangible and other assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TCPL records the margin earned from the subleases as a component of Revenues.

Restricted Investments

Restricted Investments

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

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

Income Taxes

Income Taxes

The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, NGTL System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.

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

Asset Retirement Obligations

Asset Retirement Obligations

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

The Company has recorded ARO related to the non-regulated natural gas storage operations and certain power generation facilities. The scope and timing of asset retirements related to natural gas pipelines, liquids pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities.

Environmental Liabilities

Environmental Liabilities

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

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

Stock Options and Other Compensation Programs

Stock Options and Other Compensation Programs

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

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

Employee Post-Retirement Benefits

Employee Post-Retirement Benefits

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

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

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

Foreign Currency Transactions and Translation

Foreign Currency Transactions and Translation

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

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

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

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

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

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

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

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

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

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

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

Long-Term Debt Transaction Costs

Long-Term Debt Transaction Costs

The Company records Long-term debt transaction costs as other assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.

Guarantees

Guarantees

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

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SEGMENTED INFORMATION (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

year ended December 31, 2015	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	5,383		1,879		4,038		—		11,300
Income from equity investments	179		—		261		—		440
Plant operating costs and other	(1,736	)	(478	)	(766	)	(270	)	(3,250	)
Commodity purchases resold	—		—		(2,237	)	—		(2,237	)
Property taxes	(349	)	(79	)	(89	)	—		(517	)
Depreciation and amortization	(1,132	)	(266	)	(336	)	(31	)	(1,765	)
Asset impairment charges	—		(3,686	)	(59	)	—		(3,745	)
Loss on assets held for sale	(125	)	—		—		—		(125	)
Segmented earnings/(losses)	2,220		(2,630	)	812		(301	)	101
Interest expense									(1,398	)
Interest income and other									192
Loss before income taxes									(1,105	)
Income tax expense									(35	)
Net loss									(1,140	)
Net income attributable to non-controlling interests									(6	)
Net loss attributable to controlling interests									(1,146	)
Preferred share dividends									—
Net loss attributable to common shares									(1,146	)
Capital spending
Capital expenditures	2,466		1,012		376		64		3,918
Capital projects in development	233		278		—		—		511
	2,699		1,290		376		64		4,429

year ended December 31, 2014	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	4,913		1,547		3,725		—		10,185
Income from equity investments	163		—		359		—		522
Plant operating costs and other	(1,501	)	(426	)	(919	)	(127	)	(2,973	)
Commodity purchases resold	—		—		(1,836	)	—		(1,836	)
Property taxes	(334	)	(62	)	(77	)	—		(473	)
Depreciation and amortization	(1,063	)	(216	)	(309	)	(23	)	(1,611	)
Gain on assets sold	9		—		108		—		117
Segmented earnings/(losses)	2,187		843		1,051		(150	)	3,931
Interest expense									(1,235	)
Interest income and other									128
Income before income taxes									2,824
Income tax expense									(830	)
Net income									1,994
Net income attributable to non-controlling interests									(151	)
Net income attributable to controlling interests									1,843
Preferred share dividends									(2	)
Net income attributable to common shares									1,841
Capital spending
Capital expenditures	1,768		1,469		206		46		3,489
Capital projects in development	368		480		—		—		848
	2,136		1,949		206		46		4,337

year ended December 31, 2013	Natural Gas Pipelines		Liquids Pipelines		Energy		Corporate		Total
(millions of Canadian $)
Revenues	4,497		1,124		3,176		—		8,797
Income from equity investments	145		—		452		—		597
Plant operating costs and other	(1,405	)	(328	)	(833	)	(108	)	(2,674	)
Commodity purchases resold	—		—		(1,317	)	—		(1,317	)
Property taxes	(329	)	(44	)	(72	)	—		(445	)
Depreciation and amortization	(1,027	)	(149	)	(293	)	(16	)	(1,485	)
Segmented earnings/(losses)	1,881		603		1,113		(124	)	3,473
Interest expense									(1,046	)
Interest income and other									72
Income before income taxes									2,499
Income tax expense									(605	)
Net income									1,894
Net income attributable to non-controlling interests									(105	)
Net income attributable to controlling interests									1,789
Preferred share dividends									(20	)
Net income attributable to common shares									1,769
Capital spending
Capital expenditures	1,776		2,286		152		50		4,264
Capital projects in development	245		243		—		—		488
	2,021		2,529		152		50		4,752

at December 31	2015	2014
(millions of Canadian $)
Total Assets
Natural Gas Pipelines	31,072	27,103
Liquids Pipelines	16,046	16,116
Energy	15,558	14,197
Corporate	4,253	3,999
	66,929	61,415

Revenue from External Customers by Geographic Areas

year ended December 31	2015	2014	2013
(millions of Canadian $)
Revenues
Canada – domestic	3,877	3,956	4,659
Canada – export	1,292	1,314	997
United States	5,872	4,718	3,029
Mexico	259	197	112
	11,300	10,185	8,797

Schedule of Long-Lived Assets by Country

at December 31	2015	2014
(millions of Canadian $)
Plant, Property and Equipment
Canada	19,287	19,191
United States	21,899	20,098
Mexico	3,631	2,485
	44,817	41,774

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OTHER CURRENT ASSETS (Tables)

12 Months Ended

Dec. 31, 2015

Other Assets [Abstract]

Schedule of Other Current Assets

at December 31		2014
(millions of Canadian $)	2015
Cash held as collateral	585	423
Fair value of derivative contracts (Note 23)	442	409
Regulatory assets (Note 9)	85	16
Assets held for sale (Note 6)	20	—
Other	221	170
	1,353	1,018

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ASSETS HELD FOR SALE (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Schedule of Assets Held for Sale

at December 31	2015
(millions of Canadian $)
Assets Held for Sale
Accounts receivable	4
Inventories	1
Other current assets	1
Plant, property and equipment	14
Total Assets Held for Sale (included in Other current assets, Note 5)	20
Liabilities Related to Assets Held for Sale
Accounts payable and other	38
Other long-term liabilities	1
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13)	39

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PLANT, PROPERTY AND EQUIPMENT (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Schedule of Plant, Property and Equipment

	2015			2014
at December 31	Cost	Accumulated Depreciation	Net Book Value	Cost	Accumulated Depreciation	Net Book Value
(millions of Canadian $)
Natural Gas Pipelines
Canadian Mainline
Pipeline	9,164	5,966	3,198	9,045	5,712	3,333
Compression	3,433	2,220	1,213	3,423	2,100	1,323
Metering and other	499	192	307	458	180	278
	13,096	8,378	4,718	12,926	7,992	4,934
Under construction	257	—	257	135	—	135
	13,353	8,378	4,975	13,061	7,992	5,069
NGTL System
Pipeline	8,456	3,820	4,636	8,185	3,619	4,566
Compression	2,188	1,404	784	2,055	1,318	737
Metering and other	1,096	489	607	1,032	446	586
	11,740	5,713	6,027	11,272	5,383	5,889
Under construction	969	—	969	413	—	413
	12,709	5,713	6,996	11,685	5,383	6,302
ANR1
Pipeline	1,449	350	1,099	1,217	227	990
Compression	1,101	187	914	780	140	640
Metering and other	977	252	725	737	231	506
	3,527	789	2,738	2,734	598	2,136
Under construction	304	—	304	127	—	127
	3,831	789	3,042	2,861	598	2,263
Mexico
Pipeline	1,296	162	1,134	1,053	104	949
Compression	183	14	169	151	6	145
Metering and other	388	27	361	314	20	294
	1,867	203	1,664	1,518	130	1,388
Under construction	1,959	—	1,959	1,098	—	1,098
	3,826	203	3,623	2,616	130	2,486
Other Natural Gas Pipelines
GTN	2,278	765	1,513	1,842	588	1,254
Great Lakes	2,157	1,155	1,002	1,807	939	868
Foothills	1,606	1,162	444	1,671	1,180	491
Other2	2,223	572	1,651	1,800	363	1,437
	8,264	3,654	4,610	7,120	3,070	4,050
Under construction	71	—	71	34	—	34
	8,335	3,654	4,681	7,154	3,070	4,084
	42,054	18,737	23,317	37,377	17,173	20,204

Liquids Pipelines
Keystone
Pipeline	9,288	718	8,570	7,931	463	7,468
Pumping equipment	1,092	108	984	964	80	884
Tanks and other	3,034	228	2,806	2,282	144	2,138
	13,414	1,054	12,360	11,177	687	10,490
Under construction	1,826	—	1,826	4,438	—	4,438
	15,240	1,054	14,186	15,615	687	14,928
Energy
Natural Gas – Ravenswood	2,607	654	1,953	2,140	476	1,664
Natural Gas – Other3,4	3,361	1,164	2,197	3,214	971	2,243
Hydro, Wind and Solar5	2,417	476	1,941	2,194	359	1,835
Natural Gas Storage and Other	740	132	608	717	118	599
	9,125	2,426	6,699	8,265	1,924	6,341
Under construction	430	—	430	149	—	149
	9,555	2,426	7,129	8,414	1,924	6,490
Corporate	267	82	185	232	80	152
	67,116	22,299	44,817	61,638	19,864	41,774

¹  TCO is excluded from the ANR net book value at December 31, 2015 as it has been classified as an asset held for sale. Refer to Note 6 for further information.

²  Includes Bison, Portland Natural Gas Transmission System (PNGTS), North Baja, Tuscarora and Ventures LP.

³  Includes facilities with long-term PPAs that are accounted for as operating leases. The cost and accumulated depreciation of these facilities were $813 million and $142 million, respectively, at December 31, 2015 (2014 – $695 million and $103 million, respectively). Revenues of $93 million were recognized in 2015 (2014 – $81 million; 2013 – $78 million) through the sale of electricity under the related PPAs.

⁴  Includes Halton Hills, Coolidge, Bécancour, Ocean State Power, Mackay River and other natural gas-fired facilities.

⁵  Includes the acquisitions of four solar power facilities in 2014.

Summary of Keystone XL Impairment

at December 31, 2015	Estimated	Impairment charge
(millions of Canadian $)	Fair Value	Pre-tax	After-tax
Plant and equipment	463	1,460	1,391
Terminals, including KHT	158	274	219
Intangible assets	—	1,150	737
Capitalized interest	—	725	488
Future cancellation costs	—	77	56
	621	3,686	2,891

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EQUITY INVESTMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Investments

(millions of Canadian $)	Ownership   Interest at   December 31, 2015		Income / (Loss) from Equity Investments				Equity Investments
			year ended December 31				at December 31
			2015		2014	2013	2015	2014
Natural Gas Pipelines
Northern Border1,2			85		76	66	664	587
Iroquois	44.5	%	51		43	41	238	210
TQM	50.0	%	12		12	13	72	73
Other	Various		31		32	25	73	68
Liquids Pipelines
Grand Rapids	50.0	%	—		—	—	542	240
Canaport Energy East Marine Terminal	50.0	%	—		—	—	16	—
Energy
Bruce Power3,4	48.5	%	249		314	310	4,200	3,995
ASTC Power Partnership	50.0	%	(23	)	8	110	21	29
Portlands Energy	50.0	%	30		36	31	321	335
Other	Various		5		1	1	67	61
			440		522	597	6,214	5,598

¹  The results reflect a 50.0 per cent interest in Northern Border as a result of the Company fully consolidating TC PipeLines, LP. At December 31, 2015, TCPL had an ownership interest in TC PipeLines, LP of 28.0 per cent (2014 – 28.3 and 2013 – 28.9 per cent) and its effective ownership of Northern Border, net of non-controlling interests, was 14.0 per cent (2014 – 14.2 and 2013 – 14.5 per cent).

²  At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Northern Border Pipeline Company is US$117 million (2014 – US$117 million) due to the fair value assessment of assets at the time of acquisition.

³  As a result of TCPL's increased ownership in Bruce Power L.P. (Bruce B) and the merger of Bruce Power A L.P. (Bruce A) and Bruce B (to form Bruce Power) in December 2015, TCPL has an ownership interest in Bruce Power of 48.5 per cent. Prior to the acquisition and merger, TCPL applied equity accounting to its 48.9 per cent ownership interest in Bruce A and 31.6 per cent ownership interest in Bruce B. TCPL continues to apply equity accounting to Bruce Power. Refer to Note 25 for further information.

⁴  At December 31, 2015, the difference between the carrying value of the investment and the underlying equity in the net assets of Bruce Power is $973 million (2014 – $776 million) due to the fair value assessment of assets at the time of acquisitions.

Summary of Financial Information of Equity Investments

year ended December 31	2015		2014		2013
(millions of Canadian $)
Income
Revenues	4,337		4,814		4,989
Operating and other expenses	(3,254	)	(3,489	)	(3,536	)
Net income	1,046		1,264		1,390
Net income attributable to TCPL	440		522		597

at December 31	2015		2014
(millions of Canadian $)
Balance Sheet
Current assets	1,530		1,412
Non-current assets	13,190		12,260
Current liabilities	(1,370	)	(1,067	)
Non-current liabilities	(3,116	)	(3,255	)

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RATE-REGULATED BUSINESSES (Tables)

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities

at December 31	2015	2014	Remaining Recovery/ Settlement Period (years)
(millions of Canadian $)
Regulatory Assets
Deferred income taxes1	848	1,001	n/a
Operating and debt-service regulatory assets2	47	4	1
Pensions and other post retirement benefits3	210	236	n/a
Foreign exchange on long-term debt5	54	—	1-14
Other4	110	72	n/a
	1,269	1,313
Less: Current portion included in Other current assets (Note 5)	85	16
	1,184	1,297
Regulatory Liabilities
Foreign exchange on long-term debt5	—	42	1-14
Operating and debt-service regulatory liabilities2	32	21	1
ANR-related post-employment and retirement benefits other than pension6	147	117	n/a
Long term adjustment account7	231	64	45
Pipeline abandonment costs8	285	—	n/a
Bridging amortization account9	456	—	15
Other4	52	49	n/a
	1,203	293
Less: Current portion included in Accounts payable and other (Note 13)	44	30
	1,159	263

¹  These regulatory assets are underpinned by non-cash transactions or are recovered without an allowance for return as approved by the regulator. Accordingly, these regulatory assets are not included in rate base and do not yield a return on investment during the recovery period.

²  Operating and debt-service regulatory assets and liabilities represent the accumulation of cost and revenue variances approved by the regulatory authority for inclusion in determining tolls for the following calendar year. Pre-tax operating results in 2015 would have been $32 million lower (2014 – $28 million higher; 2013 – $76 million lower) had these amounts not been recorded as Regulatory assets and liabilities.

³  These balances represent the regulatory offset to pension plan and other post-retirement obligations to the extent the amounts are expected to be collected from customers in future rates. The balances are excluded from the rate base and do not earn a return on investment. Pre-tax operating results in 2015 would have been $26 million higher (2014 – $46 million lower; 2013 – $171 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁴  Pre-tax operating results in 2015 would have been $35 million lower (2014 – $2 million higher; 2013 – $2 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁵  Foreign exchange on long-term debt of the NGTL System and Foothills represents the variance resulting from revaluing foreign currency-denominated debt instruments to the current foreign exchange rate from the historical foreign exchange rate at the time of issue. Foreign exchange gains and losses realized when foreign debt matures or is redeemed early are expected to be recovered or refunded through the determination of future tolls. In the absence of RRA, GAAP would have required the inclusion of these unrealized gains or losses in Net income.

⁶  Under the terms of ANR’s last rate settlement, ANR will be required to make refunds to its customers, pursuant to a refund plan to be approved by FERC in a future rate proceeding, of those amounts in the post-retirement benefit trust fund that have not been used to pay benefits to its employees. This regulatory liability represents the difference between the amount collected in rates and the amount of post-retirement benefits expense. ANR anticipates that the resolution of this liability will be determined through the section 4 rate case ANR filed with the FERC on January 29, 2016.  Since the timing of the rate case conclusion is uncertain, a settlement period cannot be determined at this time. Pre-tax operating results in 2015 would have been $30 million higher (2014 – $13 million higher; 2013 – $16 million higher) had these amounts not been recorded as regulatory assets and liabilities.

⁷  Pre-tax operating results in 2015 would have been $167 million higher (2014 – $418 million higher; 2013 – $247 million lower) had these amounts not been recorded as regulatory liabilities.

⁸  Effective January 1, 2015, NEB regulated pipelines including the Mainline, NGTL System, Foothills, Keystone and TQM are required to collect and set-aside funds received from customers to be used for future pipeline abandonment activities. Funds are collected through a surcharge mechanism, set-aside in trust accounts, and the obligation to use these funds for future pipeline abandonment activities is recorded as a regulatory liability. Pre-tax operating results in 2015 would have been $285 million higher (2014 –nil; 2013 –nil) had these amounts not been recorded as regulatory liabilities.

⁹  Pre-tax operating results in 2015 would have been $456 million higher (2014 – nil; 2013 –nil) had these amounts not been recorded as regulatory liabilities.

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GOODWILL (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of goodwill recorded on the entity's acquisitions in the U.S.

The Company has recorded the following Goodwill on its acquisitions in the U.S.:

(millions of Canadian $)	Natural Gas Pipelines	Energy	Total
Balance at January 1, 2014	2,816	880	3,696
Foreign exchange rate changes	258	80	338
Balance at December 31, 2014	3,074	960	4,034
Foreign exchange rate changes	593	185	778
Balance at December 31, 2015	3,667	1,145	4,812

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INTANGIBLE AND OTHER ASSETS (Tables)

12 Months Ended

Dec. 31, 2015

INTANGIBLES AND OTHER ASSETS

Schedule of Finite-Lived Intangible Assets

at December 31	2015	2014
(millions of Canadian $)
Capital projects in development	1,814	1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances1	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	9	181
Other	797	628
	3,185	2,641

¹  TCPL held a note receivable from the seller of Ravenswood of $213 million (US$154 million) and $213 million (US$184 million) as at December 31, 2015 and at December 31, 2014, which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other current assets was $55 million (US$40 million) at December 31, 2015 and $46 million (US$40 million) at December 31, 2014.

The following amounts related to PPAs are included in Intangible and other assets:

	2015			2014
at December 31	Cost	Accumulated Amortization	Net Book Value	Cost	Accumulated Amortization	Net Book Value
(millions of Canadian $)
Sheerness (expires 2020)	585	390	195	585	351	234
Sundance A (expires 2017)	225	200	25	225	187	38
	810	590	220	810	538	272

Schedule of Other Assets

at December 31	2015	2014
(millions of Canadian $)
Capital projects in development	1,814	1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances1	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	9	181
Other	797	628
	3,185	2,641

¹  TCPL held a note receivable from the seller of Ravenswood of $213 million (US$154 million) and $213 million (US$184 million) as at December 31, 2015 and at December 31, 2014, which bears interest at 6.75 per cent and matures in 2040. The current portion included in Other current assets was $55 million (US$40 million) at December 31, 2015 and $46 million (US$40 million) at December 31, 2014.

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NOTES PAYABLE (Tables)

12 Months Ended

Dec. 31, 2015

Short-term Debt [Abstract]

Schedule of Notes Payable

	2015			2014
(millions of Canadian $, unless otherwise noted)	Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31		Outstanding at December 31	Weighted Average Interest Rate per Annum at December 31
Canadian	697	0.8	%	1,540	1.2	%
U.S. (2015 – US$376; 2014 – US$800)	521	1.1	%	927	0.7	%
	1,218			2,467

Schedule of Credit Facilities

These unsecured credit facilities included the following:

					year ended December 31
at December 31, 2015					2015	2014	2013
Amount	Unused Capacity	Borrower	Description	Matures	Cost to maintain
					(millions of Canadian $)
$3 billion	$3 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2020	6	6	4
US$1 billion	US$1 billion	TCPL	Committed, syndicated, revolving, extendible TCPL credit facility	December 2016	—	—	—
US$0.5 billion	US$0.5 billion	TCPL USA	Committed, syndicated, revolving, extendible TCPL USA credit facility, guaranteed by TCPL	December 2016	3	2	1
US$1.5 billion	US$1.5 billion	TAIL/TCPM	Committed, syndicated, revolving, extendible TAIL/TCPM credit facility, guaranteed by TCPL	December 2016	2	1	—
$1.7 billion	$0.7 billion	TCPL/TCPL USA	Supports the issuance of letters of credit and provides additional liquidity	Demand	—	—	—

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ACCOUNTS PAYABLE AND OTHER (Tables)

12 Months Ended

Dec. 31, 2015

Payables and Accruals [Abstract]

Schedule of Accounts Payable and Other

at December 31	2015	2014
(millions of Canadian $)
Trade payables	1,506	1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	370	345
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39	—
Other	129	143
	3,014	2,891

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OTHER LONG-TERM LIABILITIES (Tables)

12 Months Ended

Dec. 31, 2015

Deferred Costs, Noncurrent [Abstract]

Schedule of Other Long-Term Liabilities

at December 31	2015	2014
(millions of Canadian $)
Fair value of derivative contracts (Note 23)	625	411
Employee post-retirement benefits (Note 22)	380	444
Asset retirement obligations	109	98
Guarantees (Note 26)	26	20
Other	120	79
	1,260	1,052

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INCOME TAXES (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

Schedule of Provision for Income Taxes

year ended December 31	2015		2014	2013
(millions of Canadian $)
Current
Canada	45		104	27
Foreign	92		42	16
	137		146	43
Deferred
Canada	33		307	239
Foreign	(135	)	377	323
	(102	)	684	562
Income Tax Expense	35		830	605

Schedule of Geographic Components of Income

year ended December 31	2015		2014	2013
(millions of Canadian $)
Canada	(623	)	1,146	1,201
Foreign	(482	)	1,678	1,298
(Loss)/Income Before Income Taxes	(1,105	)	2,824	2,499

Reconciliation of Income Tax Expense

year ended December 31	2015		2014		2013
(millions of Canadian $)
(Loss)/Income before income taxes	(1,105	)	2,824		2,499
Federal and provincial statutory tax rate	26.0	%	25.0	%	25.0	%
Expected income tax (recovery)/expense	(287	)	706		625
Income tax differential related to regulated operations	159		129		(13	)
Higher effective foreign tax rates	14		25		33
Income from equity investments and non-controlling interests	(56	)	(38	)	(28	)
Tax rate and legislative changes	34		—		(25	)
Asset impairment charges1	170		—		—
Other	1		8		13
Actual Income Tax Expense	35		830		605

¹  The asset impairment impact is net of $311 million attributed to higher foreign tax rates.

Schedule of Deferred Income Tax Assets and Liabilities and Amounts Classified in the Consolidated Balance Sheet

at December 31	2015	2014
(millions of Canadian $)
Deferred Income Tax Assets
Difference in accounting and tax bases of impaired assets	916	—
Tax loss and credit carryforwards	1,325	1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	132	146
	3,304	1,970
Less: Valuation allowance1	1,060	125
	2,244	1,845
Deferred Income Tax Liabilities
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,441	5,548
Equity investments	656	648
Taxes on future revenue requirement	227	253
Other	55	71
	7,379	6,520
Net Deferred Income Tax Liabilities	5,135	4,675

¹  In 2015, an increase to the valuation allowance of $935 million was recorded as the Company believes that it is more likely than not that the tax benefits related to the unrealized foreign exchange losses on long-term debt and unrealized losses on certain impaired assets will not be realized in the future.

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

at December 31	2015	20141
(millions of Canadian $)
Deferred Income Tax Assets
Intangible and other assets (Note 11)	9	181
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,856
Net Deferred Income Tax Liabilities	5,135	4,675

¹  As a result of retrospectively applying guidance on the presentation of deferred taxes on the Consolidated balance sheet on January 1, 2015, the Company reclassified its December 31, 2014 current Deferred income tax assets of $427 million, and current Deferred income tax liabilities of $4 million to its non-current Deferred income tax assets and liabilities.

Reconciliation of the Annual Changes in the Total Unrecognized Tax Benefit

Below is the reconciliation of the annual changes in the total unrecognized tax benefit:

at December 31	2015		2014		2013
(millions of Canadian $)
Unrecognized tax benefit at beginning of year	13		19		45
Gross increases – tax positions in prior years	2		2		3
Gross decreases – tax positions in prior years	(2	)	(8	)	(28	)
Gross increases – tax positions in current year	1		1		2
Lapses of statute of limitations	(1	)	(1	)	(3	)
Unrecognized Tax Benefit at End of Year	13		13		19

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LONG-TERM DEBT (Tables)

12 Months Ended

Dec. 31, 2015

Long-term Debt, Unclassified [Abstract]

Schedule of Long-Term Debt

		2015			2014
Outstanding amounts	Maturity Dates	Outstanding at December 31	Interest Rate1		Outstanding at December 31	Interest Rate1
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
Debentures
Canadian	2017 to 2020	599	10.7	%	749	10.9	%
U.S. (2015 and 2014 – US$400)	2021	554	9.9	%	464	9.9	%
Medium-Term Notes
Canadian	2016 to 2041	5,192	5.3	%	4,048	5.7	%
Senior Unsecured Notes
U.S. (2015 – US$14,723; 2014 – US$13,526)	2016 to 2045	20,340	4.8	%	15,655	5.0	%
		26,685			20,916
NOVA GAS TRANSMISSION LTD.
Debentures and Notes
Canadian2	2016 to 2024	325	11.5	%	325	11.5	%
U.S. (2015 and 2014 – US$200)	2023	277	7.9	%	232	7.9	%
Medium-Term Notes
Canadian	2025 to 2030	504	7.4	%	504	7.4	%
U.S. (2015 and 2014 – US$33)	2026	45	7.5	%	38	7.5	%
		1,151			1,099
ANR PIPELINE COMPANY
Senior Unsecured Notes
U.S. (2015 and 2014 – US$432)	2021 to 2025	598	8.9	%	502	8.9	%
GAS TRANSMISSION NORTHWEST LLC
Unsecured Term Loan
U.S. (2015 – US$75)	2019	104	1.4	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$250; 2014 – US$325)	2020 to 2035	346	5.6	%	377	5.5	%
		450			377
TC PIPELINES, LP
Unsecured Loan
U.S. (2015 – US$200; 2014 – US$330)	2017	277	1.6	%	383	1.4	%
Unsecured Term Loan Facility
U.S. (2015 and 2014 – US$500)	2018	692	1.6	%	580	1.4	%
Unsecured Term Loan
U.S. (2015 – US$170)	2018	235	1.6	%	—	—
Senior Unsecured Notes
U.S. (2015 – US$698; 2014 – US$350)	2021 to 2025	967	4.7	%	405	4.7	%
		2,171			1,368
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Senior Unsecured Notes
U.S. (2015 – US$297; 2014 – US$316)	2018 to 2030	411	7.8	%	367	7.8	%

TUSCARORA GAS TRANSMISSION COMPANY
Senior Secured Notes
U.S. (2015 – US$16; 2014 – US$20)	2017	22	4.0	%	23	4.0	%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Senior Secured Notes3
U.S. (2015 – US$69; 2014 – US$90)	2018	96	6.1	%	105	6.1	%
		31,584			24,757
Less: Current portion of Long-term debt		2,547			1,797
		29,037			22,960

¹  Interest rates are the effective interest rates except for those pertaining to Long-term debt issued for the Company's Canadian regulated natural gas operations, in which case the weighted average interest rate is presented as approved by the regulators. Weighted average and effective interest rates are stated as at the respective outstanding dates.

²  Debentures issued by NGTL in the amount of $225 million have retraction provisions that entitle the holders to periodically require redemption of up to eight per cent of the then outstanding principal plus accrued and unpaid interest on specified repayment dates. No redemptions were made in 2015 or 2014.

³  Secured by shipper transportation contracts, existing and new guarantees, letters of credit and collateral requirements.

The Company issued Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)
Company	Issue date	Type	Maturity date	Amount	Interest Rate
TRANSCANADA PIPELINES LIMITED
	November 2015	Senior Unsecured Notes	November 2017	US 1,000	1.625	%
	October 2015	Medium-Term Notes	November 2041	400	4.55	%
	July 2015	Medium-Term Notes	July 2025	750	3.30	%
	March 2015	Senior Unsecured Notes	March 2045	US 750	4.60	%
	January 2015	Senior Unsecured Notes	January 2018	US 500	1.875	%
	January 2015	Senior Unsecured Notes	January 2018	US 250	Floating
	February 2014	Senior Unsecured Notes	March 2034	US 1,250	4.63	%
	October 2013	Senior Unsecured Notes	October 2023	US 625	3.75	%
	October 2013	Senior Unsecured Notes	October 2043	US 625	5.00	%
	July 2013	Senior Unsecured Notes	June 2016	US 500	Floating
	July 2013	Medium-Term Notes	July 2023	450	3.69	%
	July 2013	Medium-Term Notes	November 2041	300	4.55	%
	January 2013	Senior Unsecured Notes	January 2016	US 750	0.75	%
TC PIPELINES, LP
	September 2015	Unsecured Term Loan	October 2018	US 170	Floating
	March 2015	Senior Unsecured Notes	March 2025	US 350	4.375	%
	July 2013	Unsecured Term Loan Facility	July 2018	US 500	Floating
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Unsecured Term Loan	June 2019	US 75	Floating

Schedule of Repayments of Long-Term Debt

At December 31, 2015, principal repayments on the Long-term debt of the Company for the next five years are approximately as follows:

(millions of Canadian $)	2016	2017	2018	2019	2020
Principal repayments on Long-term debt	2,547	2,150	3,379	1,228	1,801

Schedule of Retired Long-Term Debt

The Company retired Long-term debt over the three years ended December 31, 2015 as follows:

(millions of Canadian $, unless otherwise noted)
Company	Retirement date	Type	Amount	Interest Rate
TRANSCANADA PIPELINES LIMITED
	August 2015	Debentures	150	11.90	%
	June 2015	Senior Unsecured Notes	US 500	3.40	%
	March 2015	Senior Unsecured Notes	US 500	0.875	%
	January 2015	Senior Unsecured Notes	US 300	4.875	%
	June 2014	Debentures	125	11.10	%
	February 2014	Medium-Term Notes	300	5.05	%
	January 2014	Medium-Term Notes	450	5.65	%
	August 2013	Senior Unsecured Notes	US 500	5.05	%
	June 2013	Senior Unsecured Notes	US 350	4.00	%
GAS TRANSMISSION NORTHWEST LLC
	June 2015	Senior Unsecured Notes	US 75	5.09	%
NOVA GAS TRANSMISSION LTD.
	June 2014	Debentures	53	11.20	%

Schedule of Interest Expense

Interest expense over the three years ended December 31 was as follows:

year ended December 31	2015		2014		2013
(millions of Canadian $)
Interest on Long-term debt	1,487		1,317		1,216
Interest on Junior subordinated notes (Note 17)	116		70		65
Interest on short-term debt	44		52		73
Capitalized interest	(280	)	(259	)	(287	)
Amortization and other financial charges1	31		55		(21	)
	1,398		1,235		1,046

¹  Amortization and other financial charges includes amortization of transaction costs and debt discounts calculated using the effective interest method and changes in the fair value of derivatives used to manage the Company's exposure to changes in interest rates.

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JUNIOR SUBORDINATED NOTES (Tables)

12 Months Ended

Dec. 31, 2015

Junior Subordinated Notes [Abstract]

Schedule of Junior Subordinated Notes

		2015			2014
Outstanding loan amount	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
(millions of Canadian $, unless otherwise noted)
TRANSCANADA PIPELINES LIMITED
U.S. (2015 and 2014 – US$1,000)1	2067	1,384	6.4	%	1,160	6.5	%
U.S. (2015 – US$750)1	2075	1,038	5.3	%	—	—
		2,422			1,160

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NON-CONTROLLING INTERESTS (Tables)

12 Months Ended

Dec. 31, 2015

Noncontrolling Interest [Abstract]

Schedule of the Company's non-controlling interests included in the Consolidated Financial Statements

The Company's Non-controlling interests included in the Consolidated balance sheet are as follows:

at December 31	2015	2014
(millions of Canadian $)
Non-controlling interest in TC PipeLines, LP	1,590	1,479
Non-controlling interest in PNGTS	127	104
	1,717	1,583

The Company's Non-controlling interests included in the Consolidated statement of income are as follows:

year ended December 31	2015		2014	2013
(millions of Canadian $)
Non-controlling interest in TC PipeLines, LP	(13	)	136	93
Non-controlling interest in PNGTS	19		15	12
	6		151	105

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COMMON SHARES (Tables)

12 Months Ended

Dec. 31, 2015

Common Stock, Number of Shares, Par Value and Other Disclosures [Abstract]

Schedule of Common Shares

	Number of Shares	Amount
	(thousands)	(millions of Canadian $)
Outstanding at January 1, 2013	738,381	14,306
Issuance of common shares for cash	18,733	899
Outstanding at December 31, 2013	757,114	15,205
Issuance of common shares for cash	22,365	1,115
Outstanding at December 31, 2014	779,479	16,320
Outstanding at December 31, 2015	779,479	16,320

Schedule of Options Valuation Assumptions

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

year ended December 31	2015		2014		2013
Expected life (years)	5.8		6.0		6.0
Interest rate	1.1	%	1.8	%	1.7	%
Volatility1	18	%	17	%	18	%
Dividend yield	3.7	%	3.8	%	3.7	%
Forfeiture rate	5	%	5	%	15	%

¹  Volatility is derived based on the average of both the historical and implied volatility of the Company's common shares.

Schedule of Additional Option Information

The following table summarizes additional stock option information:

year ended December 31	2015	2014	2013
(millions of Canadian $, unless otherwise noted)
Total intrinsic value of options exercised	37	68	25
Fair value of options that have vested	91	95	64
Total options vested	2.0 million	1.7 million	1.3 million

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OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS (Tables)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Components of Other Comprehensive Income/(Loss)

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

year ended December 31, 2015	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	798		15		813
Change in fair value of net investment hedges	(505	)	133		(372	)
Change in fair value of cash flow hedges	(92	)	35		(57	)
Reclassification to net income of gains and losses on cash flow hedges	144		(56	)	88
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	74		(23	)	51
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	41		(9	)	32
Other comprehensive income on equity investments	62		(15	)	47
Other Comprehensive Income	522		80		602

year ended December 31, 2014	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	462		55		517
Change in fair value of net investment hedges	(373	)	97		(276	)
Change in fair value of cash flow hedges	(118	)	49		(69	)
Reclassification to net income of gains and losses on cash flow hedges	(95	)	40		(55	)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(146	)	44		(102	)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	25		(7	)	18
Other comprehensive loss on equity investments	(272	)	68		(204	)
Other Comprehensive Loss	(517	)	346		(171	)

year ended December 31, 2013	Before Tax Amount		Income Tax Recovery/(Expense)		Net of Tax Amount
(millions of Canadian $)
Foreign currency translation gains on net investment in foreign operations	269		114		383
Change in fair value of net investment hedges	(323	)	84		(239	)
Change in fair value of cash flow hedges	121		(50	)	71
Reclassification to net income of gains and losses on cash flow hedges	60		(19	)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	96		(29	)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	34		(11	)	23
Other comprehensive income on equity investments	313		(79	)	234
Other Comprehensive Income	570		10		580

Schedule of Changes in Accumulated Other Comprehensive Income

The changes in AOCI by component are as follows:

	Currency Translation Adjustments		Cash Flow Hedges		Pension and Other Post-Retirement Benefit Plan Adjustments		Equity Investments		Total1
AOCI balance at January 1, 2013	(707	)	(116	)	(287	)	(338	)	(1,448	)
Other comprehensive income before reclassifications2	78		71		67		219		435
Amounts reclassified from accumulated other comprehensive loss	—		41		23		15		79
Net current period other comprehensive income	78		112		90		234		514
AOCI balance at December 31, 2013	(629	)	(4	)	(197	)	(104	)	(934	)
Other comprehensive income/(loss) before reclassifications2	111		(69	)	(102	)	(206	)	(266	)
Amounts reclassified from accumulated other comprehensive loss	—		(55	)	18		2		(35	)
Net current period other comprehensive income/(loss)	111		(124	)	(84	)	(204	)	(301	)
AOCI balance at December 31, 2014	(518	)	(128	)	(281	)	(308	)	(1,235	)
Other comprehensive income/(loss) before reclassifications2	135		(57	)	51		33		162
Amounts reclassified from accumulated other comprehensive loss3	—		88		32		14		134
Net current period other comprehensive income	135		31		83		47		296
AOCI balance at December 31, 2015	(383	)	(97	)	(198	)	(261	)	(939	)

¹  All amounts are net of tax. Amounts in parentheses indicate losses recorded to OCI.

²  Other comprehensive income before reclassifications on currency translation adjustments is net of non-controlling interest gains of $306 million in 2015 (2014 – $130 million gains; 2013 – $66 million gains).

³  Losses related to cash flow hedges reported in AOCI and expected to be reclassified to Net income in the next 12 months are estimated to be $83 million ($51 million, net of tax) at December 31, 2015. These estimates assume constant commodity prices, interest rates and foreign exchange rates over time, however, the amounts reclassified will vary based on the actual value of these factors at the date of settlement.

Schedule of Reclassifications out of Accumulated Other Comprehensive Income

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

	Amounts Reclassified From Accumulated Other Comprehensive Loss1						Affected Line Item in the Consolidated Statement of Income
year ended December 31	2015		2014		2013
(millions of Canadian $)
Cash flow hedges
Commodities	(128	)	111		(44	)	Revenues (Energy)
Interest	(16	)	(16	)	(16	)	Interest expense
	(144	)	95		(60	)	Total before tax
	56		(40	)	19		Income tax expense/(recovery)
	(88	)	55		(41	)	Net of tax
Pension and other post-retirement benefit plan adjustments
Amortization of actuarial loss and past service cost	(41	)	(25	)	(34	)	2
	9		7		11		Income tax recovery
	(32	)	(18	)	(23	)	Net of tax
Equity investments
Equity income	(19	)	(2	)	(20	)	Income from equity investments
	5		—		5		Income tax recovery
	(14	)	(2	)	(15	)	Net of tax

¹  All amounts in parentheses indicate expenses to the Consolidated statement of income.

²  These Accumulated other comprehensive loss components are included in the computation of net benefit cost. Refer to Note 22 for further information.

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EMPLOYEE POST-RETIREMENT BENEFITS (Tables)

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Schedule of Payments for Defined Benefit Plans

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

year ended December 31	2015	2014	2013
(millions of Canadian $)
DB Plans	96	73	79
Other post-retirement benefit plans	6	6	6
Savings and DC Plans	41	37	29
	143	116	114

Schedule of Change in Benefit Obligations, Change in Plan Assets, and Funded Status

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Change in Benefit Obligation1
Benefit obligation – beginning of year	2,658		2,224		216		191
Service cost	108		85		3		2
Interest cost	115		113		10		10
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Actuarial (gain)/loss	(57	)	302		(11	)	14
Foreign exchange rate changes	81		32		14		6
Benefit obligation – end of year	2,780		2,658		225		216
Change in Plan Assets
Plan assets at fair value – beginning of year	2,398		2,152		39		35
Actual return on plan assets	160		246		(1	)	2
Employer contributions2	96		73		6		6
Employee contributions	4		4		—		—
Benefits paid	(129	)	(102	)	(7	)	(7	)
Foreign exchange rate changes	62		25		8		3
Plan assets at fair value – end of year	2,591		2,398		45		39
Funded Status – Plan Deficit	(189	)	(260	)	(180	)	(177	)

¹  The benefit obligation for the Company’s pension benefit plans represents the projected benefit obligation. The benefit obligation for the Company’s other post-retirement benefit plans represents the accumulated post-retirement benefit obligation

²  Excludes $214 million in letters of credit provided to the Canadian DB Plans for funding purposes (2014 – $181 million).

Schedule of Amounts Recognized in the for its DB Plans and Other Post-Retirement Benefits Plans

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Intangible and other assets (Note 11)	—		—		18		14
Accounts payable and other	—		—		(7	)	(7	)
Other long-term liabilities (Note 14)	(189	)	(260	)	(191	)	(184	)
	(189	)	(260	)	(180	)	(177	)

Schedule of Benefit Obligations in Excess of Fair Value of Plan Assets

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

at December 31	Pension Benefit Plans				Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2015		2014
Projected benefit obligation1	(2,780	)	(2,658	)	(198	)	(191	)
Plan assets at fair value	2,591		2,398		—		—
Funded Status – Plan Deficit	(189	)	(260	)	(198	)	(191	)

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

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for All DB Plans

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

at December 31	2015		2014
(millions of Canadian $)
Accumulated benefit obligation	(2,600	)	(2,437	)
Plan assets at fair value	2,591		2,398
Funded Status – Plan Deficit	(9	)	(39	)

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets for Plans Not Fully Funded

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

at December 31	2015		2014
(millions of Canadian $)
Accumulated benefit obligation	(807	)	(715	)
Plan assets at fair value	680		597
Funded Status – Plan Deficit	(127	)	(118	)

Schedule of Weighted Average Asset Allocations and Target Allocations by Asset Category

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

	Percentage of Plan Assets				Target Allocations
at December 31	2015		2014		2015
Debt securities	34	%	31	%	25% to 35%
Equity securities	66	%	69	%	50% to 70%
Alternatives	—		—		5 % to 15%
	100	%	100	%

Schedule of Allocation of Plan Assets, Employer and Related Party Securities

Debt and equity securities include the Company's debt and common shares as follows:

at December 31			Percentage of Plan Assets
(millions of Canadian $)	2015	2014	2015		2014
Debt securities	2	1	0.1	%	0.1	%
Equity securities	4	1	0.1	%	0.1	%

Schedule of Plan Assets for DB Plans and Other Post-Retirement Benefits Measured at Fair Value

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

at December 31	Quoted Prices in Active Markets (Level I)		Significant Other Observable Inputs (Level II)		Significant Unobservable Inputs (Level III)		Total		Percentage of Total Portfolio
(millions of Canadian $)	2015	2014	2015	2014	2015	2014	2015	2014	2015	2014
Asset Category
Cash and Cash Equivalents	44	20	2	—	—	—	46	20	2	1
Equity Securities:
Canadian	317	361	147	142	—	—	464	503	17	21
U.S.	589	516	40	35	—	—	629	551	24	23
International	38	218	300	147	—	—	338	365	13	15
Global	—	—	154	141	—	—	154	141	6	6
Emerging	7	7	143	80	—	—	150	87	6	3
Fixed Income Securities:
Canadian Bonds:
Federal	—	—	206	218	—	—	206	218	8	9
Provincial	—	—	202	180	—	—	202	180	8	7
Municipal	—	—	7	7	—	—	7	7	—	—
Corporate	—	—	113	76	—	—	113	76	4	3
U.S. Bonds:
State	—	—	50	47	—	—	50	47	2	2
Corporate	—	—	57	59	—	—	57	59	2	2
International:
Corporate	—	—	25	14	—	—	25	14	1	1
Mortgage backed	—	—	58	39	—	—	58	39	2	2
Other Investments:
Private equity funds	—	—	—	—	14	13	14	13	—	—
Funds held on deposit	123	117	—	—	—	—	123	117	5	5
	1,118	1,239	1,504	1,185	14	13	2,636	2,437	100	100

Schedule of the Net Change in the Level III Fair Value Category

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

(millions of Canadian $, pre-tax)	Private Equity Funds
Balance at December 31, 2013	18
Purchases and sales	(7	)
Realized and unrealized gains	2
Balance at December 31, 2014	13
Purchases and sales	(1	)
Realized and unrealized gains	2
Balance at December 31, 2015	14

Schedule of Estimated Future Benefit Payments,

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

(millions of Canadian $)	Pension Benefits	Other Post- Retirement Benefits
2016	129	8
2017	133	9
2018	138	9
2019	142	9
2020	146	10
2021 to 2025	808	51

Schedule of Weighted Average Assumptions Used in Calculating Benefit Obligation

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

	Pension Benefit Plans				Other Post-Retirement Benefit Plans
at December 31	2015		2014		2015		2014
Discount rate	4.20	%	4.15	%	4.40	%	4.20	%
Rate of compensation increase	0.50	%	3.15	%	—	%	—	%

Schedule of Significant Weighted Average Actuarial Assumptions Adopted in Measuring Net Benefit Plan Costs

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

	Pension Benefit Plans						Other Post-Retirement Benefit Plans
year ended December 31	2015		2014		2013		2015		2014		2013
Discount rate	4.15	%	4.95	%	4.35	%	4.20	%	5.00	%	4.35	%
Expected long-term rate of return on plan assets	6.95	%	6.90	%	6.70	%	4.60	%	4.60	%	4.60	%
Rate of compensation increase	3.15	%	3.15	%	3.15	%	—		—		—

Schedule of Effects of a 1% Change in Assumed Health Care Cost Trend Rates

A one per cent change in assumed health care cost trend rates would have the following effects:

(millions of Canadian $)	Increase	Decrease
Effect on total of service and interest cost components	1	(1	)
Effect on post-retirement benefit obligation	14	(12	)

Schedule of Net Benefit Costs

The Company's net benefit cost recognized is as follows:

at December 31	Pension Benefit Plans						Other Post-Retirement Benefit Plans
(millions of Canadian $)	2015		2014		2013		2015		2014		2013
Service cost	108		85		84		3		2		2
Interest cost	115		113		96		10		10		7
Expected return on plan assets	(155	)	(139	)	(120	)	(2	)	(2	)	(2	)
Amortization of actuarial loss	35		21		30		3		2		2
Amortization of past service cost	2		2		2		1		—		—
Amortization of regulatory asset	23		18		30		1		1		1
Amortization of transitional obligation related to regulated business	—		—		—		2		2		2
Net Benefit Cost Recognized	128		100		122		18		15		12

Schedule of the Pre-Tax Amounts Recognized in AOCI

Pre-tax amounts recognized in AOCI were as follows:

	2015		2014		2013
at December 31	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits	Pension Benefits	Other Post- Retirement Benefits
(millions of Canadian $)
Net loss	247	28	348	39	236	32
Prior service cost	—	—	2	1	3	1
	247	28	350	40	239	33

Schedule of the Pre-Tax Amounts Recognized in OCI

Pre-tax amounts recognized in OCI were as follows:

	2015				2014				2013
at December 31	Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits		Pension Benefits		Other Post- Retirement Benefits
(millions of Canadian $)
Amortization of net loss from AOCI to OCI	(34	)	(4	)	(21	)	(2	)	(30	)	(2	)
Amortization of prior service costs from AOCI to OCI	(2	)	(1	)	(2	)	—		(2	)	—
Funded status adjustment	(67	)	(7	)	137		9		(96	)	—
	(103	)	(12	)	114		7		(128	)	(2	)

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

12 Months Ended

Dec. 31, 2015

Derivative financial instruments

Schedule of Financial Instruments

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2015 is as follows:

at December 31, 2015	Cash Flow Hedges1		Fair Value Hedges1		Net Investment Hedges1		Held for Trading1		Total Fair Value of Derivative Instruments
(millions of Canadian $)
Other current assets (Note 5)
Commodities2	46		—		—		326		372
Foreign exchange	—		—		65		2		67
Interest rate	—		1		—		2		3
	46		1		65		330		442
Intangible and other assets (Note 11)
Commodities2	11		—		—		126		137
Foreign exchange	—		—		29		—		29
Interest rate	—		2		—		—		2
	11		2		29		126		168
Total Derivative Assets	57		3		94		456		610
Accounts payable and other (Note 13)
Commodities2	(112	)	—		—		(443	)	(555	)
Foreign exchange	—		—		(313	)	(54	)	(367	)
Interest rate	(1	)	(1	)	—		(2	)	(4	)
	(113	)	(1	)	(313	)	(499	)	(926	)
Other long-term liabilities (Note 14)
Commodities2	(31	)	—		—		(131	)	(162	)
Foreign exchange	—		—		(461	)	—		(461	)
Interest rate	(1	)	(1	)	—		—		(2	)
	(32	)	(1	)	(461	)	(131	)	(625	)
Total Derivative Liabilities	(145	)	(2	)	(774	)	(630	)	(1,551	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power and natural gas.

The balance sheet classification of the fair value of the derivative instruments as at December 31, 2014 is as follows:

at December 31, 2014	Cash Flow Hedges1		Fair Value Hedges1	Net Investment Hedges1		Held for Trading1		Total Fair Value of Derivative Instruments
(millions of Canadian $)
Other current assets (Note 5)
Commodities2	39		—	—		359		398
Foreign exchange	—		—	5		1		6
Interest rate	—		2	—		3		5
	39		2	5		363		409
Intangible and other assets (Note 11)
Commodities2	18		—	—		72		90
Foreign exchange	—		—	1		—		1
Interest rate	—		1	—		1		2
	18		1	1		73		93
Total Derivative Assets	57		3	6		436		502
Accounts payable and other (Note 13)
Commodities2	(136	)	—	—		(422	)	(558	)
Foreign exchange	—		—	(155	)	(32	)	(187	)
Interest rate	(1	)	—	—		(3	)	(4	)
	(137	)	—	(155	)	(457	)	(749	)
Other long-term liabilities (Note 14)
Commodities2	(27	)	—	—		(72	)	(99	)
Foreign exchange	—		—	(310	)	—		(310	)
Interest rate	(1	)	—	—		(1	)	(2	)
	(28	)	—	(310	)	(73	)	(411	)
Total Derivative Liabilities	(165	)	—	(465	)	(530	)	(1,160	)

¹  Fair value equals carrying value.

²  Includes purchases and sales of power and natural gas.

The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts approximate fair value, and would be classified in Level II of the fair value hierarchy:

	2015				2014
at December 31	Carrying Amount		Fair Value		Carrying Amount		Fair Value
(millions of Canadian $)
Notes receivable1	214		265		213		263
Current and Long-term debt2,3 (Note 16)	(31,584	)	(34,309	)	(24,757	)	(28,713	)
Junior subordinated notes (Note 17)	(2,422	)	(2,011	)	(1,160	)	(1,157	)
	(33,792	)	(36,055	)	(25,704	)	(29,607	)

¹  Notes receivable are included in Other current assets and Intangible and other assets on the Consolidated balance sheet.

²  Long-term debt is recorded at amortized cost, except for US$850 million (2014 – US$400 million) that is attributed to hedged risk and recorded at fair value.

³  Consolidated Net income in 2015 included gains of $2 million (2014 – losses of $3 million) for fair value adjustments attributable to the hedged interest rate risk associated with interest rate swap fair value hedging relationships on US$850 million of Long-term debt at December 31, 2015 (2014 – US$400 million). There were no other unrealized gains or losses from fair value adjustments to the non-derivative financial instruments.

Available for Sale Assets Summary

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

	2015		2014
at December 31	LMCI Restricted Investments1	Other Restricted Investments2	LMCI Restricted Investments1	Other Restricted Investments2
(millions of Canadian $)
Fair values
Fixed income securities (maturing within 5 years)	—	90	—	75
Fixed income securities (maturing after 10 years)	261	—	—	—
	261	90	—	75

¹  Gains and losses arising from changes in the fair value of LMCI restricted investments impact the subsequent amounts to be collected through tolls to cover future pipeline abandonment costs. As a result, the Company would record these gains and losses as regulatory assets or liabilities. In 2015 and 2014, there were no net realized or unrealized gains or losses on LMCI restricted investments.

²  Other restricted investments have been set aside to fund insurance claim losses to be paid by the Company's wholly-owned captive insurance subsidiary. In 2015 and 2014, there were no net realized or unrealized gains or losses on other restricted investments.

Summary of Derivative Instruments

The following tables present the maturity and notional principal or quantity outstanding related to the Company's derivative instruments excluding hedges of the net investment in foreign operations:

at December 31, 2015	Power	Natural Gas	Foreign Exchange	Interest
Purchases1	70,331	133	—	—
Sales1	54,382	70	—	—
Millions of dollars	—	—	US 1,476	US 1,100
Maturity dates	2016–2020	2016–2020	2016	2016–2019

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

at December 31, 2014	Power	Natural Gas	Foreign Exchange	Interest
Purchases1	53,217	60	—	—
Sales1	39,429	38	—	—
Millions of dollars	—	—	US 1,374	US 650
Maturity dates	2015–2019	2015–2020	2015	2015–2018

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

Summary of Unrealized and Realized Gains/(Losses) of Derivative Instruments

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

year ended December 31	2015		2014
(millions of Canadian $)
Derivative instruments held for trading1
Amount of unrealized losses in the year
Commodities	(37	)	(40	)
Foreign exchange	(21	)	(20	)
Amount of realized losses in the year
Commodities	(151	)	(28	)
Foreign exchange	(112	)	(28	)
Derivative instruments in hedging relationships2,3
Amount of realized (losses)/gains in the year
Commodities	(179	)	130
Interest rate	8		4

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 derivative instruments held for trading are included net in Interest expense and Interest income and other, respectively.

²  In 2015, net realized gains on fair value hedges were $11 million (2014 – gains of $7 million) and were included in Interest expense.

³  In 2015 and 2014, 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.

Schedule of Components of OCI related to Derivatives in Cash Flow Hedging Relationships

The components of OCI (Note 21) related to derivatives in cash flow hedging relationships are as follows:

year ended December 31	2015		2014
(millions of Canadian $, pre-tax)
Change in fair value of derivative instruments recognized in OCI (effective portion)1
Commodities	(92	)	(128	)
Foreign exchange	—		10
	(92	)	(118	)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net income (effective portion)1
Commodities2	128		(111	)
Interest rate3	16		16
	144		(95	)
Losses on derivative instruments recognized in Net income (ineffective portion)
Commodities2	—		(13	)

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

²  Reported within Revenues on the Consolidated statement of income.

³  Reported within Interest expense on the Consolidated statement of income.

Schedule of Offsetting Assets

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

at December 31, 2015	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
	(1,551	)	512		(1,039	)

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

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2014:

at December 31, 2014	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	488		(387	)	101
Foreign exchange	7		(7	)	—
Interest rate	7		(1	)	6
	502		(395	)	107
Derivative - Liability
Commodities	(657	)	387		(270	)
Foreign exchange	(497	)	7		(490	)
Interest rate	(6	)	1		(5	)
	(1,160	)	395		(765	)

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

Schedule of Offsetting Liabilities

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

at December 31, 2015	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	509		(418	)	91
Foreign exchange	96		(93	)	3
Interest rate	5		(1	)	4
	610		(512	)	98
Derivative - Liability
Commodities	(717	)	418		(299	)
Foreign exchange	(828	)	93		(735	)
Interest rate	(6	)	1		(5	)
	(1,551	)	512		(1,039	)

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

The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2014:

at December 31, 2014	Gross Derivative Instruments Presented on the Balance Sheet		Amounts Available for Offset1		Net Amounts
(millions of Canadian $)
Derivative - Asset
Commodities	488		(387	)	101
Foreign exchange	7		(7	)	—
Interest rate	7		(1	)	6
	502		(395	)	107
Derivative - Liability
Commodities	(657	)	387		(270	)
Foreign exchange	(497	)	7		(490	)
Interest rate	(6	)	1		(5	)
	(1,160	)	395		(765	)

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

Schedule of Fair Value of Assets and Liabilities Measured on a Recurring Basis

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2015, are categorized as follows:

at December 31, 2015	Quoted Prices in Active Markets Level I1		Significant Other Observable Inputs Level II1		Significant Unobservable Inputs Level III1		Total
(millions of Canadian $)
Derivative Instrument Assets:
Commodities	34		462		13		509
Foreign exchange	—		96		—		96
Interest rate	—		5		—		5
Derivative Instrument Liabilities:
Commodities	(102	)	(611	)	(4	)	(717	)
Foreign exchange	—		(828	)	—		(828	)
Interest rate	—		(6	)	—		(6	)
	(68	)	(882	)	9		(941	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2015.

The fair value of the Company's derivative assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:

at December 31, 2014	Quoted Prices in Active Markets Level I1		Significant Other Observable Inputs Level II1		Significant Unobservable Inputs Level III1		Total
(millions of Canadian $)
Derivative Instrument Assets:
Commodities	40		441		7		488
Foreign exchange	—		7		—		7
Interest rate	—		7		—		7
Derivative Instrument Liabilities:
Commodities	(86	)	(568	)	(3	)	(657	)
Foreign exchange	—		(497	)	—		(497	)
Interest rate	—		(6	)	—		(6	)
	(46	)	(616	)	4		(658	)

¹  There were no transfers from Level I to Level II or from Level II to Level III for the year ended December 31, 2014.

Schedule of Net Change in the Level III Fair Value Category

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

(millions of Canadian $, pre-tax)	2015		2014
Balance at beginning of year	4		1
Transfers out of Level III	5		—
Total gains included in Net income	3		3
Sales	(2	)	—
Settlements	(1	)	—
Balance at end of year1	9		4

¹  Revenues include unrealized gains attributed to derivatives in the Level III category that were still held at December 31, 2015 of $7 million (2014 – $3 million).

Designated as a net investment hedge

Derivative financial instruments

Summary of Derivative Instruments

U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge

at December 31	2015	2014
(millions of Canadian $, unless otherwise noted)
Carrying value	23,000 (US 16,600)	17,000 (US 14,700)
Fair value	23,800 (US 17,200)	19,000 (US 16,400)

Derivatives Designated as a Net Investment Hedge

	2015				2014
at December 31	Fair Value1		Notional or Principal Amount		Fair Value1		Notional or Principal Amount
(millions of Canadian $, unless otherwise noted)
U.S. dollar cross-currency interest rate swaps (maturing 2016 to 2019)2	(730	)	US	3,150	(431	)	US	2,900
U.S. dollar foreign exchange forward contracts (maturing 2016 to 2017)	50		US	1,800	(28	)	US	1,400
	(680	)	US	4,950	(459	)	US	4,300

¹  Fair values equal carrying values.

²  In 2015, net realized gains of $8 million (2014 – gains of $21 million) related to the interest component of cross-currency swap settlements are included in Interest expense.

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CHANGES IN OPERATING WORKING CAPITAL (Tables)

12 Months Ended

Dec. 31, 2015

CHANGES IN OPERATING WORKING CAPITAL

Schedule of changes in operating working capital

year ended December 31	2015		2014		2013
(millions of Canadian $)
Increase in Accounts receivable	(20	)	(205	)	(60	)
Increase in Inventories	(3	)	(27	)	(30	)
(Increase)/decrease in Other current assets	(268	)	(386	)	40
(Decrease)/increase in Accounts payable and other	(159	)	393		(291	)
Increase in Accrued interest	91		36		7
Increase in Operating Working Capital	(359	)	(189	)	(334	)

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COMMITMENTS, CONTINGENCIES AND GUARANTEES (Tables)

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Annual Payments

Future annual payments under the Company's operating leases for various premises, services and equipment as well as fixed payments on Alberta PPAs, net of sublease receipts, are approximately as follows:

year ended December 31	Minimum Lease Payments	Amounts Recoverable under Sub-leases	Net Payments
(millions of Canadian $)
2016	354	46	308
2017	355	45	310
2018	270	26	244
2019	248	24	224
2020	185	20	165
2021 and thereafter	311	1	310
	1,723	162	1,561

Schedule of Generating Capacities and Expiry Dates of the PPAs

The generating capacities and expiry dates of the PPAs are as follows:

	MW	Expiry Date
Sundance A	560	December 31, 2017
Sheerness	756	December 31, 2020

Schedule of Guarantees

Information regarding the Company’s guarantees is as follows:

		2015		2014
year ended December 31	Term	Potential Exposure1	Carrying Value	Potential Exposure1	Carrying Value
(millions of Canadian $)
Bruce Power	Ranging to 20182	88	2	634	6
Other jointly owned entities	Ranging to 2040	139	24	104	14
		227	26	738	20

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

²  Except for one guarantee with no termination date.

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RELATED PARTY TRANSACTIONS (Tables)

12 Months Ended

Dec. 31, 2015

Related Party Transactions [Abstract]

Amounts included in due from/to affiliates

The following amounts are included in Due from affiliates:

		2015			2014
(millions of Canadian $)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
Discount Notes1	2016	2,376	0.9	%	2,597	1.3	%
Credit Facility2		100	2.7	%	245	3.0	%
		2,476			2,842

¹  Issued to TransCanada. Interest on the discount notes is equivalent to current commercial paper rates.

²  Issued to TransCanada. This facility is repayable on demand and bears interest at the Royal Bank of Canada prime rate per annum.

The following amounts are included in Due to affiliates:

		2015			2014
(millions of Canadian $)	Maturity Date	Outstanding at December 31	Effective Interest Rate		Outstanding at December 31	Effective Interest Rate
Credit Facility1	2016	311	3.5	%	866	3.8	%
		311			866

¹  TransCanada has an unsecured $3.5 billion credit facility with a subsidiary of TCPL. Interest on this facility is charged at Reuters prime rate plus 75 basis points.

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DESCRIPTION OF TCPL'S BUSINESS (Details)	12 Months Ended
	Dec. 31, 2015 plant segment Bcf facility mi km
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of business segments in which the entity operates | segment	3
Investments of regulated natural gas pipelines (in kilometers) | km	67,300
Investments of regulated natural gas pipelines (in miles) | mi	41,900
Investments of regulated natural gas storage facilities (in billion cubic feet) | Bcf	250
Wholly owned and operated crude oil pipeline systems (in kilometers) | km	4,247
Wholly owned and operated crude oil pipeline systems (in miles) | mi	2,639
Number of electrical power generation plants | plant	19
Number of non-regulated natural gas storage facilities | facility	2

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ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2015 level
Annual review for goodwill impairment
Number of levels below operating segments level considered for measuring reporting unit level	1
Employee Post-Retirement Benefits
Moving average period of basis used to determine expected return on plan assets	5 years
Corporate | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	3.00%
Corporate | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	20.00%
Natural Gas Pipelines | Pipeline | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	1.00%
Natural Gas Pipelines | Pipeline | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	6.00%
Natural Gas Pipelines | Compression | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	1.00%
Natural Gas Pipelines | Compression | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	6.00%
Liquids Pipelines | Pipeline | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.00%
Liquids Pipelines | Pipeline | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.50%
Liquids Pipelines | Pumping equipment | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.00%
Liquids Pipelines | Pumping equipment | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.50%
Energy | Power generation and natural gas storage plant, equipment and structures | Minimum
Plant, property and equipment
Annual depreciation rate on straight-line basis	2.00%
Energy | Power generation and natural gas storage plant, equipment and structures | Maximum
Plant, property and equipment
Annual depreciation rate on straight-line basis	20.00%

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SEGMENTED INFORMATION (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segmented information
Revenues	CAD 11,300	CAD 10,185	CAD 8,797
Income from Equity Investments (Note 8)	440	522	597
Plant operating costs and other	(3,250)	(2,973)	(2,674)
Commodity purchases resold	(2,237)	(1,836)	(1,317)
Property taxes	(517)	(473)	(445)
Depreciation and amortization	(1,765)	(1,611)	(1,485)
Asset impairment charges	(3,745)
Loss on assets held for sale	(125)	117
Segmented earnings/(losses)	101	3,931	3,473
Interest expense	(1,398)	(1,235)	(1,046)
Interest income and other	192	128	72
(Loss)/Income before Income Taxes	(1,105)	2,824	2,499
Income tax expense	(35)	(830)	(605)
Net (Loss)/Income	(1,140)	1,994	1,894
Net income attributable to non-controlling interests	(6)	(151)	(105)
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,843	1,789
Preferred share dividends		(2)	(20)
Net (Loss)/Income Attributable to Common Shares	(1,146)	1,841	1,769
Capital spending
Capital expenditures	3,918	3,489	4,264
Capital projects in development	511	848	488
Payments to Acquire Productive Assets	4,429	4,337	4,752
Assets	66,929	61,415
GEOGRAPHIC INFORMATION
Revenues	11,300	10,185	8,797
Plant, Property and Equipment	44,817	41,774
Canada
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	19,287	19,191
Canada - domestic
Segmented information
Revenues	3,877	3,956	4,659
GEOGRAPHIC INFORMATION
Revenues	3,877	3,956	4,659
Canada - export
Segmented information
Revenues	1,292	1,314	997
GEOGRAPHIC INFORMATION
Revenues	1,292	1,314	997
United States
Segmented information
Revenues	5,872	4,718	3,029
GEOGRAPHIC INFORMATION
Revenues	5,872	4,718	3,029
Plant, Property and Equipment	21,899	20,098
Mexico
Segmented information
Revenues	259	197	112
GEOGRAPHIC INFORMATION
Revenues	259	197	112
Plant, Property and Equipment	3,631	2,485
Corporate
Segmented information
Plant operating costs and other	(270)	(127)	(108)
Depreciation and amortization	(31)	(23)	(16)
Segmented earnings/(losses)	(301)	(150)	(124)
Capital spending
Capital expenditures	64	46	50
Payments to Acquire Productive Assets	64	46	50
Assets	4,253	3,999
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	185	152
Natural Gas Pipelines | Operating segments
Segmented information
Revenues	5,383	4,913	4,497
Income from Equity Investments (Note 8)	179	163	145
Plant operating costs and other	(1,736)	(1,501)	(1,405)
Property taxes	(349)	(334)	(329)
Depreciation and amortization	(1,132)	(1,063)	(1,027)
Loss on assets held for sale	(125)	9
Segmented earnings/(losses)	2,220	2,187	1,881
Capital spending
Capital expenditures	2,466	1,768	1,776
Capital projects in development	233	368	245
Payments to Acquire Productive Assets	2,699	2,136	2,021
Assets	31,072	27,103
GEOGRAPHIC INFORMATION
Revenues	5,383	4,913	4,497
Plant, Property and Equipment	23,317	20,204
Natural Gas Pipelines | Operating segments | Mexico
GEOGRAPHIC INFORMATION
Plant, Property and Equipment	3,623	2,486
Liquids Pipelines | Operating segments
Segmented information
Revenues	1,879	1,547	1,124
Plant operating costs and other	(478)	(426)	(328)
Property taxes	(79)	(62)	(44)
Depreciation and amortization	(266)	(216)	(149)
Asset impairment charges	(3,686)
Segmented earnings/(losses)	(2,630)	843	603
Capital spending
Capital expenditures	1,012	1,469	2,286
Capital projects in development	278	480	243
Payments to Acquire Productive Assets	1,290	1,949	2,529
Assets	16,046	16,116
GEOGRAPHIC INFORMATION
Revenues	1,879	1,547	1,124
Plant, Property and Equipment	14,186	14,928
Energy | Operating segments
Segmented information
Revenues	4,038	3,725	3,176
Income from Equity Investments (Note 8)	261	359	452
Plant operating costs and other	(766)	(919)	(833)
Commodity purchases resold	(2,237)	(1,836)	(1,317)
Property taxes	(89)	(77)	(72)
Depreciation and amortization	(336)	(309)	(293)
Asset impairment charges	(59)
Loss on assets held for sale		108
Segmented earnings/(losses)	812	1,051	1,113
Capital spending
Capital expenditures	376	206	152
Payments to Acquire Productive Assets	376	206	152
Assets	15,558	14,197
GEOGRAPHIC INFORMATION
Revenues	4,038	3,725	CAD 3,176
Plant, Property and Equipment	CAD 7,129	CAD 6,490

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OTHER CURRENT ASSETS (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Assets [Abstract]
Cash held as collateral	CAD 585	CAD 423
Fair value of derivative contracts (Note 23)	442	409
Regulatory assets (Note 9)	85	16
Assets held for sale (Note 6)	20
Other	221	170
Other current assets, total	CAD 1,353	CAD 1,018

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ASSETS HELD FOR SALE (Details) - CAD CAD in Millions		12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Assets Held for Sale
Accounts receivable	CAD 4	CAD 4
Inventories	1	1
Other current assets	1	1
Plant, property and equipment	14	14
Total Assets Held for Sale (included in Other current assets, Note 5)	20	20
Liabilities Related to Assets Held for Sale
Accounts payable and other	38	38
Other long-term liabilities	1	1
Total Liabilities Related to Assets Held for Sale (included in Accounts payable and other, Note 13)	39	39
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal		CAD (125)	CAD 117
TC Offshore LLC | Disposal group, not discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain (loss) on disposal	CAD (125)

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PLANT, PROPERTY AND EQUIPMENT (Details) CAD in Millions		12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD facility	Dec. 31, 2013 CAD
Plant, property and equipment
Cost	CAD 67,116	CAD 67,116	CAD 61,638
Accumulated Depreciation	22,299	22,299	19,864
Net Book Value	44,817	44,817	41,774
Plant and equipment
Plant, property and equipment
Estimated fair value	463	463
Energy Turbine
Plant, property and equipment
Impairment charge, Pre-tax	59
Impairment charge, After-tax	43
Mexico
Plant, property and equipment
Net Book Value	3,631	3,631	2,485
Keystone XL
Plant, property and equipment
Estimated Fair Value	621	621
Impairment charge, Pre-tax	3,686
Impairment charge, After-tax	2,891
Estimated fair value	621	621
Keystone XL | Plant and equipment
Plant, property and equipment
Estimated Fair Value	463	463
Impairment charge, Pre-tax	1,460
Impairment charge, After-tax	CAD 1,391
Keystone XL | Plant and equipment | Market Approach Valuation Technique
Plant, property and equipment
Disposal period	2 years
Keystone XL | Terminals, including KHT
Plant, property and equipment
Estimated Fair Value	CAD 158	158
Impairment charge, Pre-tax	274
Impairment charge, After-tax	219
Keystone XL | Intangible assets
Plant, property and equipment
Impairment charge, Pre-tax	1,150
Impairment charge, After-tax	737
Keystone XL | Capitalized interest
Plant, property and equipment
Impairment charge, Pre-tax	725
Impairment charge, After-tax	488
Keystone XL | Future cancellation costs
Plant, property and equipment
Impairment charge, Pre-tax	77
Impairment charge, After-tax	56
Energy | Facilities under PPAs
Plant, property and equipment
Cost	813	813	695
Accumulated Depreciation	142	142	103
Revenues recognized through the sale of electricity		93	81	CAD 78
Operating segments | Natural Gas Pipelines
Plant, property and equipment
Cost	42,054	42,054	37,377
Accumulated Depreciation	18,737	18,737	17,173
Net Book Value	23,317	23,317	20,204
Operating segments | Natural Gas Pipelines | Mexico
Plant, property and equipment
Cost	3,826	3,826	2,616
Accumulated Depreciation	203	203	130
Net Book Value	3,623	3,623	2,486
Operating segments | Natural Gas Pipelines | Pipeline | Mexico
Plant, property and equipment
Cost	1,296	1,296	1,053
Accumulated Depreciation	162	162	104
Net Book Value	1,134	1,134	949
Operating segments | Natural Gas Pipelines | Compression | Mexico
Plant, property and equipment
Cost	183	183	151
Accumulated Depreciation	14	14	6
Net Book Value	169	169	145
Operating segments | Natural Gas Pipelines | Metering and other | Mexico
Plant, property and equipment
Cost	388	388	314
Accumulated Depreciation	27	27	20
Net Book Value	361	361	294
Operating segments | Natural Gas Pipelines | Property, plant and equipment excluding under construction | Mexico
Plant, property and equipment
Cost	1,867	1,867	1,518
Accumulated Depreciation	203	203	130
Net Book Value	1,664	1,664	1,388
Operating segments | Natural Gas Pipelines | Under construction | Mexico
Plant, property and equipment
Cost	1,959	1,959	1,098
Net Book Value	1,959	1,959	1,098
Operating segments | Natural Gas Pipelines | Canadian Mainline
Plant, property and equipment
Cost	13,353	13,353	13,061
Accumulated Depreciation	8,378	8,378	7,992
Net Book Value	4,975	4,975	5,069
Operating segments | Natural Gas Pipelines | Canadian Mainline | Pipeline
Plant, property and equipment
Cost	9,164	9,164	9,045
Accumulated Depreciation	5,966	5,966	5,712
Net Book Value	3,198	3,198	3,333
Operating segments | Natural Gas Pipelines | Canadian Mainline | Compression
Plant, property and equipment
Cost	3,433	3,433	3,423
Accumulated Depreciation	2,220	2,220	2,100
Net Book Value	1,213	1,213	1,323
Operating segments | Natural Gas Pipelines | Canadian Mainline | Metering and other
Plant, property and equipment
Cost	499	499	458
Accumulated Depreciation	192	192	180
Net Book Value	307	307	278
Operating segments | Natural Gas Pipelines | Canadian Mainline | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	13,096	13,096	12,926
Accumulated Depreciation	8,378	8,378	7,992
Net Book Value	4,718	4,718	4,934
Operating segments | Natural Gas Pipelines | Canadian Mainline | Under construction
Plant, property and equipment
Cost	257	257	135
Net Book Value	257	257	135
Operating segments | Natural Gas Pipelines | NGTL System
Plant, property and equipment
Cost	12,709	12,709	11,685
Accumulated Depreciation	5,713	5,713	5,383
Net Book Value	6,996	6,996	6,302
Operating segments | Natural Gas Pipelines | NGTL System | Pipeline
Plant, property and equipment
Cost	8,456	8,456	8,185
Accumulated Depreciation	3,820	3,820	3,619
Net Book Value	4,636	4,636	4,566
Operating segments | Natural Gas Pipelines | NGTL System | Compression
Plant, property and equipment
Cost	2,188	2,188	2,055
Accumulated Depreciation	1,404	1,404	1,318
Net Book Value	784	784	737
Operating segments | Natural Gas Pipelines | NGTL System | Metering and other
Plant, property and equipment
Cost	1,096	1,096	1,032
Accumulated Depreciation	489	489	446
Net Book Value	607	607	586
Operating segments | Natural Gas Pipelines | NGTL System | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	11,740	11,740	11,272
Accumulated Depreciation	5,713	5,713	5,383
Net Book Value	6,027	6,027	5,889
Operating segments | Natural Gas Pipelines | NGTL System | Under construction
Plant, property and equipment
Cost	969	969	413
Net Book Value	969	969	413
Operating segments | Natural Gas Pipelines | ANR
Plant, property and equipment
Cost	3,831	3,831	2,861
Accumulated Depreciation	789	789	598
Net Book Value	3,042	3,042	2,263
Operating segments | Natural Gas Pipelines | ANR | Pipeline
Plant, property and equipment
Cost	1,449	1,449	1,217
Accumulated Depreciation	350	350	227
Net Book Value	1,099	1,099	990
Operating segments | Natural Gas Pipelines | ANR | Compression
Plant, property and equipment
Cost	1,101	1,101	780
Accumulated Depreciation	187	187	140
Net Book Value	914	914	640
Operating segments | Natural Gas Pipelines | ANR | Metering and other
Plant, property and equipment
Cost	977	977	737
Accumulated Depreciation	252	252	231
Net Book Value	725	725	506
Operating segments | Natural Gas Pipelines | ANR | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	3,527	3,527	2,734
Accumulated Depreciation	789	789	598
Net Book Value	2,738	2,738	2,136
Operating segments | Natural Gas Pipelines | ANR | Under construction
Plant, property and equipment
Cost	304	304	127
Net Book Value	304	304	127
Operating segments | Natural Gas Pipelines | Other Natural Gas Pipelines
Plant, property and equipment
Cost	8,335	8,335	7,154
Accumulated Depreciation	3,654	3,654	3,070
Net Book Value	4,681	4,681	4,084
Operating segments | Natural Gas Pipelines | Other Natural Gas Pipelines | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	8,264	8,264	7,120
Accumulated Depreciation	3,654	3,654	3,070
Net Book Value	4,610	4,610	4,050
Operating segments | Natural Gas Pipelines | Other Natural Gas Pipelines | Under construction
Plant, property and equipment
Cost	71	71	34
Net Book Value	71	71	34
Operating segments | Natural Gas Pipelines | GTN | Pipeline
Plant, property and equipment
Cost	2,278	2,278	1,842
Accumulated Depreciation	765	765	588
Net Book Value	1,513	1,513	1,254
Operating segments | Natural Gas Pipelines | Great Lakes | Pipeline
Plant, property and equipment
Cost	2,157	2,157	1,807
Accumulated Depreciation	1,155	1,155	939
Net Book Value	1,002	1,002	868
Operating segments | Natural Gas Pipelines | Foothills | Pipeline
Plant, property and equipment
Cost	1,606	1,606	1,671
Accumulated Depreciation	1,162	1,162	1,180
Net Book Value	444	444	491
Operating segments | Natural Gas Pipelines | Other | Pipeline
Plant, property and equipment
Cost	2,223	2,223	1,800
Accumulated Depreciation	572	572	363
Net Book Value	1,651	1,651	1,437
Operating segments | Liquids Pipelines
Plant, property and equipment
Cost	15,240	15,240	15,615
Accumulated Depreciation	1,054	1,054	687
Net Book Value	14,186	14,186	14,928
Operating segments | Liquids Pipelines | Under construction
Plant, property and equipment
Cost	1,826	1,826	4,438
Net Book Value	1,826	1,826	4,438
Operating segments | Liquids Pipelines | Keystone | Pipeline
Plant, property and equipment
Cost	9,288	9,288	7,931
Accumulated Depreciation	718	718	463
Net Book Value	8,570	8,570	7,468
Operating segments | Liquids Pipelines | Keystone | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	13,414	13,414	11,177
Accumulated Depreciation	1,054	1,054	687
Net Book Value	12,360	12,360	10,490
Operating segments | Liquids Pipelines | Keystone | Pumping equipment
Plant, property and equipment
Cost	1,092	1,092	964
Accumulated Depreciation	108	108	80
Net Book Value	984	984	884
Operating segments | Liquids Pipelines | Keystone | Tanks and other
Plant, property and equipment
Cost	3,034	3,034	2,282
Accumulated Depreciation	228	228	144
Net Book Value	2,806	2,806	2,138
Operating segments | Energy
Plant, property and equipment
Cost	9,555	9,555	8,414
Accumulated Depreciation	2,426	2,426	1,924
Net Book Value	7,129	7,129	6,490
Operating segments | Energy | Property, plant and equipment excluding under construction
Plant, property and equipment
Cost	9,125	9,125	8,265
Accumulated Depreciation	2,426	2,426	1,924
Net Book Value	6,699	6,699	6,341
Operating segments | Energy | Under construction
Plant, property and equipment
Cost	430	430	149
Net Book Value	430	430	149
Operating segments | Energy | Natural Gas – Ravenswood
Plant, property and equipment
Cost	2,607	2,607	2,140
Accumulated Depreciation	654	654	476
Net Book Value	1,953	1,953	1,664
Operating segments | Energy | Natural Gas - Other
Plant, property and equipment
Cost	3,361	3,361	3,214
Accumulated Depreciation	1,164	1,164	971
Net Book Value	2,197	2,197	2,243
Operating segments | Energy | Hydro, Wind and Solar
Plant, property and equipment
Cost	2,417	2,417	2,194
Accumulated Depreciation	476	476	359
Net Book Value	1,941	1,941	1,835
Operating segments | Energy | Natural Gas Storage and Other
Plant, property and equipment
Cost	740	740	717
Accumulated Depreciation	132	132	118
Net Book Value	608	608	CAD 599
Operating segments | Energy | Solar
Plant, property and equipment
Number of facilities acquired | facility			4
Corporate
Plant, property and equipment
Cost	267	267	CAD 232
Accumulated Depreciation	82	82	80
Net Book Value	CAD 185	CAD 185	CAD 152

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EQUITY INVESTMENTS - Schedule and Narrative (Details) CAD in Millions, $ in Millions		12 Months Ended
	Dec. 03, 2015 CAD	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD	Dec. 31, 2013 CAD	Dec. 31, 2015 USD ($)	Dec. 30, 2015	Dec. 04, 2015	Dec. 02, 2015	Dec. 31, 2014 USD ($)	May. 31, 2013	Apr. 30, 2013
Equity Investments
Income / (Loss) from Equity Investments		CAD 440	CAD 522	CAD 597
Equity Investments		6,214	5,598
Distributions received from equity investments		802	738	733
Returns of capital		226	159	128
Undistributed earnings		198	551	754
Contributions made to equity investments		CAD 493	CAD 256	CAD 163
TC PipeLines, LP
Equity Investments
Ownership interest in subsidiary		28.00%	28.30%	28.90%	28.00%				28.30%	28.90%	33.30%
Northern Border
Equity Investments
Difference between the carrying value of the investment and the underlying equity in the net assets | $					$ 117				$ 117
Bruce Power
Equity Investments
Ownership interest		48.50%			48.50%		48.50%
Difference between the carrying value of the investment and the underlying equity in the net assets		CAD 973	CAD 776
Bruce A
Equity Investments
Ownership interest						48.90%		48.90%
Bruce B
Equity Investments
Ownership interest	46.50%					31.60%		31.60%
Contributions made to equity investments	CAD 236
Natural Gas Pipelines | Northern Border
Equity Investments
Ownership interest		14.00%	14.20%	14.50%	14.00%				14.20%
Income / (Loss) from Equity Investments		CAD 85	CAD 76	CAD 66
Equity Investments		CAD 664	587
Natural Gas Pipelines | Northern Border | TC PipeLines, LP
Equity Investments
Ownership interest		50.00%			50.00%
Natural Gas Pipelines | Iroquois
Equity Investments
Ownership interest		44.50%			44.50%
Income / (Loss) from Equity Investments		CAD 51	43	41
Equity Investments		CAD 238	210
Natural Gas Pipelines | TQM
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		CAD 12	12	13
Equity Investments		72	73
Natural Gas Pipelines | Other
Equity Investments
Income / (Loss) from Equity Investments		31	32	25
Equity Investments		CAD 73	68
Liquids Pipelines | Grand Rapids
Equity Investments
Ownership interest		50.00%			50.00%
Equity Investments		CAD 542	240
Liquids Pipelines | Canaport Energy East Marine Terminal
Equity Investments
Ownership interest		50.00%			50.00%
Equity Investments		CAD 16
Energy | Other
Equity Investments
Income / (Loss) from Equity Investments		5	1	1
Equity Investments		CAD 67	61
Energy | Bruce Power
Equity Investments
Ownership interest		48.50%			48.50%
Income / (Loss) from Equity Investments		CAD 249	314	310
Equity Investments		CAD 4,200	3,995
Energy | ASTC Power Partnership
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		CAD (23)	8	110
Equity Investments		CAD 21	29
Energy | Portlands Energy
Equity Investments
Ownership interest		50.00%			50.00%
Income / (Loss) from Equity Investments		CAD 30	36	CAD 31
Equity Investments		CAD 321	CAD 335

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EQUITY INVESTMENTS - Summarized Financial Information of Equity Investments (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income
Revenues	CAD 4,337	CAD 4,814	CAD 4,989
Operating and other expenses	(3,254)	(3,489)	(3,536)
Net income	1,046	1,264	1,390
Net income attributable to TCPL	440	522	CAD 597
Balance Sheet
Current assets	1,530	1,412
Non-current assets	13,190	12,260
Current liabilities	(1,370)	(1,067)
Non-current liabilities	CAD (3,116)	CAD (3,255)

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RATE-REGULATED BUSINESSES - Narrative (Details) - CAD CAD in Millions			1 Months Ended			12 Months Ended			24 Months Ended	48 Months Ended
	Jul. 01, 2015	Nov. 28, 2014	Feb. 28, 2015	Nov. 30, 2013	Mar. 31, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2021	Dec. 31, 2019
Rate-regulated business
Allowance for funds used during construction						CAD 295	CAD 136	CAD 37
Settlement, reduction in rates	3.00%
Scenario, forecast
Rate-regulated business
Settlement, reduction in rates									8.00%	10.00%
Canadian Mainline | Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity		10.10%			11.50%
Deemed common equity		40.00%			40.00%
Term of regulatory decision					5 years			5 years
After-tax annual contribution to reduce revenue requirement		CAD 20
Fixed toll term		6 years
NGTL System | National Energy Board | 2015 Revenue Requirement Settlement
Rate-regulated business
Approved ROE on deemed common equity			10.10%
Deemed common equity			40.00%
Period of settlement			1 year
Composite depreciation rate							3.12%
NGTL System | National Energy Board | 2015 Revenue Requirement Settlement | Canadian Regulated Operations
Rate-regulated business
Approved ROE on deemed common equity				10.10%
Deemed common equity				40.00%

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RATE-REGULATED BUSINESSES - Assets and Liabilities (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Regulatory Assets
Total regulatory assets	CAD 1,269	CAD 1,313
Less: Current portion included in Other current assets (Note 5)	85	16
Regulatory assets, noncurrent	1,184	1,297
Regulatory Liabilities
Total regulatory liabilities	1,203	293
Less: Current portion included in Accounts payable and other (Note 13)	44	30
Regulated liabilities, noncurrent	CAD 1,159	263
Foreign exchange on long-term debt
Regulatory Liabilities
Total regulatory liabilities		42
Foreign exchange on long-term debt | Minimum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)	1 year
Foreign exchange on long-term debt | Maximum
Regulatory Liabilities
Remaining Recovery/ Settlement Period (years)	14 years
Operating and debt-service regulatory liabilities
Regulatory Liabilities
Total regulatory liabilities	CAD 32	21
Remaining Recovery/ Settlement Period (years)	1 year
Pensions and other post retirement benefits
Regulatory Liabilities
Total regulatory liabilities	CAD 147	117
Long term adjustment account
Regulatory Liabilities
Total regulatory liabilities	CAD 231	64
Remaining Recovery/ Settlement Period (years)	45 years
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	CAD 167	418	CAD (247)
Pipeline abandonment costs
Regulatory Liabilities
Total regulatory liabilities	285
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	285
Bridging amortization account
Regulatory Liabilities
Total regulatory liabilities	CAD 456
Remaining Recovery/ Settlement Period (years)	15 years
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	CAD 456
Other
Regulatory Liabilities
Total regulatory liabilities	52	49
Deferred income taxes
Regulatory Assets
Total regulatory assets	848	1,001
Operating and debt-service regulatory assets
Regulatory Assets
Total regulatory assets	CAD 47	4
Remaining Recovery/ Settlement Period (years)	1 year
Operating and debt-service regulatory assets | Operating and debt-service regulatory liabilities
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	CAD (32)	28	(76)
Pensions and other post retirement benefits
Regulatory Assets
Total regulatory assets	210	236
Pensions and other post retirement benefits | Pensions and other post retirement benefits
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	26	(46)	171
Foreign exchange on long-term debt
Regulatory Assets
Total regulatory assets	CAD 54
Foreign exchange on long-term debt | Minimum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	1 year
Foreign exchange on long-term debt | Maximum
Regulatory Assets
Remaining Recovery/ Settlement Period (years)	14 years
Other
Regulatory Assets
Total regulatory assets	CAD 110	72
Other | Other
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	(35)	2	2
Postretirement benefit costs | Postretirement benefit costs
Other disclosures pertaining to regulated assets and liabilities
Amount by which pre-tax operating results would have been higher (lower) if regulatory assets and liabilities had not been recorded	CAD 30	CAD 13	CAD 16

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GOODWILL (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD	Dec. 31, 2015 CAD	Dec. 31, 2015 USD ($)
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	CAD 4,034		CAD 3,696	CAD 4,812
Goodwill
Balance at the beginning of the period	4,034		3,696
Foreign exchange rate changes	778		338
Balance at the end of the period	CAD 4,812		4,034
Great Lakes
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill | $		$ 573			$ 573
Estimated fair value exceeds carrying value				10.00%	10.00%
Reduced forecasted cash flows, number of years	10 years	10 years
Goodwill
Balance at the beginning of the period | $		$ 573
Balance at the end of the period | $		573
Great Lakes | TC PipeLines, LP
Goodwill recorded on Company's acquisitions in the U.S.
Impairment charge	CAD 199
Ownership interest (as a percentage)				46.45%	46.45%
Great Lakes | Net of non-controlling interest
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill | $		243			$ 386
Goodwill
Balance at the beginning of the period | $		243
Balance at the end of the period | $		$ 386
Natural Gas Pipelines
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	3,074		2,816	CAD 3,667
Goodwill
Balance at the beginning of the period	3,074		2,816
Foreign exchange rate changes	593		258
Balance at the end of the period	3,667		3,074
Energy
Goodwill recorded on Company's acquisitions in the U.S.
Goodwill	960		880	CAD 1,145
Goodwill
Balance at the beginning of the period	960		880
Foreign exchange rate changes	185		80
Balance at the end of the period	CAD 1,145		CAD 960

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INTANGIBLE AND OTHER ASSETS (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD	Dec. 31, 2013 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
Capital projects in development	CAD 1,814	CAD 1,286
PPAs	220	272
Fair value of derivative contracts (Note 23)	168	93
Loans and advances	159	167
Employee post-retirement benefits (Note 22)	18	14
Deferred income tax assets and charges (Note 15)	9	181
Other	797	628
Intangible and other assets	3,185	2,641
Note receivable
Notes receivable	CAD 213	213		$ 154	$ 184
Interest rate on notes receivable	6.75%
Current portion of note receivable	CAD 55	46		$ 40	$ 40
Amount related to PPAs which are included in intangibles and other assets
Cost	810	810
Accumulated Amortization	590	538
Net Book Value	220	272
Amortization expense	52	52	CAD 52
Expected annual amortization expense
2016	52
2017	52
2018	39
2019	39
2020	39
Sheerness (expires 2020)
Goodwill and Intangible Assets Disclosure [Abstract]
PPAs	195	234
Amount related to PPAs which are included in intangibles and other assets
Cost	585	585
Accumulated Amortization	390	351
Net Book Value	195	234
Sundance A (expires 2017)
Goodwill and Intangible Assets Disclosure [Abstract]
PPAs	25	38
Amount related to PPAs which are included in intangibles and other assets
Cost	225	225
Accumulated Amortization	200	187
Net Book Value	CAD 25	CAD 38

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NOTES PAYABLE (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD	Dec. 31, 2013 CAD	Dec. 31, 2015 USD ($)	Nov. 01, 2015 USD ($)	Oct. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Notes payable
Outstanding at December 31	CAD 1,218	CAD 2,467
Affiliates
Notes payable
Amount	3,500
Unused Capacity	600	400
Notes payable | U.S. dollars
Notes payable
Outstanding at December 31 | $				$ 376			$ 800
Revolving and demand credit facilities
Notes payable
Unused Capacity	8,900	6,700
TCPL | Revolving Credit Facility | Maturing December 2020
Notes payable
Amount	3,000
Unused Capacity	3,000
Cost to maintain	6	6	CAD 4
TCPL | Revolving Credit Facility | Maturing December 2016
Notes payable
Amount | $				1,000
Unused Capacity | $				1,000
TCPL | Revolving Credit Facility | U.S. dollars
Notes payable
Amount | $				$ 1,000
TCPL | Notes payable
Notes payable
Outstanding at December 31	CAD 697	CAD 1,540
Weighted Average Interest Rate per Annum at December 31	0.80%	1.20%		0.80%			1.20%
TAIL/TCPM | Revolving Credit Facility
Notes payable
Amount | $				$ 1,500
Unused Capacity | $				$ 1,500
Cost to maintain	CAD 2	CAD 1
TAIL/TCPM | Notes payable
Notes payable
Outstanding at December 31	CAD 521	CAD 927
Weighted Average Interest Rate per Annum at December 31	1.10%	0.70%		1.10%			0.70%
TAIL | Revolving Credit Facility | U.S. dollars
Notes payable
Amount | $					$ 1,500	$ 1,000
TCPL USA | Revolving Credit Facility
Notes payable
Amount | $				$ 500
Unused Capacity | $				$ 500
Cost to maintain	CAD 3	CAD 2	CAD 1
TCPL USA | Revolving Credit Facility | U.S. dollars
Notes payable
Amount | $					$ 500	$ 1,000
TCPL/TCPL USA | Revolving Credit Facility
Notes payable
Amount	1,700
Unused Capacity	CAD 700

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ACCOUNTS PAYABLE AND OTHER (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Payables and Accruals [Abstract]
Trade payables	CAD 1,506	CAD 1,624
Fair value of derivative contracts (Note 23)	926	749
Dividends payable	370	345
Regulatory liabilities (Note 9)	44	30
Liabilities related to assets held for sale (Note 6)	39
Other	129	143
Accounts payable and other	CAD 3,014	CAD 2,891

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OTHER LONG-TERM LIABILITIES (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred Costs, Noncurrent [Abstract]
Fair value of derivative contracts (Note 23)	CAD 625	CAD 411
Employee post-retirement benefits (Note 22)	380	444
Asset retirement obligations	109	98
Guarantees (Note 26)	26	20
Other	120	79
Other Long-Term Liabilities	CAD 1,260	CAD 1,052

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INCOME TAXES - Provision (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
Canada	CAD 45	CAD 104	CAD 27
Foreign	92	42	16
Total	137	146	43
Deferred
Canada	33	307	239
Foreign	(135)	377	323
Total	(102)	684	562
Total Income Tax Expense/(Recovery)	CAD 35	CAD 830	CAD 605

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INCOME TAXES - Geographic Components of Income (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Canada	CAD (623)	CAD 1,146	CAD 1,201
Foreign	(482)	1,678	1,298
(Loss)/Income before Income Taxes	CAD (1,105)	CAD 2,824	CAD 2,499

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INCOME TAXES - Reconciliation of Expense (Details) - CAD CAD in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
(Loss)/Income before income taxes		CAD (1,105)	CAD 2,824	CAD 2,499
Federal and provincial statutory tax rate		26.01%	25.00%	25.00%
Expected income tax (recovery)/expense		CAD (287)	CAD 706	CAD 625
Income tax differential related to regulated operations		159	129	(13)
Higher effective foreign tax rates		14	25	33
Income from equity investments and non-controlling interests		(56)	(38)	(28)
Tax rate and legislative changes	CAD 25	34		(25)
Asset impairment charges		170
Other		1	8	13
Total Income Tax Expense/(Recovery)		35	CAD 830	CAD 605
Asset impairment charges		CAD 311

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INCOME TAXES - Deferred Assets and Liabilities (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Assets, Net [Abstract]
Difference in accounting and tax bases of impaired assets	CAD 916
Tax loss and credit carryforwards	1,325	CAD 1,344
Regulatory and other deferred amounts	231	236
Unrealized foreign exchange losses on long-term debt	589	140
Financial instruments	111	104
Other	132	146
Deferred tax assets, gross	3,304	1,970
Less: Valuation allowance	1,060	125
Deferred Tax Assets, Net of Valuation Allowance	2,244	1,845
Deferred Tax Liabilities, Net [Abstract]
Difference in accounting and tax bases of plant, property and equipment and PPAs	6,441	5,548
Equity investments	656	648
Taxes on future revenue requirement	227	253
Other	55	71
Deferred tax liabilities, gross	7,379	6,520
Net Deferred Income Tax Liabilities	5,135	4,675
Increase (decrease) to the valuation allowance	935
Deferred Income Tax Assets
Intangible and other assets (Note 11)	9	181
Deferred Income Tax Liabilities
Deferred income tax liabilities	5,144	4,856
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred noncurrent income tax liabilities, post accounting pronouncement	CAD 5,144	4,856
New Accounting Pronouncement, Early Adoption, Effect
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred current income tax assets, prior to accounting pronouncement		427
Deferred noncurrent income tax assets, post accounting pronouncement		427
Deferred current income tax liabilities, prior to accounting pronouncement		4
Deferred noncurrent income tax liabilities, post accounting pronouncement		CAD 4

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INCOME TAXES - Reconciliation of Unrecognized Tax Benefit (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefit at beginning of year	CAD 13	CAD 19	CAD 45
Gross increases – tax positions in prior years	2	2	3
Gross decreases – tax positions in prior years	(2)	(8)	(28)
Gross increases – tax positions in current year	1	1	2
Lapses of statute of limitations	(1)	(1)	(3)
Unrecognized Tax Benefit at End of Year	CAD 13	CAD 13	CAD 19

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INCOME TAXES - Narrative (Details) CAD in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2013 CAD	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD	Dec. 31, 2013 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Net operating loss carryforwards
Deferred income tax liabilities on the unremitted earnings of foreign investments		CAD 308	CAD 236
Income tax payments, net of refunds		164	109	CAD 206
Favourable income tax adjustment	CAD 25	34		CAD (25)
Interest expense (reversal) reflected within net tax expense		(1)
Accrued interest expense		4	5
Canada federal and provincial
Net operating loss carryforwards
Unused net operating loss carryforwards		1,276	1,131
U.S. federal
Net operating loss carryforwards
Unused net operating loss carryforwards | $					$ 1,617	$ 2,267
Alternative Minimum Tax [Member] | Canada federal and provincial
Net operating loss carryforwards
Minimum tax credits		CAD 57	CAD 50
Alternative Minimum Tax [Member] | U.S. federal
Net operating loss carryforwards
Minimum tax credits | $					$ 41	$ 26

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LONG-TERM DEBT - Schedule of Activity and Summary of Principal Repayments (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 31,584		CAD 24,757
Less: Current portion of Long-term debt	2,547		1,797
Long-term Debt, Excluding Current Maturities	29,037		22,960
Repayments of Long-term Debt [Abstract]
2016	2,547
2017	2,150
2018	3,379
2019	1,228
2020	1,801
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	26,685		20,916
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Dates Between 2015 and 2020
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 599		CAD 749
Interest Rate	10.70%	10.70%	10.90%	10.90%
TRANSCANADA PIPELINES LIMITED | Debentures, Maturity Date of 2021
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 554	$ 400	CAD 464	$ 400
Interest Rate	9.90%	9.90%	9.90%	9.90%
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 5,192		CAD 4,048
Interest Rate	5.30%	5.30%	5.70%	5.70%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 20,340	$ 14,723	CAD 15,655	$ 13,526
Interest Rate	4.80%	4.80%	5.00%	5.00%
NOVA GAS TRANSMISSION LTD.
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 1,151		CAD 1,099
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Dates between 2016 and 2024
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 325		CAD 325
Interest Rate	11.50%	11.50%	11.50%	11.50%
NOVA GAS TRANSMISSION LTD. | Debentures and Notes, Maturity Date of 2023
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 277	$ 200	CAD 232	$ 200
Interest Rate	7.90%	7.90%	7.90%	7.90%
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity between 2025 and 2030
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 504		CAD 504
Interest Rate	7.40%	7.40%	7.40%	7.40%
NOVA GAS TRANSMISSION LTD. | Medium-Term Notes, Maturity Date of 2026
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 45	$ 33	CAD 38	$ 33
Interest Rate	7.50%	7.50%	7.50%	7.50%
NOVA GAS TRANSMISSION LTD. | Debentures and Notes
Debt Instrument [Line Items]
Long-term debt issued with retraction provision	CAD 225
NOVA GAS TRANSMISSION LTD. | Debentures and Notes | Maximum
Debt Instrument [Line Items]
Redemption price, percentage	8.00%
ANR PIPELINE COMPANY | Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 598	$ 432	CAD 502	$ 432
Interest Rate	8.90%	8.90%	8.90%	8.90%
GAS TRANSMISSION NORTHWEST LLC
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 450		CAD 377
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 346	$ 250	CAD 377	$ 325
Interest Rate	5.60%	5.60%	5.50%	5.50%
GAS TRANSMISSION NORTHWEST LLC | Unsecured Term Loan
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 104	$ 75
Interest Rate	1.40%	1.40%
TC PIPELINES, LP
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 2,171		CAD 1,368
TC PIPELINES, LP | Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 967	$ 698	CAD 405	$ 350
Interest Rate	4.70%	4.70%	4.70%	4.70%
TC PIPELINES, LP | Unsecured Term Loan
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 235	$ 170
Interest Rate	1.60%	1.60%
TC PIPELINES, LP | Unsecured Loan
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 277	$ 200	CAD 383	$ 330
Interest Rate	1.60%	1.60%	1.40%	1.40%
TC PIPELINES, LP | Unsecured Term Loan Facility
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 692	$ 500	CAD 580	$ 500
Interest Rate	1.60%	1.60%	1.40%	1.40%
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP | Senior Unsecured Notes
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 411	$ 297	CAD 367	$ 316
Interest Rate	7.80%	7.80%	7.80%	7.80%
TUSCARORA GAS TRANSMISSION COMPANY | Secured Debt
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 22	$ 16	CAD 23	$ 20
Interest Rate	4.00%	4.00%	4.00%	4.00%
PORTLAND NATURAL GAS TRANSMISSION SYSTEM | Secured Debt
Debt Instrument [Line Items]
Current and Long-Term Debt, Outstanding December 31	CAD 96	$ 69	CAD 105	$ 90
Interest Rate	6.10%	6.10%	6.10%	6.10%

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LONG-TERM DEBT - Long-Term Debt Issued (Details) CAD in Millions, $ in Millions	1 Months Ended
	Nov. 30, 2015 USD ($)	Oct. 31, 2015 CAD	Sep. 30, 2015 USD ($)	Jul. 31, 2015 CAD	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jan. 31, 2015 USD ($)	Feb. 28, 2014 USD ($)	Oct. 31, 2013 USD ($)	Jul. 31, 2013 CAD	Jul. 31, 2013 USD ($)	Jan. 31, 2013 USD ($)
TRANSCANADA PIPELINES LIMITED | 1.625% senior unsecured notes, due November 2017
Debt Instrument [Line Items]
Amount	$ 1,000
Interest Rate	1.625%
TRANSCANADA PIPELINES LIMITED | 4.55% medium-term notes, due November 2041
Debt Instrument [Line Items]
Amount | CAD		CAD 400
Interest Rate		4.55%
TRANSCANADA PIPELINES LIMITED | 3.30% medium-term notes, due July 2025
Debt Instrument [Line Items]
Amount | CAD				CAD 750
Interest Rate				3.30%
TRANSCANADA PIPELINES LIMITED | 4.60% senior unsecured notes, due March 2045
Debt Instrument [Line Items]
Amount						$ 750
Interest Rate						4.60%
TRANSCANADA PIPELINES LIMITED | 1.875% senior unsecured notes, due January 2018
Debt Instrument [Line Items]
Amount							$ 500
Interest Rate							1.875%
TRANSCANADA PIPELINES LIMITED | Senior unsecured notes, floating rates, due in January 2018
Debt Instrument [Line Items]
Amount							$ 250
TRANSCANADA PIPELINES LIMITED | 4.63% senior unsecured notes, due March 2034
Debt Instrument [Line Items]
Amount								$ 1,250
Interest Rate								4.63%
TRANSCANADA PIPELINES LIMITED | 3.75% senior unsecured notes, due October 16, 2023
Debt Instrument [Line Items]
Amount									$ 625
Interest Rate									3.75%
TRANSCANADA PIPELINES LIMITED | 5.00% senior unsecured notes, due October 16, 2043
Debt Instrument [Line Items]
Amount									$ 625
Interest Rate									5.00%
TRANSCANADA PIPELINES LIMITED | 0.95% floating rate notes, maturing June 30, 2016
Debt Instrument [Line Items]
Amount											$ 500
TRANSCANADA PIPELINES LIMITED | 3.69% medium term notes, due July 19, 2023
Debt Instrument [Line Items]
Amount | CAD										CAD 450
Interest Rate										3.69%	3.69%
TRANSCANADA PIPELINES LIMITED | 4.55% medium term notes, due November 15, 2041
Debt Instrument [Line Items]
Amount | CAD										CAD 300
Interest Rate										4.55%	4.55%
TRANSCANADA PIPELINES LIMITED | 0.75 % senior notes, due January 15, 2016
Debt Instrument [Line Items]
Amount												$ 750
Interest Rate												0.75%
TC PIPELINES, LP | Unsecured term loan, floating rate, due October 2018
Debt Instrument [Line Items]
Amount			$ 170
TC PIPELINES, LP | 4.375% senior unsecured notes, due March 2025
Debt Instrument [Line Items]
Amount						$ 350
Interest Rate						4.375%
TC PIPELINES, LP | Medium-term loan, floating rate, due July 2018
Debt Instrument [Line Items]
Amount											$ 500
GAS TRANSMISSION NORTHWEST LLC | Unsecured term loan, floating interest rate, due June 2019
Debt Instrument [Line Items]
Amount					$ 75

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LONG-TERM DEBT - Retired (Details) CAD in Millions, $ in Millions	1 Months Ended
	Aug. 31, 2015 CAD	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Jan. 31, 2015 USD ($)	Jun. 30, 2014 CAD	Feb. 28, 2014 CAD	Jan. 31, 2014 CAD	Aug. 31, 2013 USD ($)	Jun. 30, 2013 USD ($)
TRANSCANADA PIPELINES LIMITED | Debentures, 11.90%
Debt Instrument [Line Items]
Amount | CAD	CAD 150
Interest Rate	11.90%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 3.40%
Debt Instrument [Line Items]
Amount		$ 500
Interest Rate		3.40%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 0.875%
Debt Instrument [Line Items]
Amount			$ 500
Interest Rate			0.875%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 4.875%
Debt Instrument [Line Items]
Amount				$ 300
Interest Rate				4.875%
TRANSCANADA PIPELINES LIMITED | Debentures, 11.10%
Debt Instrument [Line Items]
Amount | CAD					CAD 125
Interest Rate					11.10%
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes at 5.05%
Debt Instrument [Line Items]
Amount | CAD						CAD 300
Interest Rate						5.05%
TRANSCANADA PIPELINES LIMITED | Medium-Term Notes, 5.65%
Debt Instrument [Line Items]
Amount | CAD							CAD 450
Interest Rate							5.65%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes 5.05%
Debt Instrument [Line Items]
Amount								$ 500
Interest Rate								5.05%
TRANSCANADA PIPELINES LIMITED | Senior Unsecured Notes, 4.00%
Debt Instrument [Line Items]
Amount									$ 350
Interest Rate									4.00%
GAS TRANSMISSION NORTHWEST LLC | Senior Unsecured Notes, 5.09%
Debt Instrument [Line Items]
Amount		$ 75
Interest Rate		5.09%
NOVA GAS TRANSMISSION LTD. | Debentures, 11.20%
Debt Instrument [Line Items]
Amount | CAD					CAD 53
Interest Rate					11.20%

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LONG-TERM DEBT - Interest Expense and Payments (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Interest Expense [Abstract]
Capitalized interest	CAD (280)	CAD (259)	CAD (287)
Amortization and other financial charges	31	55	(21)
Interest expense	1,398	1,235	1,046
Interest payments on long-term debt and junior subordinated notes, net of interest capitalized on construction projects	1,295	1,160	1,047
Short-term debt
Interest Expense [Abstract]
Interest on debt	44	52	73
Total long-term debt (excluding junior subordinated notes)
Interest Expense [Abstract]
Interest on debt	1,487	1,317	1,216
Junior subordinated notes
Interest Expense [Abstract]
Interest on debt	CAD 116	CAD 70	CAD 65

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JUNIOR SUBORDINATED NOTES (Details) CAD in Millions	1 Months Ended	12 Months Ended	240 Months Ended	360 Months Ended
	May. 31, 2015 USD ($)	Dec. 31, 2015 CAD	Apr. 30, 2045	Apr. 30, 2075	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD	Dec. 31, 2014 USD ($)
Debt Instrument [Line Items]
Outstanding at December 31 | CAD		CAD 2,422				CAD 1,160
TRANSCANADA PIPELINES LIMITED
Debt Instrument [Line Items]
Outstanding at December 31 | CAD		CAD 2,422				1,160
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes
Debt Instrument [Line Items]
Outstanding at December 31					$ 1,000,000,000.0
Stated interest rate		6.35%			6.35%
Optional period for which payment of interest can be deferred		10 years
Redemption price as a percentage of principal amount plus accrued and unpaid interest		100.00%
TRANSCANADA PIPELINES LIMITED | Junior subordinated notes | LIBOR
Debt Instrument [Line Items]
Basis points		2.21%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2075
Debt Instrument [Line Items]
Outstanding at December 31		CAD 1,038			$ 750,000,000
Effective Interest Rate		5.30%			5.30%
TRANSCANADA PIPELINES LIMITED | Junior subordinated debt, due 2067
Debt Instrument [Line Items]
Outstanding at December 31		CAD 1,384			$ 1,000,000,000	CAD 1,160	$ 1,000,000,000
Effective Interest Rate		6.40%			6.40%	6.50%	6.50%
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in May 2075 | Junior subordinated notes
Debt Instrument [Line Items]
Stated interest rate	5.875%
Debt	$ 750,000,000
Administrative charge	0.25%
Redemption price as a percentage of principal amount plus accrued and unpaid interest	100.00%
TRANSCANADA PIPELINES LIMITED | TransCanada Trust loan, due in May 2075 | Junior subordinated notes | LIBOR | Scenario, forecast
Debt Instrument [Line Items]
Basis points			3.778%	4.528%
TransCanada Trust | Trust Notes - Series 2015-A | Notes Payable
Debt Instrument [Line Items]
Stated interest rate	5.625%
Debt	$ 750,000,000
Stated interest rate, period of time	10 years

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NON-CONTROLLING INTERESTS (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD	Dec. 31, 2013 CAD	Jan. 01, 2015	Jan. 01, 2014	May. 01, 2013	Dec. 31, 2012 CAD
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	CAD 1,717		CAD 1,583
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	6		151	CAD 105
Additional information
Impairment charge	3,745
TC PipeLines, LP
Additional information
Impairment charge | $		$ 199
Fees received for services provided	4		3	3
PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Additional information
Fees received for services provided	11		8	7
Noncontrolling Interest
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	1,717		1,583	1,417				CAD 1,036
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	19		15	12
Noncontrolling Interest | TC PipeLines, LP
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	1,590		1,479
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	CAD (13)		136	93
Additional information
Percentage of non-controlling interests	72.00%				71.70%	71.10%	66.70%
Impairment charge	CAD 13	$ 143
Noncontrolling Interest | PORTLAND NATURAL GAS TRANSMISSION SYSTEM
Non-controlling interest included in the Consolidated Balance Sheet
Non-controlling interest	127		104
Non-controlling interests included in the Consolidated Statement of Income
Non-controlling interest	CAD 19		CAD 15	CAD 12
Additional information
Percentage of non-controlling interests	38.30%		38.30%	38.30%

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COMMON SHARES - Narrative (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Additional disclosure
Maximum amount allowed for paying dividends	CAD 4,100.0	CAD 8,700.0	CAD 1,300.0
Award vesting period	3 years
Expiration period	7 years
Amount expensed for stock awards, with a corresponding increase in additional paid-in capital	CAD 11.0	CAD 9.0	CAD 6.0
Aggregate intrinsic value of total options exercisable	23.0
Total intrinsic value of options outstanding	CAD 23.0

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COMMON SHARES - Reconciliation (Details) - CAD shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Changes in common shares during the period
Outstanding at the end of the period (in shares)	779,000
Outstanding at the end of the period	CAD 16,320
Common Shares
Changes in common shares during the period
Outstanding at the beginning of the period (in shares)	757,114	738,381
Outstanding at the beginning of the period	CAD 15,205	CAD 14,306
Exercise of options (in shares)	22,365	18,733
Exercise of options	CAD 1,115	CAD 899
Outstanding at the end of the period (in shares)	779,479	757,114
Outstanding at the end of the period	CAD 16,320	CAD 15,205

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COMMON SHARES - Weighted-Average Assumptions (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Weighted average assumptions used in binomial model for determining the fair value of awards granted
Expected life (years)	5 years 9 months	6 years	6 years
Interest rate	1.10%	1.80%	1.70%
Volatility	18.00%	17.00%	18.00%
Dividend yield	3.70%	3.80%	3.70%
Forfeiture rate	5.00%	5.00%	15.00%

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COMMON SHARES - Additional Stock Option Information (Details) - CAD shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Additional Stock Option Information
Total intrinsic value of options exercised	CAD 37	CAD 68	CAD 25
Fair value of options that have vested	CAD 91	CAD 95	CAD 64
Total options vested (in shares)	2.0	1.7	1.3

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PREFERRED SHARES (Details) - CAD CAD / shares in Units, shares in Millions, CAD in Millions	1 Months Ended
	Mar. 31, 2014	Oct. 31, 2013
Series Y preferred shares
Preferred Shares [Line Items]
Stock redeemed during period (in shares)	4
Redemption price per share (in Canadian dollars per share)	CAD 50
Gross payment for preferred stock redemption	CAD 200
Series U preferred shares
Preferred Shares [Line Items]
Stock redeemed during period (in shares)		4
Redemption price per share (in Canadian dollars per share)		CAD 50
Gross payment for preferred stock redemption		CAD 200

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OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Components - (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Before Tax Amount
Foreign currency translation gains on net investment in foreign operations	CAD 798	CAD 462	CAD 269
Change in fair value of net investment hedges	(505)	(373)	(323)
Change in fair value of cash flow hedges	(92)	(118)	121
Reclassification to net income of gains and losses on cash flow hedges	144	(95)	60
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	74	(146)	96
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	41	25	34
Other comprehensive income on equity investments	62	(272)	313
Other comprehensive income (loss)	522	(517)	570
Income Tax Recovery/(Expense)
Foreign currency translation gains on net investment in foreign operations	15	55	114
Change in fair value of net investment hedges	133	97	84
Change in fair value of cash flow hedges	35	49	(50)
Reclassification to net income of gains and losses on cash flow hedges	(56)	40	(19)
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	(23)	44	(29)
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	(9)	(7)	(11)
Other comprehensive income on equity investments	(15)	68	(79)
Other comprehensive income (loss)	80	346	10
Net of Tax Amount
Foreign currency translation gains on net investment in foreign operations	813	517	383
Change in fair value of net investment hedges	(372)	(276)	(239)
Change in fair value of cash flow hedges	(57)	(69)	71
Reclassification to net income of gains and losses on cash flow hedges	88	(55)	41
Unrealized actuarial gains and losses on pension and other post-retirement benefit plans	51	(102)	67
Reclassification to net income of actuarial gains and losses and prior service costs on pension and other post-retirement benefit plans	32	18	23
Other comprehensive income on equity investments	47	(204)	234
Other comprehensive income/(loss) (Note 21)	CAD 602	CAD (171)	CAD 580

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OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reconciliation (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	CAD (1,235)	CAD (934)	CAD (1,448)
Other comprehensive income/(loss) before reclassifications	162	(266)	435
Amounts reclassified from accumulated other comprehensive loss	134	(35)	79
Net current period other comprehensive income	296	(301)	514
AOCI Balance	(939)	(1,235)	(934)
Other comprehensive income/(loss) before reclassifications attributable to noncontrolling interest	306	130	66
Cash flow hedge losses expected to be reclassified within the next twelve months, before tax	83
Cash flow hedge losses expected to be reclassified within the next twelve months, net of tax	51
Currency translation adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(518)	(629)	(707)
Other comprehensive income/(loss) before reclassifications	135	111	78
Net current period other comprehensive income	135	111	78
AOCI Balance	(383)	(518)	(629)
Cash flow hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(128)	(4)	(116)
Other comprehensive income/(loss) before reclassifications	(57)	(69)	71
Amounts reclassified from accumulated other comprehensive loss	88	(55)	41
Net current period other comprehensive income	31	(124)	112
AOCI Balance	(97)	(128)	(4)
Pension and OPEB plan adjustments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(281)	(197)	(287)
Other comprehensive income/(loss) before reclassifications	51	(102)	67
Amounts reclassified from accumulated other comprehensive loss	32	18	23
Net current period other comprehensive income	83	(84)	90
AOCI Balance	(198)	(281)	(197)
Equity Investments
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Balance	(308)	(104)	(338)
Other comprehensive income/(loss) before reclassifications	33	(206)	219
Amounts reclassified from accumulated other comprehensive loss	14	2	15
Net current period other comprehensive income	47	(204)	234
AOCI Balance	CAD (261)	CAD (308)	CAD (104)

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OTHER COMPREHENSIVE INCOME/(LOSS) AND ACCUMULATED OTHER COMPREHENSIVE LOSS - Reclassifications (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Energy)	CAD 4,038	CAD 3,725	CAD 3,176
Interest expense	(1,398)	(1,235)	(1,046)
Income / (Loss) from Equity Investments	440	522	597
(Loss)/Income before income taxes	(1,105)	2,824	2,499
Income tax expense	(35)	(830)	(605)
Net (Loss)/Income Attributable to Controlling Interests	(1,146)	1,843	1,789
Amounts reclassified from accumulated other comprehensive loss | Cash flow hedges
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
(Loss)/Income before income taxes	(144)	95	(60)
Income tax expense	56	(40)	19
Net (Loss)/Income Attributable to Controlling Interests	(88)	55	(41)
Amounts reclassified from accumulated other comprehensive loss | Cash flow hedges | Commodities
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Revenues (Energy)	(128)	111	(44)
Amounts reclassified from accumulated other comprehensive loss | Cash flow hedges | Interest
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	(16)	(16)	(16)
Amounts reclassified from accumulated other comprehensive loss | Pension and other post-retirement benefit plan adjustments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Amortization of actuarial loss and past service cost	(41)	(25)	(34)
(Loss)/Income before income taxes	9	7	11
Net (Loss)/Income Attributable to Controlling Interests	(32)	(18)	(23)
Amounts reclassified from accumulated other comprehensive loss | Equity investments
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income / (Loss) from Equity Investments	(19)	(2)	(20)
Income tax expense	5		5
Net (Loss)/Income Attributable to Controlling Interests	CAD (14)	CAD (2)	CAD (15)

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EMPLOYEE POST-RETIREMENT BENEFITS - Cash Payments and Changes (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee post-retirement benefits
Expected average remaining life expectancy of former employees over which past service costs are amortized	12 years	12 years	11 years
Expense for savings plan and DC Plans	CAD 41	CAD 37	CAD 29
Cash Payments for Employee Post-Retirement Benefits [Abstract]
Savings and DC Plans	41	37	29
Total cash contributions	143	116	CAD 114
Change in Plan Assets
Plan assets at fair value – beginning of year	2,437
Plan assets at fair value – end of year	2,636	2,437
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 11)	18	14
Other long-term liabilities (Note 14)	CAD (380)	CAD (444)
Pension Benefit Plans
Employee post-retirement benefits
Consecutive period of employment for highest average earnings	3 years
Expected average remaining service life of employees over which past service costs are amortized	9 years	9 years	9 years
Cash Payments for Employee Post-Retirement Benefits [Abstract]
DB Plans and Other post-retirement benefit plans	CAD 96	CAD 73	CAD 79
Change in Benefit Obligation
Benefit obligation – beginning of year	2,658	2,224
Service cost	108	85	84
Interest cost	115	113	96
Employee contributions	4	4
Benefits paid	(129)	(102)
Actuarial (gain)/loss	(57)	302
Foreign exchange rate changes	81	32
Benefit obligation – end of year	2,780	2,658	2,224
Change in Plan Assets
Plan assets at fair value – beginning of year	2,398	2,152
Actual return on plan assets	160	246
Employer contributions	96	73	79
Employee contributions	4	4
Benefits paid	(129)	(102)
Foreign exchange rate changes	62	25
Plan assets at fair value – end of year	2,591	2,398	2,152
Funded Status – Plan Deficit	(189)	(260)
Amounts recognized in the Balance Sheet
Other long-term liabilities (Note 14)	(189)	(260)
Net	(189)	(260)
Pension Benefit Plans | Canada
Employee post-retirement benefits
Letter of credit to the DB Plan	33	47	59
Total amount outstanding under letters of credit	214	181
Other Post-Retirement Benefit Plans
Cash Payments for Employee Post-Retirement Benefits [Abstract]
DB Plans and Other post-retirement benefit plans	6	6	6
Change in Benefit Obligation
Benefit obligation – beginning of year	216	191
Service cost	3	2	2
Interest cost	10	10	7
Benefits paid	(7)	(7)
Actuarial (gain)/loss	(11)	14
Foreign exchange rate changes	14	6
Benefit obligation – end of year	225	216	191
Change in Plan Assets
Plan assets at fair value – beginning of year	39	35
Actual return on plan assets	(1)	2
Employer contributions	6	6	6
Benefits paid	(7)	(7)
Foreign exchange rate changes	8	3
Plan assets at fair value – end of year	45	39	CAD 35
Funded Status – Plan Deficit	(180)	(177)
Amounts recognized in the Balance Sheet
Intangible and other assets (Note 11)	18	14
Accounts payable and other	(7)	(7)
Other long-term liabilities (Note 14)	(191)	(184)
Net	CAD (180)	CAD (177)

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EMPLOYEE POST-RETIREMENT BENEFITS - Obligations, Fair Value and Weighted Average Assets (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Funded status based on accumulated benefit obligation
Plan assets at fair value	CAD 2,636	CAD 2,437
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	CAD (2,780)	CAD (2,658)
Plan assets at fair value	2,591	2,398
Funded Status – Plan Deficit	(189)	(260)
Funded status based on accumulated benefit obligation
Accumulated benefit obligation	(2,600)	(2,437)
Plan assets at fair value	2,591	2,398	CAD 2,152
Funded Status – Plan Deficit	(9)	(39)
Accumulated benefit obligation and fair value of plan assets for plans that are not fully funded
Accumulated benefit obligation	(807)	(715)
Plan assets at fair value	680	597
Funded Status – Plan Deficit	CAD (127)	CAD (118)
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	100.00%	100.00%
Pension Benefit Plans | Debt securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	34.00%	31.00%
Amount of debt or common shares included in plan assets	CAD 2	CAD 1
Percentage of Plan Assets	0.10%	0.10%
Pension Benefit Plans | Debt securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	25.00%
Pension Benefit Plans | Debt securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	35.00%
Pension Benefit Plans | Equity securities
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	66.00%	69.00%
Amount of debt or common shares included in plan assets	CAD 4	CAD 1
Percentage of Plan Assets	0.10%	0.10%
Pension Benefit Plans | Equity securities | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	50.00%
Pension Benefit Plans | Equity securities | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	70.00%
Pension Benefit Plans | Alternatives
Pension plans' weighted average asset allocations and target allocations by asset category
Percentage of Plan Assets	0.00%	0.00%
Pension Benefit Plans | Alternatives | Minimum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	5.00%
Pension Benefit Plans | Alternatives | Maximum
Pension plans' weighted average asset allocations and target allocations by asset category
Target Allocations	15.00%
Other Post-Retirement Benefit Plans
Benefit obligation and fair value of plan assets for plans that are not fully funded
Projected benefit obligation	CAD (198)	CAD (191)
Funded Status – Plan Deficit	(198)	(191)
Funded status based on accumulated benefit obligation
Plan assets at fair value	CAD 45	CAD 39	CAD 35

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EMPLOYEE POST-RETIREMENT BENEFITS - Measured at Fair Value (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee post-retirement benefits
Fair value of plan assets	CAD 2,636	CAD 2,437
Percentage of Total Portfolio	100.00%	100.00%
Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 1,118	CAD 1,239
Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	1,504	1,185
Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	14	13
Cash and Cash Equivalents
Employee post-retirement benefits
Fair value of plan assets	CAD 46	CAD 20
Percentage of Total Portfolio	2.00%	1.00%
Cash and Cash Equivalents | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 44	CAD 20
Cash and Cash Equivalents | Significant Other Observable Inputs (Level II)
Employee post-retirement benefits
Fair value of plan assets	2
Equity securities | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 464	CAD 503
Percentage of Total Portfolio	17.00%	21.00%
Equity securities | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 629	CAD 551
Percentage of Total Portfolio	24.00%	23.00%
Equity securities | International
Employee post-retirement benefits
Fair value of plan assets	CAD 338	CAD 365
Percentage of Total Portfolio	13.00%	15.00%
Equity securities | Global
Employee post-retirement benefits
Fair value of plan assets	CAD 154	CAD 141
Percentage of Total Portfolio	6.00%	6.00%
Equity securities | Emerging
Employee post-retirement benefits
Fair value of plan assets	CAD 150	CAD 87
Percentage of Total Portfolio	6.00%	3.00%
Equity securities | Quoted Prices in Active Markets (Level I) | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 317	CAD 361
Equity securities | Quoted Prices in Active Markets (Level I) | U.S.
Employee post-retirement benefits
Fair value of plan assets	589	516
Equity securities | Quoted Prices in Active Markets (Level I) | International
Employee post-retirement benefits
Fair value of plan assets	38	218
Equity securities | Quoted Prices in Active Markets (Level I) | Emerging
Employee post-retirement benefits
Fair value of plan assets	7	7
Equity securities | Significant Other Observable Inputs (Level II) | Canada
Employee post-retirement benefits
Fair value of plan assets	147	142
Equity securities | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	40	35
Equity securities | Significant Other Observable Inputs (Level II) | International
Employee post-retirement benefits
Fair value of plan assets	300	147
Equity securities | Significant Other Observable Inputs (Level II) | Global
Employee post-retirement benefits
Fair value of plan assets	154	141
Equity securities | Significant Other Observable Inputs (Level II) | Emerging
Employee post-retirement benefits
Fair value of plan assets	143	80
Federal | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 206	CAD 218
Percentage of Total Portfolio	8.00%	9.00%
Federal | Significant Other Observable Inputs (Level II) | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 206	CAD 218
Provincial | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 202	CAD 180
Percentage of Total Portfolio	8.00%	7.00%
Provincial | Significant Other Observable Inputs (Level II) | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 202	CAD 180
Municipal | Canada
Employee post-retirement benefits
Fair value of plan assets	7	7
Municipal | Significant Other Observable Inputs (Level II) | Canada
Employee post-retirement benefits
Fair value of plan assets	7	7
Corporate | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 113	CAD 76
Percentage of Total Portfolio	4.00%	3.00%
Corporate | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 57	CAD 59
Percentage of Total Portfolio	2.00%	2.00%
Corporate | International
Employee post-retirement benefits
Fair value of plan assets	CAD 25	CAD 14
Percentage of Total Portfolio	1.00%	1.00%
Corporate | Significant Other Observable Inputs (Level II) | Canada
Employee post-retirement benefits
Fair value of plan assets	CAD 113	CAD 76
Corporate | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	57	59
Corporate | Significant Other Observable Inputs (Level II) | International
Employee post-retirement benefits
Fair value of plan assets	25	14
State | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 50	CAD 47
Percentage of Total Portfolio	2.00%	2.00%
State | Significant Other Observable Inputs (Level II) | U.S.
Employee post-retirement benefits
Fair value of plan assets	CAD 50	CAD 47
Mortgage Backed | International
Employee post-retirement benefits
Fair value of plan assets	CAD 58	CAD 39
Percentage of Total Portfolio	2.00%	2.00%
Mortgage Backed | Significant Other Observable Inputs (Level II) | International
Employee post-retirement benefits
Fair value of plan assets	CAD 58	CAD 39
Other Investments: Private Equity Funds
Employee post-retirement benefits
Fair value of plan assets	14	13
Other Investments: Private Equity Funds | Significant Unobservable Inputs (Level III)
Employee post-retirement benefits
Fair value of plan assets	14	13	CAD 18
Other Investments: Funds Held on Deposit
Employee post-retirement benefits
Fair value of plan assets	CAD 123	CAD 117
Percentage of Total Portfolio	5.00%	5.00%
Other Investments: Funds Held on Deposit | Quoted Prices in Active Markets (Level I)
Employee post-retirement benefits
Fair value of plan assets	CAD 123	CAD 117

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EMPLOYEE POST-RETIREMENT BENEFITS - Net Change in Level III Fair Value (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	CAD 2,437
Plan assets at fair value – end of year	2,636	CAD 2,437
Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	13
Plan assets at fair value – end of year	14	13
Private Equity Funds
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	13
Plan assets at fair value – end of year	14	13
Private Equity Funds | Significant Unobservable Inputs (Level III)
Net change in the Level III fair value category
Plan assets at fair value – beginning of year	13	18
Purchases and sales	(1)	(7)
Realized and unrealized gains	2	2
Plan assets at fair value – end of year	CAD 14	CAD 13

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EMPLOYEE POST-RETIREMENT BENEFITS - Savings, Payments, Future Benefits and Assumptions (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other post-retirement benefit plans, Savings Plan and DC Plans
Company's expected funding contributions	CAD 37
Health care benefits
Assumed average annual rate of increase in the per capita cost of covered health care benefits for 2013 (as a percent)	7.00%
Percentage level to which average annual rate was assumed to decrease	5.00%
Effects of a one per cent change in assumed health care cost trend rates
Effect on total of service and interest cost components, Increase	CAD 1
Effect on total of service and interest cost components, Decrease	(1)
Effect on post-retirement benefit obligation, Increase	14
Effect on post-retirement benefit obligation, Decrease	(12)
Pension Benefit Plans
DB Plans
Company's expected funding contributions	70
Estimated future benefit payments, which reflect expected future service
2016	129
2017	133
2018	138
2019	142
2020	146
2021 to 2025	CAD 808
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.20%	4.15%
Rate of compensation increase	0.50%	3.15%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.15%	4.95%	4.35%
Expected long-term rate of return on plan assets	6.95%	6.90%	6.70%
Rate of compensation increase	3.15%	3.15%	3.15%
Net benefit cost
Service cost	CAD 108	CAD 85	CAD 84
Interest cost	115	113	96
Expected return on plan assets	(155)	(139)	(120)
Amortization of actuarial loss	35	21	30
Amortization of past service cost	2	2	2
Amortization of regulatory asset	23	18	30
Net Benefit Cost Recognized	128	100	122
Pre-tax amounts recognized in AOCI
Net loss	247	348	236
Prior service cost		2	3
Total pre-tax amounts recognized in AOCI	247	350	239
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	21
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	(34)	(21)	(30)
Amortization of prior service costs from AOCI to OCI	(2)	(2)	(2)
Funded status adjustment	(67)	137	(96)
Total pre-tax amounts recognized in OCI	(103)	114	CAD (128)
Pension Benefit Plans | Canada
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	214	CAD 181
Pension Benefit Plans | Canada | Scenario, Plan
Other post-retirement benefit plans, Savings Plan and DC Plans
Expected estimated additional letter of credit	33
Other Post-Retirement Benefit Plans
DB Plans
Company's expected funding contributions	7
Estimated future benefit payments, which reflect expected future service
2016	8
2017	9
2018	9
2019	9
2020	10
2021 to 2025	CAD 51
Weighted average actuarial assumptions adopted in measuring the benefit obligations
Discount rate	4.40%	4.20%
Weighted average actuarial assumptions adopted in measuring the net benefit plan costs
Discount rate	4.20%	5.00%	4.35%
Expected long-term rate of return on plan assets	4.60%	4.60%	4.60%
Net benefit cost
Service cost	CAD 3	CAD 2	CAD 2
Interest cost	10	10	7
Expected return on plan assets	(2)	(2)	(2)
Amortization of actuarial loss	3	2	2
Amortization of past service cost	1
Amortization of regulatory asset	1	1	1
Amortization of transitional obligation related to regulated business	2	2	2
Net Benefit Cost Recognized	18	15	12
Pre-tax amounts recognized in AOCI
Net loss	28	39	32
Prior service cost		1	1
Total pre-tax amounts recognized in AOCI	28	40	33
Amount that will be amortized from AOCI into net periodic benefit cost over the next fiscal year
Estimated net loss that will be amortized	3
Pre-tax amounts recognized in OCI
Amortization of net loss from AOCI to OCI	(4)	(2)	(2)
Amortization of prior service costs from AOCI to OCI	(1)
Funded status adjustment	(7)	9
Total pre-tax amounts recognized in OCI	CAD (12)	CAD 7	CAD (2)

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - U.S. Dollar-Denominated Debt Designated as Net Investment Hedges (Details) - Designated as a net investment hedge CAD in Millions, $ in Millions	Dec. 31, 2015 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Debt carrying value | CAD	CAD 23,000		CAD 17,000
Debt fair value | CAD	CAD 23,800		CAD 19,000
US$ denominated
Derivative [Line Items]
Debt carrying value | $		$ 16,600		$ 14,700
Debt fair value | $		$ 17,200		$ 16,400

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives Designated as a Net Investment Hedge (Details) - Designated as a net investment hedge CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Derivative [Line Items]
Fair value	CAD (680)	CAD (459)
US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			$ 4,950	$ 4,300
Cross-currency interest rate swaps
Derivative [Line Items]
Fair value	(730)	(431)
Cross-currency interest rate swaps | US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			3,150	2,900
Net realized gains related to the interest component	8	21
Forward foreign exchange contracts
Derivative [Line Items]
Fair value	CAD 50	CAD (28)
Forward foreign exchange contracts | US$ denominated
Derivative [Line Items]
Notional or Principal Amount | $			$ 1,800	$ 1,400

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Non-Derivative Financial Instruments (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Carrying and fair values of non-derivative financial instruments
Current and Long-Term Debt	CAD (31,584)	CAD (24,757)
Junior subordinated notes (Note 17)	(2,422)	(1,160)
Long-term Debt | $			$ 850	$ 400
Interest rate swap agreements
Carrying and fair values of non-derivative financial instruments
Fair value adjustments (losses)	2	(3)
Long-term debt hedged | $			$ 850	$ 400
Level II | Carrying Amount
Carrying and fair values of non-derivative financial instruments
Notes receivable	214	213
Current and Long-Term Debt	(31,584)	(24,757)
Junior subordinated notes (Note 17)	(2,422)	(1,160)
Total liabilities	(33,792)	(25,704)
Level II | Fair Value
Carrying and fair values of non-derivative financial instruments
Notes receivable	265	263
Current and Long-Term Debt	(34,309)	(28,713)
Junior subordinated notes (Note 17)	(2,011)	(1,157)
Total liabilities	CAD (36,055)	CAD (29,607)

XML

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Available for Sale and Balance Sheet Presentation (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD GWh Bcf	Dec. 31, 2014 CAD GWh Bcf	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	CAD 610	CAD 502
Gross derivative liabilities presented on the balance sheet	(1,551)	(1,160)
Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	456	436
Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	57	57
Gross derivative liabilities presented on the balance sheet	(145)	(165)
Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	3	3
Gross derivative liabilities presented on the balance sheet	(2)
Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	94	6
Gross derivative liabilities presented on the balance sheet	(774)	(465)
Commodities | Power
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	509	488
Gross derivative liabilities presented on the balance sheet	CAD (717)	CAD (657)
Commodities | Power | Not designated as hedging instrument | Purchases
Derivatives, Fair Value [Line Items]
Power (in GWh) | GWh	70,331	53,217
Commodities | Power | Not designated as hedging instrument | Sales
Derivatives, Fair Value [Line Items]
Power (in GWh) | GWh	54,382	39,429
Commodities | Natural Gas | Not designated as hedging instrument | Purchases
Derivatives, Fair Value [Line Items]
Natural Gas (in Bcf) | Bcf	133	60
Commodities | Natural Gas | Not designated as hedging instrument | Sales
Derivatives, Fair Value [Line Items]
Natural Gas (in Bcf) | Bcf	70	38
Commodities | Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	CAD (630)	CAD (530)
Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	96	7
Gross derivative liabilities presented on the balance sheet	(828)	(497)
Notional or Principal Amount | $			$ 1,476	$ 1,374
Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	5	7
Gross derivative liabilities presented on the balance sheet	(6)	(6)
Notional or Principal Amount | $			$ 1,100	$ 650
Other current assets
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	442	409
Other current assets | Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	330	363
Other current assets | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	46	39
Other current assets | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	1	2
Other current assets | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	65	5
Other current assets | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	372	398
Other current assets | Commodities | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	326	359
Other current assets | Commodities | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	46	39
Other current assets | Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	67	6
Other current assets | Foreign exchange | Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	1
Other current assets | Foreign exchange | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	65	5
Other current assets | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	3	5
Other current assets | Interest rate | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	3
Other current assets | Interest rate | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	1	2
Intangible and other assets
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	168	93
Intangible and other assets | Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	126	73
Intangible and other assets | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	11	18
Intangible and other assets | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	1
Intangible and other assets | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	29	1
Intangible and other assets | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	137	90
Intangible and other assets | Commodities | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	126	72
Intangible and other assets | Commodities | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	11	18
Intangible and other assets | Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	29	1
Intangible and other assets | Foreign exchange | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	29	1
Intangible and other assets | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	2
Intangible and other assets | Interest rate | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet		1
Intangible and other assets | Interest rate | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative assets presented on the balance sheet	2	1
Accounts payable and other
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(926)	(749)
Accounts payable and other | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(113)	(137)
Accounts payable and other | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)
Accounts payable and other | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(313)	(155)
Accounts payable and other | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(555)	(558)
Accounts payable and other | Commodities | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(443)	(422)
Accounts payable and other | Commodities | Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(54)	(32)
Accounts payable and other | Commodities | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(2)	(3)
Accounts payable and other | Commodities | Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(499)	(457)
Accounts payable and other | Commodities | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(112)	(136)
Accounts payable and other | Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(367)	(187)
Accounts payable and other | Foreign exchange | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(313)	(155)
Accounts payable and other | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(4)	(4)
Accounts payable and other | Interest rate | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)	(1)
Accounts payable and other | Interest rate | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)
Other long-term liabilities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(625)	(411)
Other long-term liabilities | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(32)	(28)
Other long-term liabilities | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)
Other long-term liabilities | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(461)	(310)
Other long-term liabilities | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(162)	(99)
Other long-term liabilities | Commodities | Commodities
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(131)	(72)
Other long-term liabilities | Commodities | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet		(1)
Other long-term liabilities | Commodities | Total trading activity
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(131)	(73)
Other long-term liabilities | Commodities | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(31)	(27)
Other long-term liabilities | Foreign exchange
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(461)	(310)
Other long-term liabilities | Foreign exchange | Net Investment Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(461)	(310)
Other long-term liabilities | Interest rate
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(2)	(2)
Other long-term liabilities | Interest rate | Cash Flow Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	(1)	CAD (1)
Other long-term liabilities | Interest rate | Fair Value Hedges
Derivatives, Fair Value [Line Items]
Gross derivative liabilities presented on the balance sheet	CAD (1)
Fixed income securities
Derivatives, Fair Value [Line Items]
Fixed income securities (maturing within 5 years)	5 years	5 years
Fixed income securities (maturing after 10 years)	10 years	10 years
LMCI Restricted Investments | Fixed income securities
Derivatives, Fair Value [Line Items]
Available-for-sale Securities, Debt Maturities, after Ten Years, Fair Value	CAD 261
Fixed income securities	261
Other Restricted Investments | Fixed income securities
Derivatives, Fair Value [Line Items]
Available-for-sale Securities, Debt Maturities, within Five Years, Fair Value	90	CAD 75
Fixed income securities	CAD 90	CAD 75

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Unrealized and Realized (Losses)/Gains (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value Hedges | Interest expense
Derivative [Line Items]
Amount of realized (losses)/gains in the year	CAD 11	CAD 7
Commodity contract
Derivative [Line Items]
Unrealized losses on derivative instruments held for trading	(37)	(40)
Realized losses on derivative instruments held for trading	(151)	(28)
Commodity contract | Derivative Financial Instruments in Hedging Relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	(179)	130
Foreign exchange
Derivative [Line Items]
Unrealized losses on derivative instruments held for trading	(21)	(20)
Realized losses on derivative instruments held for trading	(112)	(28)
Interest rate | Derivative Financial Instruments in Hedging Relationships
Derivative [Line Items]
Amount of realized (losses)/gains in the year	CAD 8	CAD 4

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivatives in Cash Flow Hedging Relationships (Details) - Cash Flow Hedges - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	CAD (92)	CAD (118)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	144	(95)
Commodities | Power
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)	(92)	(128)
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	128	(111)
Losses on derivative instruments recognized in Net income (ineffective portion)		(13)
Foreign exchange
Components of OCI related to derivatives
Change in fair value of derivative instruments recognized in OCI (effective portion)		10
Interest rate
Components of OCI related to derivatives
Reclassification of gains/(losses) on derivative instruments from AOCI to Net Income (effective portion)	CAD 16	CAD 16

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Offsetting of Derivative Instruments (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative - Asset
Gross derivative assets presented on the balance sheet	CAD 610	CAD 502
Amounts available for offset	(512)	(395)
Net Amounts	98	107
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(1,551)	(1,160)
Amounts available for offset	512	395
Net Amounts	(1,039)	(765)
Cash collateral provided by the Company	482	459
Letters of credit provided by the Company	41	26
Cash collateral received by the Company		1
Letters of credit received by the Company	2	1
Credit Risk Related Contingent Features
Aggregate fair value of derivative instruments in a net liability position	32	15
Additional collateral required if credit-risk-related contingent features were triggered	32	15
Foreign exchange
Derivative - Asset
Gross derivative assets presented on the balance sheet	96	7
Amounts available for offset	(93)	(7)
Net Amounts	3
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(828)	(497)
Amounts available for offset	93	7
Net Amounts	(735)	(490)
Interest rate
Derivative - Asset
Gross derivative assets presented on the balance sheet	5	7
Amounts available for offset	(1)	(1)
Net Amounts	4	6
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(6)	(6)
Amounts available for offset	1	1
Net Amounts	(5)	(5)
Power | Commodities
Derivative - Asset
Gross derivative assets presented on the balance sheet	509	488
Amounts available for offset	(418)	(387)
Net Amounts	91	101
Derivative - Liability
Gross derivative liabilities presented on the balance sheet	(717)	(657)
Amounts available for offset	418	387
Net Amounts	CAD (299)	CAD (270)

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Derivative Assets and Liabilities Measured on a Recurring Basis (Details) - CAD CAD in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Hierarchy
Derivative Instrument Assets	CAD 610	CAD 502
Derivative Instrument Liabilities	(1,551)	(1,160)
Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets	509	488
Derivative Instrument Liabilities	(717)	(657)
Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets	96	7
Derivative Instrument Liabilities	(828)	(497)
Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	5	7
Derivative Instrument Liabilities	(6)	(6)
Recurring basis
Fair Value Hierarchy
Assets and (liabilities), net	(941)	(658)
Recurring basis | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets	509	488
Derivative Instrument Liabilities	(717)	(657)
Recurring basis | Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets	96	7
Derivative Instrument Liabilities	(828)	(497)
Recurring basis | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	5	7
Derivative Instrument Liabilities	(6)	(6)
Recurring basis | Quoted Prices in Active Markets (Level I)
Fair Value Hierarchy
Assets and (liabilities), net	(68)	(46)
Recurring basis | Quoted Prices in Active Markets (Level I) | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets	34	40
Derivative Instrument Liabilities	(102)	(86)
Recurring basis | Significant Other Observable Inputs (Level II)
Fair Value Hierarchy
Assets and (liabilities), net	(882)	(616)
Recurring basis | Significant Other Observable Inputs (Level II) | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets	462	441
Derivative Instrument Liabilities	(611)	(568)
Recurring basis | Significant Other Observable Inputs (Level II) | Foreign exchange contracts
Fair Value Hierarchy
Derivative Instrument Assets	96	7
Derivative Instrument Liabilities	(828)	(497)
Recurring basis | Significant Other Observable Inputs (Level II) | Interest rate
Fair Value Hierarchy
Derivative Instrument Assets	5	7
Derivative Instrument Liabilities	(6)	(6)
Recurring basis | Significant Unobservable Inputs (Level III)
Fair Value Hierarchy
Assets and (liabilities), net	9	4
Recurring basis | Significant Unobservable Inputs (Level III) | Commodity contract | Power
Fair Value Hierarchy
Derivative Instrument Assets	13	7
Derivative Instrument Liabilities	CAD (4)	CAD (3)

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Net Change in Fair Value of Derivative Assets and Liabilities Classified as Level III (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Energy Revenue
Net change in the Level III fair value category
Revenues include unrealized gains attributed to derivatives in the Level III category	CAD 7	CAD 3
Commodity contract | Power
Net change in the Level III fair value category
Balance at beginning of year	4	1
Transfers out of Level III	5
Total gains included in Net income	3	3
Sales	(2)
Settlements	(1)
Balance at end of year	9	CAD 4
Commodity contract | Power | Level III
Net change in the Level III fair value category
Decrease in fair value of outstanding derivative instruments included in Level III due to a 10% increase in commodity prices	2
Increase in fair value of outstanding derivative instruments included in Level III due to a 10% decrease in commodity prices	CAD 2

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Counterparty Credit Risk (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD	Dec. 31, 2014 USD ($)
Risk Management and Financial Instruments [Abstract]
Credit risk concentration	CAD 248	$ 179	CAD 258	$ 222

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CHANGES IN OPERATING WORKING CAPITAL (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CHANGES IN OPERATING WORKING CAPITAL
Increase in Accounts receivable	CAD (20)	CAD (205)	CAD (60)
Increase in Inventories	(3)	(27)	(30)
(Increase)/decrease in Other current assets	(268)	(386)	40
(Decrease)/increase in Accounts payable and other	(159)	393	(291)
Increase in Accrued interest	91	36	7
Increase in Operating Working Capital	CAD (359)	CAD (189)	CAD (334)

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ACQUISITIONS AND DISPOSITIONS (Details) $ / shares in Units, CAD in Millions, $ in Millions						1 Months Ended			12 Months Ended			24 Months Ended
	Dec. 03, 2015 CAD	Apr. 01, 2015 USD ($)	Nov. 26, 2014 CAD	Oct. 01, 2014 USD ($)	Apr. 15, 2014 CAD	Jul. 31, 2013 USD ($)	May. 31, 2013 CAD shares	May. 31, 2013 USD ($) $ / shares shares	Dec. 31, 2015 CAD	Dec. 31, 2014 CAD facility	Dec. 31, 2013 CAD facility	Dec. 31, 2014 facility	Dec. 30, 2015	Dec. 04, 2015	Dec. 02, 2015	Apr. 30, 2013
ACQUISITIONS AND DISPOSITIONS
Proceeds from sale of assets, net of transaction costs (Note 25)										CAD 196
Gain (loss) on disposal									CAD (125)	117
Contributions made to equity investments									493	256	CAD 163
Purchase price									236	CAD 241	CAD 216
Gas Pacifico and INNERGY | Disposal group, not discontinued operations
ACQUISITIONS AND DISPOSITIONS
Ownership interest			30.00%
Proceeds from sale of assets, net of transaction costs (Note 25)			CAD 9
Gain (loss) on disposal			9
Proceeds from sale of assets, net of tax			CAD 8
Cancarb Limited | Disposal group, not discontinued operations
ACQUISITIONS AND DISPOSITIONS
Proceeds from sale of assets, net of transaction costs (Note 25)					CAD 190
Gain (loss) on disposition, gross					108
Gain (loss) on disposition, net of tax					CAD 99
Gas Transmission Northwest LLC | Natural Gas
ACQUISITIONS AND DISPOSITIONS
Ownership interest before transaction (as a percent)						45.00%
Ontario solar projects | Energy
ACQUISITIONS AND DISPOSITIONS
Number of facilities acquired | facility										4	4	8
Purchase price									CAD 457	CAD 241	CAD 216
Term of contract to sell solar power									20 years
TC PipeLines, LP
ACQUISITIONS AND DISPOSITIONS
Number of common units sold in an underwritten public offering (in shares) | shares							8,855,000	8,855,000
Price per common unit issued (in dollars per unit) | $ / shares								$ 43.85
Gross proceeds from public offering | $								$ 388
Net proceeds from issuance of common units | $								373
Capital contribution made to maintain general partnership interest | $								$ 8
General partnership interest							2.00%	2.00%
Ownership interest in subsidiary							28.90%	28.90%	28.00%	28.30%	28.90%	28.30%				33.30%
After-tax dilution gain recorded in additional paid-in capital							CAD 29
Pre-tax dilution gain recorded in additional paid-in capital as a result of decrease in ownership interest							CAD 47
Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas
ACQUISITIONS AND DISPOSITIONS
Ownership interest before transaction (as a percent)		30.00%
Total consideration | $		$ 457
Cash received | $		264
Assumption of debt by purchaser | $		98
Gas Transmission Northwest | Disposal group, disposed of by sale, not discontinued operations | Natural Gas | Class B units
ACQUISITIONS AND DISPOSITIONS
Receipt of new units | $		$ 95
Bison LLC | Natural Gas
ACQUISITIONS AND DISPOSITIONS
Ownership interest before transaction (as a percent)				30.00%
Cash received | $				$ 215
GTN LLC and Bison LLC | Natural Gas
ACQUISITIONS AND DISPOSITIONS
Cash received | $						$ 1,050
Long-term debt included in aggregate purchase price | $						$ 146
Percentage of acquired long-term debt						45.00%
Bruce Power
ACQUISITIONS AND DISPOSITIONS
Ownership interest									48.50%					48.50%
Bruce Power | Energy
ACQUISITIONS AND DISPOSITIONS
Ownership interest									48.50%
Bruce A
ACQUISITIONS AND DISPOSITIONS
Ownership interest													48.90%		48.90%
Bruce B
ACQUISITIONS AND DISPOSITIONS
Ownership interest	46.50%												31.60%		31.60%
Additional ownership acquired	14.89%
Contributions made to equity investments	CAD 236

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COMMITMENTS, CONTINGENCIES AND GUARANTEES - Operating Leases (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Minimum Lease Payments
2016	CAD 354
2017	355
2018	270
2019	248
2020	185
2021 and thereafter	311
Minimum Lease Payments	1,723
Amounts Recoverable under Sub-leases
2016	46
2017	45
2018	26
2019	24
2020	20
2021 and thereafter	1
Amounts Recoverable under Sub-leases	162
Net Payments
2016	308
2017	310
2018	244
2019	224
2020	165
2021 and thereafter	310
Net Payments	1,561
Rent Expense
Net rental expense on operating leases	CAD 131	CAD 114	CAD 98
Minimum
Rent Expense
Operating leases optional renewable terms, low end of range	1 year
Maximum
Rent Expense
Operating leases optional renewable terms, low end of range	25 years

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COMMITMENTS, CONTINGENCIES AND GUARANTEES - Power Purchase Arrangements (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2015 CAD MW	Dec. 31, 2014 CAD	Dec. 31, 2013 CAD
Alberta PPAs
Commitments under operating leases
Share of payments under PPAs | CAD	CAD 348	CAD 391	CAD 242
Sundance A (expires 2017)
Commitments under operating leases
Power generating capacities under PPAs (in megawatts)	560
Sheerness (expires 2020)
Commitments under operating leases
Power generating capacities under PPAs (in megawatts)	756

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COMMITMENTS, CONTINGENCIES AND GUARANTEES - Other Commitments and Contingencies (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015 CAD	Dec. 31, 2015 USD ($)	Dec. 31, 2014 CAD	Dec. 31, 2013 CAD
Contingencies
Amount accrued related to operating facilities for the estimated expenses to remediate the sites	CAD 32		CAD 31	CAD 32
Ironwood
Other Commitments
Purchase price | $		$ 657
Natural Gas Pipelines | Capital expenditures
Other Commitments
Commitment for capital expenditures	900		900
Liquids Pipelines | Capital expenditures
Other Commitments
Commitment for capital expenditures	800		1,800
Energy | Capital expenditures
Other Commitments
Commitment for capital expenditures	CAD 600		CAD 200

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COMMITMENTS, CONTINGENCIES AND GUARANTEES - Guarantees (Details) CAD in Millions	Dec. 31, 2015 CAD guarantee	Dec. 31, 2014 CAD guarantee
Guarantees
Number of guarantees without a termination date | guarantee	1	1
Contingent financial obligation
Guarantees
Potential Exposure	CAD 227	CAD 738
Carrying Value	26	20
Contingent financial obligation | Bruce Power
Guarantees
Potential Exposure	88	634
Carrying Value	2	6
Contingent financial obligation | Other
Guarantees
Potential Exposure	139	104
Carrying Value	CAD 24	CAD 14

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CORPORATE RESTRUCTURING COSTS (Details) - Employee severance CAD in Millions	12 Months Ended
	Dec. 31, 2015 CAD
Restructuring Cost and Reserve [Line Items]
Corporate restructuring costs incurred	CAD 122
Provision recorded for restructuring charges	87
Total corporate restructuring charges	209
Restructuring costs capitalized	8
Restructuring costs recoverable through regulatory and tolling structures	58
Regulatory asset
Restructuring Cost and Reserve [Line Items]
Total corporate restructuring charges	44
Plant operating cost and other
Restructuring Cost and Reserve [Line Items]
Total corporate restructuring charges	CAD 157

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RELATED PARTY TRANSACTIONS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Due from affiliates	CAD 2,476	CAD 2,842
Due to affiliates	311	866
Interest expense	28	37	CAD 62
Transcanada
Related Party Transaction [Line Items]
Interest income, inter-corporate borrowing	29	37	38
Accounts receivable	13	59
Accounts payable and other	12	16
Interest payable		1
Affiliates
Related Party Transaction [Line Items]
Amount	3,500
Discount Notes
Related Party Transaction [Line Items]
Due from affiliates	CAD 2,376	CAD 2,597
Effective interest rate (as a percent)	0.90%	1.30%
Credit Facility
Related Party Transaction [Line Items]
Due from affiliates	CAD 100	CAD 245
Effective interest rate (as a percent)	2.70%	3.00%
Credit Facility
Related Party Transaction [Line Items]
Due to affiliates	CAD 311	CAD 866
Effective interest rate (as a percent)	3.50%	3.80%
Credit Facility | Affiliates | Prime rate
Related Party Transaction [Line Items]
Spread on variable rate (as a percent)	0.75%
Interest
Related Party Transaction [Line Items]
Interest paid	CAD 29	CAD 37	CAD 62

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SUBSEQUENT EVENTS (Details)				12 Months Ended
	Feb. 01, 2016 USD ($) MW	Jan. 06, 2016 USD ($)	Jan. 01, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jan. 27, 2016 USD ($)
Ironwood
Subsequent Event [Line Items]
Purchase price				$ 657,000,000
Subsequent event | Ironwood
Subsequent Event [Line Items]
Power plant capacity (in megawatts) | MW	778
Purchase price	$ 657,000,000
Subsequent event | PNGTS
Subsequent Event [Line Items]
Ownership interest before transaction (as a percent)			49.90%
Total consideration			$ 223,000,000
Subsequent event | TCPL | Senior notes | Senior notes, due January 22, 2026, 4.875%
Subsequent Event [Line Items]
Debt					$ 850,000,000
Stated interest rate (as a percent)					4.875%
Subsequent event | TCPL | Senior notes | Senior notes, due January 22, 2019, 3.125%
Subsequent Event [Line Items]
Debt					$ 400,000,000
Stated interest rate (as a percent)					3.125%
Subsequent event | Pending litigation | Claim under Chapter 11 of North American Free Trade Agreement
Subsequent Event [Line Items]
Costs and damages sought		$ 15,000,000,000

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Label	Element	Value
Common Stock [Member]
Common Stock, Shares, Outstanding	us-gaap_CommonStockSharesOutstanding	779,479,000
Common Stock, Value, Issued	us-gaap_CommonStockValue	CAD 16,320,000,000