0001232384-17-000027.txt : 20170216 0001232384-17-000027.hdr.sgml : 20170216 20170216153544 ACCESSION NUMBER: 0001232384-17-000027 CONFORMED SUBMISSION TYPE: 40-F PUBLIC DOCUMENT COUNT: 186 CONFORMED PERIOD OF REPORT: 20161231 FILED AS OF DATE: 20170216 DATE AS OF CHANGE: 20170216 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TRANSCANADA CORP CENTRAL INDEX KEY: 0001232384 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 000000000 STATE OF INCORPORATION: A0 FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 40-F SEC ACT: 1934 Act SEC FILE NUMBER: 001-31690 FILM NUMBER: 17617742 BUSINESS ADDRESS: STREET 1: 450 - 1ST STREET S.W. CITY: CALGARY ALBERTA STATE: A0 ZIP: T2P 5H1 BUSINESS PHONE: 4039202000 MAIL ADDRESS: STREET 1: 450 - 1ST STREET S.W. CITY: CALGARY ALBERTA STATE: A0 ZIP: T2P 5H1 40-F 1 trp-12312016x40f.htm FORM 40-F Document


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, 2016           Commission File Number 1-31690
TRANSCANADA CORPORATION
(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))
Not Applicable
(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:
Title of each class
Name of each exchange on which registered
Common Shares (including Rights under Shareholder Rights Plan)
New York Stock Exchange
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: None
For annual reports, indicate by check mark the information filed with this Form:
x 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, 2016, 863,759,075 common shares;
9,498,423 Cumulative Redeemable First Preferred Shares, Series 1;
12,501,577 Cumulative Redeemable First Preferred Shares, Series 2;
8,533,405 Cumulative Redeemable First Preferred Shares, Series 3;
5,466,595 Cumulative Redeemable First Preferred Shares, Series 4;
12,714,261 Cumulative Redeemable First Preferred Shares, Series 5;
1,285,739 Cumulative Redeemable First Preferred Shares Series 6;
24,000,000 Cumulative Redeemable First Preferred Shares Series 7;
18,000,000 Cumulative Redeemable First Preferred Shares Series 9;
10,000,000 Cumulative Redeemable First Preferred Shares, Series 11;
20,000,000 Cumulative Redeemable First Preferred Shares, Series 13; and
40,000,000 Cumulative Redeemable First Preferred Shares, Series 15
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.
S-8
333-5916
S-8
333-8470
S-8
333-9130
S-8
333-151736
S-8
333-184074
F-3
33-13564
F-3
333-6132
F-10
333-151781
F-10
333-161929
F-10
333-208585
F-10
333-214971

AUDITED CONSOLIDATED ANNUAL FINANCIAL STATEMENTS AND
MANAGEMENT'S DISCUSSION & ANALYSIS
Except sections specifically referenced below which shall be deemed incorporated by reference herein and filed, no other portion of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders, except as otherwise specifically incorporated by reference in the TransCanada Corporation Annual information form, 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 119 through 194 of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders included herein.
B.    Management's Discussion and Analysis
For management's discussion and analysis, see pages 5 through 118 of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders included herein under the heading "Management's discussion and analysis".
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 119 of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders 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 99 of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders.
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 ("Code") for its directors, officers, employees and contractors. In 2016, the Code was amended to include new rules concerning the avoidance of conflicts of interest, maintaining a harassment, violence and weapons-free workplace and glossary to provide additional clarity thereto. Effective July 1, 2016, TransCanada acquired Columbia Pipeline Group, Inc. (Columbia). Columbia's code of business ethics and compliance program was assessed and determined to be essentially equivalent to TransCanada's Code. Columbia employees will transition to compliance with TransCanada's Code during 2017. The Registrant's Code was filed with the Commission as part of a Form 6-K report on November 8, 2016 and is incorporated herein by reference and available on its website at www.transcanada.com. No waivers have been granted from any provision of the Code during the 2016 fiscal year.
PRINCIPAL ACCOUNTANT FEES AND SERVICES
For information on principal accountant fees and services, see "Audit committee - Pre-approval Policies and Procedures" and "Audit committee - External Auditor Service Fees" on page 37 of the TransCanada Corporation Annual information form.
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 27 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 88 of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders.







IDENTIFICATION OF THE AUDIT COMMITTEE
The Registrant has a separately-designated standing Audit committee. The members of the Audit committee as of February 15, 2017 (unless otherwise indicated) are:
Chair:
Members:
S.A. Vanaselja
K.E. Benson
D.H. Burney
S. Crétier (effective February 17, 2017)
J.E. Lowe
I. Samarasekera
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 include information about the following, among other things:
planned changes in our business including the divestiture of certain assets
our financial and operational performance, including the performance of our subsidiaries
expectations or projections about strategies and goals for growth and expansion
expected cash flows and future financing options available to us
expected dividend growth
expected costs for planned projects, including projects under construction, permitting and in development
expected schedules for planned projects (including anticipated construction and completion dates)
expected regulatory processes and outcomes
expected 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 the following key assumptions, and subject to the following risks and uncertainties:

Assumptions
planned monetization of our U.S. Northeast power business
inflation rates, commodity prices and capacity prices
nature and scope of hedging
regulatory decisions and outcomes
the Canadian dollar to U.S. dollar exchange rate remains at or near current levels
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.

Risks and uncertainties
our ability to realize the anticipated benefits from the acquisition of Columbia Pipeline Group, Inc.





timing and execution of our planned asset sales
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 Commission.
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 CORPORATION
 
 
 
 
Per:
/s/ DONALD R. MARCHAND
 
 
DONALD R. MARCHAND
Executive Vice-President and Chief Financial Officer
 
 
 
 
 
Date: February 16, 2017




DOCUMENTS FILED AS PART OF THIS REPORT
EXHIBITS
 
 
13.1
TransCanada Corporation Annual information form for the year ended December 31, 2016.
 
 
13.2
Management's discussion and analysis (included on pages 5 through 118 of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders).
 
 
13.3
2016 Audited consolidated financial statements (included on pages 119 through 194 of the TransCanada Corporation 2016 Management's discussion and analysis and audited consolidated financial statements to shareholders), including the auditors' report thereon and the Report of Independent Registered Public Accounting Firm on the effectiveness of TransCanada's internal control over financial reporting as of December 31, 2016.
 
 
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.
 
 
99.1
Supplementary Information to the TransCanada Corporation 2016 Management's discussion and analysis.
 
 
99.2
A copy of the Registrant's Code of Business Ethics Policy as amended (filed with the Securities and Exchange Commission as part of a Form 6-K report on November 8, 2016 and incorporated by reference herein).
 
 
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 2 a12312016tccaifenglish.htm FORM 40-F ANNUAL INFORMATION FORM Document
EXHIBIT 13.1

TransCanada Corporation
2016 Annual information form
February 15, 2017




















image0a01.gif















BLANK PAGE FOR MARGINS - THIS PAGE WILL BE REMOVED WHEN FORMATTING HAS BEEN COMPLETED

 
 
TransCanada Annual information form 2016
2


Contents

 
 
TransCanada Annual information form 2016
1


Presentation of information
Throughout this Annual information form (AIF), the terms, we, us, our, the Company and TransCanada mean TransCanada Corporation and its subsidiaries. In particular, TransCanada includes references to TransCanada PipeLines Limited (TCPL). Where TransCanada is referred to with respect to actions that occurred prior to its 2003 plan of arrangement (Arrangement) with TCPL, which is described in the TransCanada Corporation - Corporate structure section below, such actions were taken by TCPL or its subsidiaries. The term subsidiary, when referred to in this AIF, with reference to TransCanada means direct and indirect wholly owned subsidiaries of, and legal entities controlled by, TransCanada or TCPL, as applicable.
Unless otherwise noted, the information contained in this AIF is given at or for the year ended December 31, 2016 (Year End). Amounts are expressed in Canadian dollars unless otherwise indicated. Information in relation to metric conversion can be found at Schedule A to this AIF. The Glossary found at the end of this AIF contains certain terms defined throughout this AIF and abbreviations and acronyms that may not otherwise be defined in this document.
Certain portions of TransCanada's Management's discussion and analysis dated February 15, 2017 (MD&A) are incorporated by reference into this AIF as stated below. The MD&A can be found on SEDAR (www.sedar.com) under TransCanada's profile.
Financial information is presented in accordance with U.S. generally accepted accounting principles (GAAP). We use certain financial measures that do not have a standardized meaning under GAAP and therefore they may not be comparable to similar measures presented by other entities. Refer to the About this document – Non-GAAP measures section of the MD&A for more information about the non-GAAP measures we use and a reconciliation to their GAAP equivalents, which section of the MD&A is incorporated by reference herein.
Forward-looking information
This AIF, including the MD&A disclosure incorporated by reference herein, contains certain information that is forward-looking and is subject to important risks and uncertainties. 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 include information about the following, among other things:
planned changes in our business including the divestiture of certain assets
our financial and operational performance, including the performance of our subsidiaries
expectations or projections about strategies and goals for growth and expansion
expected cash flows and future financing options available to us
expected dividend growth
expected costs for planned projects, including projects under construction, permitting and in development
expected schedules for planned projects (including anticipated construction and completion dates)
expected regulatory processes and outcomes
expected 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 the following key assumptions, and subject to the following risks and uncertainties:


 
2   
TransCanada Annual information form 2016
 


Assumptions
planned monetization of our U.S. Northeast power business
inflation rates, commodity prices and capacity prices
nature and scope of hedging
regulatory decisions and outcomes
the Canadian dollar to U.S. dollar exchange rate remains at or near current levels
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.
Risks and uncertainties
our ability to realize the anticipated benefits from the acquisition of Columbia Pipeline Group, Inc. (Columbia)
timing and execution of our planned asset sales
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.

 
 
TransCanada Annual information form 2016
3


TransCanada Corporation
CORPORATE STRUCTURE
Our head office and registered office are located at 450 – 1st Street S.W., Calgary, Alberta, T2P 5H1. TransCanada was incorporated pursuant to the provisions of the Canada Business Corporations Act (CBCA) on February 25, 2003 in connection with the Arrangement, which established TransCanada as the parent company of TCPL. The Arrangement was approved by TCPL common shareholders on April 25, 2003 and, following court approval and the filing of Articles of Arrangement, the Arrangement became effective May 15, 2003. Pursuant to the Arrangement, the common shareholders of TCPL exchanged each of their TCPL common shares for one common share of TransCanada. The debt securities and preferred shares of TCPL remained obligations and securities of TCPL (the preferred shares of TCPL have been subsequently redeemed). TCPL continues to carry on business as the principal operating subsidiary of TransCanada. TransCanada does not hold any material assets directly other than the common shares of TCPL and receivables from certain of TransCanada's subsidiaries.
INTERCORPORATE RELATIONSHIPS
The following diagram presents the name and jurisdiction of incorporation, continuance or formation of TransCanada’s principal subsidiaries as at Year End. Each of the subsidiaries shown has total assets that exceeded 10 per cent of the total consolidated assets of TransCanada as at Year End or revenues that exceeded 10 per cent of the total consolidated revenues of TransCanada for the year then ended. TransCanada beneficially owns, controls or directs, directly or indirectly, 100 per cent of the voting shares or units in each of these subsidiaries.
TransCanada Corporation – Canada
TransCanada PipeLines Limited – Canada
TransCanada PipeLine USA Ltd. – Nevada
TransCanada Oil Pipelines Inc. – Delaware
Columbia Pipeline Group, Inc. – Delaware
Columbia Energy Group – Delaware
Columbia Pipeline Partners LP – Delaware
CPG OpCo LP – Delaware
NOVA Gas Transmission Ltd. – Alberta

orgcharta03.jpg
The above diagram does not include all of the subsidiaries of TransCanada. The assets and revenues of excluded subsidiaries in the aggregate did not exceed 20 per cent of the total consolidated assets of TransCanada as at Year End or total consolidated revenues of TransCanada for the year then ended.

 
4   
TransCanada Annual information form 2016
 


General development of the business
We operate in three core businesses: Natural Gas Pipelines, Liquids Pipelines and Energy. As a result of our acquisition of Columbia on July 1, 2016 and the pending sales of the U.S. Northeast power business, we have determined that a change in our operating segments is appropriate. Accordingly, we consider ourselves to be operating in the following segments: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy. This provides information that is aligned with how management decisions about our business are made and how performance of our business is assessed. We also have a non-operational Corporate segment consisting of corporate and administrative functions that provide governance and other support to our operational business segments.
Natural Gas Pipelines and Liquids Pipelines are principally comprised of our respective natural gas and liquids pipelines in Canada, the U.S. and Mexico as well as our regulated natural gas storage operations in the U.S. Energy includes our power operations and the non-regulated natural gas storage business in Canada.
Summarized below are significant developments that have occurred in our Natural Gas Pipelines, Liquids Pipelines and Energy businesses, respectively, and certain acquisitions, dispositions, events or conditions which have had an influence on that development, during the last three financial years and year to date in 2017. Further information about changes in our business that we expect to occur during the current financial year can be found in the Canadian Natural Gas Pipelines , U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, Liquids Pipelines and Energy sections of the MD&A, which sections of the MD&A are incorporated by reference herein.
NATURAL GAS PIPELINES
Developments in the Canadian Natural Gas Pipelines segment
Date
Description of development
 
 
CANADIAN REGULATED PIPELINES
 
 
NGTL System
 
 
March 2014
We received an NEB Safety Order (the Order) in response to the recent pipeline releases on the NGTL System. The Order required us to reduce the maximum operating pressure on three per cent of NGTL’s pipeline segments. We filed a request for a review and variance of the Order that would minimize gas disruptions while still maintaining a high level of safety, which the NEB granted in April 2014 subject to certain conditions. We accelerated components of our integrity management program to address the NEB Order.
March 2014
The NEB approved approximately $400 million in NGTL facility expansions.
Fourth Quarter 2014
We continued to experience significant growth on the NGTL System as a result of growing natural gas supply in northwestern Alberta and northeastern British Columbia (B.C.) from unconventional gas plays and substantive growth in intra-basin delivery markets. This demand growth was driven primarily by oil sands development, gas-fired electric power generation and expectations regarding B.C. west coast LNG projects.
First Quarter 2015
The NGTL System had approximately $6.7 billion of new supply and demand facilities under development and we continued to advance several of these capital expansion projects by filing the regulatory applications with the NEB. We also received additional requests for firm receipt service.
Fourth Quarter 2015 / First Quarter 2016
In 2015, we placed approximately $350 million of facilities in service. In 2016, the NGTL System continued to develop further new supply and demand facilities. We had approximately $2.3 billion of facilities that received regulatory approval and had approximately $450 million currently under construction. We 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 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. Subject to regulatory approvals, construction is expected to start in 2017, with all facilities expected to be in service in 2018.
October 2016
On October 6, 2016, the NEB recommended government approval of the $0.4 billion Towerbirch Project. This project consists of a 55 km (34 miles) 36-inch pipeline loop and a 32 km (20 miles) 30-inch pipeline extension of the NGTL System in northwest Alberta and northeast B.C. The NEB approved the continued use of the existing rolled-in toll methodology for this project. On October 31, 2016, the Government of Canada approved our $1.3 billion NGTL 2017 Facilities Application, which is a major component of the 2016/2017 program. This NGTL expansion program consists of five pipeline loops ranging in size from 24-inch up to 48-inch pipe of approximately 230 km (143 miles) in length, plus two compressor station unit additions of approximately 46.5 MW (62,360 HP).

 
 
TransCanada Annual information form 2016
5


Date
Description of development
December 2016
We announced the $0.6 billion Saddle West expansion of the NGTL System to increase natural gas transportation capacity on the northwest portion of our system. The project will consist of 29 km (18 miles) of 36-inch pipeline looping of existing mainlines, the addition of five compressor units at existing station sites and new metering facilities. The project is underpinned by incremental firm service contracts and is expected to be in-service in 2019. NGTL currently has a $3.7 billion near-term capital program for completion to 2020, including the Saddle West expansion and excluding the $1.7 billion North Montney and $1.9 billion Merrick pipeline projects. In 2016, we have placed in service approximately $0.5 billion of facilities. We currently have regulatory approval for $2.0 billion of facilities and plan to place in service $1.6 billion of new facilities in 2017.
 
 
NGTL Revenue Requirement Settlements
 
 
October 2014
We reached a revenue requirement settlement with our shippers for 2015 on the NGTL System.
February 2015
We received NEB approval for our revenue requirement settlement with our shippers for 2015 on the NGTL System. The terms of the one year settlement include continuation of the 2014 ROE of 10.1 per cent on 40 per cent deemed equity, continuation of the 2014 depreciation rates and a mechanism for sharing variances above and below a fixed operating, maintenance and administration (OM&A) expense amount that is based on an escalation of 2014 actual costs.
December 2015

We reached a two-year revenue requirement agreement with customers and other interested parties on the annual costs, including return on equity and depreciation required to operate the NGTL System for 2016 and 2017. The agreement fixes the equity return at 10.1 per cent on 40 per cent deemed common equity, establishes depreciation at a forecast composite rate of 3.16 per cent and fixes OM&A costs at $222.5 million annually. An incentive mechanism for variances will enable NGTL to capture savings from improved performance and provide for the flow-through of all other costs, including pipeline integrity expenses and emissions costs. on December 1, 2015, NGTL filed with the NEB for approval of the agreement.
 
 
North Montney
 
 
June 2015
The NEB approved the $1.7 billion North Montney Mainline (NMML) project subject to certain terms and conditions. Under one of these conditions, construction on the NMML project can only begin after a positive final investment decision (FID) has been made on the proposed Pacific North West LNG project (PNW LNG). The NMML 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 Western Canada Sedimentary Basin (WCSB) supply to both existing and new natural gas markets, including LNG markets. The project will also include an interconnection with our proposed Prince Rupert Gas Transmission Project (PRGT) to provide natural gas supply to the proposed PNW LNG liquefaction and export facility near Prince Rupert, B.C.
September 2016
The Canadian Government approved the sunset clause extension request we filed in March 2016, for the NMML Certificate of Public Convenience and Necessity for one year to June 10, 2017. The extension continues to be subject to the condition that construction shall not begin until a positive FID has been made on PNW LNG. NGTL continues to work with our customers and stakeholders to be ready to initiate construction of the $1.7 billion North Montney facilities, however, the in-service date will be finalized once a FID has been made.
 
 
Canadian Mainline – Kings North and Station 130 Facilities
 
 
Fourth Quarter 2016
We placed in service the approximate $310 million Kings North Connector and the approximate $75 million compressor unit addition at Station 130 on the Canadian Mainline system. These two projects are consistent with our current 2015-2020 Mainline Settlement with our shippers and provide optionality to access alternative supply sources while contracting for increased short haul transportation service within the Eastern Triangle area of the Canadian Mainline system.
 
 
Canadian Mainline – Eastern Mainline Project
 
 
May 2014
We filed a project description with the NEB for the Eastern Mainline Project.
October 2014
We filed an application with the NEB for the Energy East pipeline project and to transfer a portion of the Canadian Mainline from natural gas service to crude oil service. We also filed an application for the Eastern Mainline Project, consisting of new gas facilities in southeastern Ontario required as a result of the proposed transfer of Mainline assets to crude oil service for the Energy East pipeline project. This $2 billion project consists of new gas facilities in southeastern Ontario that will be required as a result of the proposed Energy East pipeline project that includes a planned transfer of a portion of Canadian Mainline from natural gas service to crude oil service.
August 2015
TransCanada announced it had reached an agreement with eastern local distribution companies (LDCs)
 that resolved their issues with Energy East pipeline project and the Eastern Mainline Project.
December 2015
Application amendments were filed that reflect the agreement we announced in August 2015 with eastern LDCs resolving their issues with Energy East pipeline project and the Eastern Mainline Project. The agreement provided gas consumers in eastern Canada with sufficient natural gas transmission capacity and provides for reduced natural gas transmission costs.

 
6   
TransCanada Annual information form 2016
 


Date
Description of development
January 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. The Eastern Mainline Project is conditioned on the approval and construction of the Energy East pipeline. Refer to the General development of the business – Liquids pipelines section for an update on Energy East.
 
 
Canadian Mainline – Other Expansions
 
 
January 2014
Shippers on the Canadian Mainline elected to renew approximately 2.5 Bcf/d of their contracts through November 2016.
November 2014
In addition to the Eastern Mainline Project, we executed new short haul arrangements in the Eastern Triangle portion of the Canadian Mainline that require new facilities, or modifications to existing facilities. These projects are subject to regulatory approval and, once constructed, will provide capacity needed to meet customer requirements in eastern Canada.
First Quarter 2016
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 were required to meet contractual commitments from shippers. Also refer to the Canadian Mainline - Kings North and Station 130 Facilities section
above.
Third Quarter 2016
We launched an open season for the Canadian Mainline, seeking binding commitments on our new long-term, fixed-price proposal to transport WCSB supply from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The open season for the proposed service resulted in bids that fell well short of the volumes required to make the proposal viable. On November 15, 2016 we announced we would not proceed with the service offering at this time.
First Quarter 2017
In addition to the Eastern Mainline Project, new facilities investments in the Eastern Triangle portion of the Canadian Mainline are planned for 2017. Including the Vaughan Loop, with a planned in-service date of November 2017, we have approximately $300 million of additional investment to meet contractual commitments from shippers.
 
 
Canadian Mainline Settlement
 
 
March 2014
The Canadian Mainline and the three largest Canadian local distribution companies (LDCs) entered into a settlement (LDC Settlement) which was filed with the NEB for approval in December 2013. In March 2014, the NEB responded to the LDC Settlement application and did not approve the application as a settlement, but allowed us the option to continue with the application as a contested tolls application, amend the application or terminate the processing of the application. The LDC Settlement calculated tolls for 2015 on a base ROE of 10.1 per cent on 40 per cent deemed common equity. It also included an incentive mechanism that required a $20 million (after tax) annual contribution by us from 2015 to 2020, which could have resulted in a range of ROE outcomes from 8.7 per cent to 11.5 per cent. The LDC Settlement would have enabled the addition of facilities in the Eastern Triangle to serve immediate market demand for supply diversity and market access. The LDC Settlement was intended to provide a market driven, stable, long-term accommodation of future demand in this region in combination with the anticipated lower demand for transportation on the Prairies Line and the Northern Ontario Line while providing a reasonable opportunity to recover our costs. The LDC Settlement also retained pricing flexibility for discretionary services and implemented certain tariff changes and new services as required by the terms of the settlement. We amended the application with additional information.
November 2014
Following a hearing, the NEB approved the Canadian Mainline's 2015 - 2030 Tolls and Tariff Application (the NEB 2014 Decision) which superseded the NEB 2013 Decision. The application reflected components of the LDC Settlement. In 2014, the Canadian Mainline operated under the NEB's 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.
First Quarter 2015
In 2015, the Canadian Mainline began operating under the NEB 2014 Decision.
August 2015
TransCanada announced it had reached an agreement with the eastern LDCs that resolves the LDCs’ issues with Energy East and the Eastern Mainline Project.

 
 
TransCanada Annual information form 2016
7


Date
Description of development
 
 
LNG PIPELINE PROJECTS
 
Prince Rupert Gas Transmission
 
 
November 2014
We received an Environmental Assessment Certificate (EAC) from the B.C. Environmental Assessment Office (EAO). We submitted our pipeline permit applications to the B.C. Oil and Gas Commission (OGC) for construction of the pipeline. We made significant changes to the project route since first announced, increasing it by 150 km (93 miles) to 900 km (559 miles), taking into account Aboriginal and stakeholder input. We continued to work closely with Aboriginal groups and stakeholders along the proposed route to create and deliver appropriate benefits to all impacted groups. We concluded a benefits agreement with the Nisga’a First Nation to allow 85 km (52 miles) of the proposed natural gas pipeline to run through Nisga'a Lands.
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.
Third Quarter 2015
We received all remaining permits from the B.C. OGC which completed the eleven permits required to build and operate PRGT. Environmental permits for the project were received in November 2014 from the B.C. 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 will be aligned with PNW LNG’s liquefaction facility timeline.
September 2016
PNW LNG received an environmental certificate from the Government of Canada for a proposed LNG plant at Prince Rupert, B.C. PNW LNG has indicated they will conduct a total project review over the coming months prior to announcing next steps for the project. The project has key approvals in place and will advance construction following direction from PNW LNG.
December 2016
PNW LNG received an LNG export license from the NEB which extended the export term from 25 years to 40 years.
We continued our engagement with Indigenous groups and have now signed project agreements with 14 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 miles) natural gas pipeline that will deliver gas from the North 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. The in-service date for PRGT will be aligned with PNW LNG's liquefaction facility timeline.
 
 
Coastal GasLink
 
 
January 2014
We filed the EAC application with the B.C. EAO. We focused on community, landowner, government and Aboriginal engagement as the project advanced through the regulatory process. The pipeline was expected to be placed in service near the end of the decade, subject to a FID to be made by LNG Canada after obtaining final regulatory approvals. Coastal GasLink is a 670 km (416 miles) pipeline that will deliver natural gas from Montney gas producing region at an expected interconnect on NGTL near the Dawson Creek, B.C. area, to LNG Canada’s proposed LNG facility near Kitimat, BC. Should the project not proceed, our project costs (including carrying charges) are fully recoverable.
October 2014
The EAO issued an EAC for Coastal GasLink. In 2014, we also submitted applications to the B.C. OGC for the permits required under the Oil and Gas Activities Act to build and operate Coastal GasLink.
First Quarter 2016
We continued to engage with Indigenous groups and have now announced project agreements with 11 First Nation groups along the pipeline route which outline financial and other benefits and commitments that will be provided to each First Nation group for as long as the project is in service. We also continued to engage with stakeholders along the pipeline route and progressed detailed engineering and construction planning work to refine the capital cost estimate. In response to feedback received, we applied for a minor route amendment to the B.C. EAO in order to provide an option in the area of concern.
July 2016
The LNG Canada joint venture participants announced a delay to their FID for the proposed liquefied natural gas facility in Kitimat, B.C. A future FID date has not been disclosed. We worked with LNG Canada to maintain the appropriate pace of the Coastal GasLink development schedule and work activities. We continued our engagement with Indigenous groups along our pipeline route and have now concluded long-term project agreements with 17 First Nation communities. We look to continue discussions with the remaining First Nations who have not signed project agreements.
 
 
Merrick Mainline
 
 
June 2014
We announced the signing of agreements for approximately 1.9 Bcf/d of firm natural gas transportation services to underpin the development of a major extension of our NGTL System. The Merrick Mainline pipeline will deliver natural gas from NGTL's existing Groundbirch Mainline and the proposed PRGT project. Since the Merrick Mainline is dependent upon the construction of the downstream infrastructure, the in-service date of the Merrick Mainline remains uncertain.
 
 

 
8   
TransCanada Annual information form 2016
 


Developments in the U.S. Natural Gas Pipelines segment
Date
Description of development
 
 
COLUMBIA ACQUISITION
 
 
July 2016
On July 1, 2016, we acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash. The acquisition was initially financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, following the closing of the acquisition, the subscription receipts were exchanged into 96.6 million TransCanada common shares. In respect of the acquisition, we filed a business acquisition report on Form 51-102F4 on July 22, 2016, which can be found on the Company’s SEDAR profile at www.SEDAR.com. For more information about the acquisition of Columbia, refer to the About our business – Acquisition of Columbia Pipeline Group, Inc. section of the MD&A.
 
 
COLUMBIA CAPITAL PROJECTS
 
Third Quarter 2016
The July 1, 2016 acquisition of Columbia included a capital expansion program that was underway for new facilities planned to be in service in 2016 through 2018 as well as modernization programs for existing assets to be completed through 2020. The large capital expansion program, less projects completed in 2016, consists of US$6.8 billion related to our regulated pipeline business and US$0.3 billion related to our midstream business. The estimated project costs exclude AFUDC. The following summarizes the eight key capital projects for this new set of assets that are now part of our overall U.S. Natural Gas Pipelines footprint. For clarification, when used below, Columbia Gas is our natural gas transportation system for the Appalachian basin, which contains the Marcellus and Utica shale plays. This system also interconnects with other pipelines that provide access to key markets in the U.S. Northeast and south to the Gulf of Mexico and its growing demand for natural gas to serve LNG exports. Access to markets from producers in the region is driving the large capital program for new pipeline facilities on this system. Columbia Gulf is our pipeline system originally designed as a long haul delivery system transporting supply from the Gulf of Mexico to major supply markets in the U.S. Northeast. The pipeline is now transitioning and expanding to accommodate new supply in the Appalachian basin and its interconnect with Columbia Gas and other pipelines to deliver gas to various Gulf Coast markets.
 
 
Leach XPress
 
June 2015
The FERC 7(C) application for this Columbia Gas project was filed. The project is designed to transport approximately 1.5 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with Columbia Gulf. The project consists of 219 km (136 miles) of 36-inch greenfield pipe, 39 km (24 miles) of 36-inch loop, three km (two miles) of 30- inch greenfield pipe, 82.8 MW (111,000 hp) of greenfield compression and 24.6 MW (33,000 hp) of brownfield compression.
September 2016
The Final Environmental Impact Statement (FEIS) for the project was received.
January 2017
The FERC Order approving the construction of the facility was issued. Once remaining regulatory approvals are obtained, we plan to begin right-of-way preparation and construction activities in February 2017. We expect the project, with an estimated capital investment of US$1.4 billion, to be in service in fourth quarter 2017.
 
 
Rayne XPress
 
July 2015

The FERC 7(C) application for this Columbia Gulf project was filed. The project is designed to transport approximately 1.1 Bcf/d of southwest Marcellus and Utica production associated with the Leach XPress expansion and an interconnect with the Texas Eastern System to various delivery points on Columbia Gulf and the Gulf Coast. The project consists of bi-directional compressor station modifications along Columbia Gulf, 38.8 MW (52,000 hp) of greenfield compression, 20.1 MW (27,000 hp) of replacement compression and six km (four miles) of 30-inch pipe replacement.
September 2016
The FEIS for the project was received.
January 2017
The FERC Order approving the construction of the facility was issued. We expect the project, with an estimated capital investment of US$0.4 billion, to be in service on November 1, 2017.
 
 
Mountaineer XPress
 
 April 2016
The FERC 7(C) application for this Columbia Gas project was filed. The project is designed to transport approximately 2.7 Bcf/d of Marcellus and Utica gas supply to delivery points along the pipeline and to the Leach interconnect with Columbia Gulf. The project consists of 264 km (164 miles) of 36-inch greenfield pipeline, 10 km (six miles) of 24-inch lateral pipeline, 0.6 km (0.4 miles) of 30-inch replacement pipeline, 114.1 MW (153,000 hp) of greenfield compression and 55.9 MW (75,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$2.0 billion, to be in service in fourth quarter 2018.

 
 
TransCanada Annual information form 2016
9


Date
Description of development
 
 
Gulf XPress
 
April 2016
The FERC 7(C) application for this Columbia Gulf project was filed. The project is designed to transport approximately 0.9 Bcf/d associated with the Mountaineer XPress expansion to various delivery points on Columbia Gulf and the Gulf Coast. The project consists of adding seven greenfield midpoint compressor stations along the Columbia Gulf route totaling 182.7 MW (254,000 hp). We expect this project, with an estimated capital investment of US$0.6 billion, to be placed in service in fourth quarter 2018.
 
 
Cameron Access Project
 
September 2015
The FERC certificate for this Columbia Gulf project was received. The project is designed to transport approximately 0.8 Bcf/d of gas supply to the Cameron LNG export terminal in Louisiana. The project consists of 44 km (27 miles) of 36-inch greenfield pipeline, 11 km (seven miles) of 30-inch looping and 9.7 MW (13,000 hp) of greenfield compression. We expect this project, with an estimated capital investment of US$0.3 billion, to be in service in first quarter 2018.
 
 
WB XPress
 
December 2015
The FERC 7(C) application for both segments of this Columbia Gas project was filed. The project is designed to transport approximately 1.3 Bcf/d of Marcellus gas supply westbound (0.8 Bcf/d) to the Gulf Coast via an interconnect with the Tennessee Gas Pipeline, and eastbound (0.5 Bcf/d) to Mid-Atlantic markets. The project consists of 47 km (29 miles) of various diameter pipeline, 338 km (210 miles) of restoring and uprating maximum operating pressure of existing pipeline, 29.8 MW (40,000 hp) of greenfield compression and 99.9 MW (134,000 hp) of brownfield compression. We expect this project, with an estimated capital investment of US$0.8 billion, to have a Western build in service in the beginning of second quarter 2018 and an Eastern build in service in fourth quarter 2018.
 
 
Modernization I & II
 
First Quarter 2017
Columbia Gas and its customers have entered into a settlement arrangement, approved by FERC, which provides recovery and return on investment to modernize its system, improve system integrity and enhance service reliability and flexibility. The modernization program includes, among other things, replacement of aging pipeline and compressor facilities, enhancements to system inspection capabilities and improvements in control systems. Modernization I has been approved for up to US$0.6 billion of work with approximately US$0.2 billion remaining to be spent in 2017. Modernization II has been approved for up to US$1.1 billion of work to be completed through 2020. As per terms of the arrangements, facilities in service by October 31 collect revenues effective February 1 of the following year.
 
 
Midstream – Gibraltar Pipeline Project
 
December 2016
The first phase of the multi-phase project was completed. We expect to complete the US$0.3 billion investment to construct an approximate 1,000 TJ/d dry gas header pipeline in southwest Pennsylvania by the end of 2017.
 
 
OTHER U.S. NATURAL GAS PIPELINES
 
 
Columbia Pipeline Partners LP (CPPL)
 
 
November 2016
We announced that we entered into an agreement and plan of merger through which Columbia agreed to acquire, for cash, all of the outstanding publicly held common units of CPPL at a price of US$17.00 per common unit for an aggregate transaction value of approximately US$915 million. The transaction is expected to close in first quarter 2017.
 
 
ANR Pipeline
 
 
March 2014
We secured nearly 2.0 Bcf/d of additional firm natural gas transportation commitments for existing and expanded capacity on ANR Pipeline's Southeast Mainline (SEML). The capacity sales and expansion projects include reversing the Lebanon Lateral in western Ohio, additional compression at Sulphur Springs, Indiana, expanding the Rockies Express pipeline interconnect near Shelbyville, Indiana and 600 MMcf/d of capacity as part of a reversal project on ANR's SEML. Capital costs associated with the ANR System expansions required to bring the additional capacity to market were estimated to be US$150 million. The capacity was subscribed at maximum rates for an average term of 23 years with approximately 1.25 Bcf/d of new contracts beginning service in late 2014. These secured contracts on the SEML will move Utica and Marcellus shale gas to points north and south on the system. ANR also assessed further demand from our customers to transport natural gas from the Utica/Marcellus formation, which was expected to result in incremental opportunities to enhance and expand the system.
January 2016
ANR Pipeline filed a Section 4 Rate Case 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 resulted in the current tariff rates not providing a reasonable return on our investment. We also pursued 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.

 
10   
TransCanada Annual information form 2016
 


Date
Description of development
Second and Third Quarters 2016

ANR reached a settlement with its shippers effective August 1, 2016 and received FERC approval on December 16, 2016. Per the settlement, transmission reservation rates will increase by 34.8 per cent and storage rates will remain the same for contracts one to three years in length, while increasing slightly for contracts of less than one year and decreasing slightly for contracts more than three years in duration. There is a moratorium on any further rate changes until August 1, 2019. ANR may file for new rates after that date if it has spent more than US$0.8 billion in capital additions, but must file for new rates no later than an effective date of August 1, 2022. In addition to ANR’s rate case settlement, FERC approvals were obtained for settlements with shippers for our Iroquois, Tuscarora and Columbia Gulf pipelines.
 
 
Great Lakes
 
 
February 2016
We reduced forecasted cash flows 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. Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$386 million at December 31, 2016 (2015 – US$386 million).
 
 
Sale of Gas Transmission Northwest LLC (GTN) Pipeline and Portland Natural Gas Transmission System (PNGTS)
to TC PipeLines, LP (TCLP)
 
April 2015

We closed the sale of our remaining 30 per cent interest in GTN to TCLP for an aggregate purchase price of US$457 million. Proceeds were comprised of US$246 million in cash, the assumption of US$98 million in proportional GTN debt and US$95 million of new Class B units of TCLP.
January 2016
We closed the sale of 49.9 per cent of our total 61.7 per cent interest in PNGTS to TCLP for US$223 million including the assumption of US$35 million of proportional PNGTS debt.
 
 
TC Offshore LLC (TC Offshore)
 
 
December 2015
We entered into an agreement to sell TC Offshore to a third party and expected 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 provisions of $125 million recorded in 2015.
March 2016
We completed the sale of TC Offshore to a third party.
 
 
Iroquois Gas Transmission System, L.P. (Iroquois)
 
 
First/Second Quarter 2016
On March 31, 2016, we acquired an additional 4.87 per cent interest in Iroquois for an aggregate purchase price of US$54 million and on May 1, 2016, a further 0.65 per cent was acquired for US$7 million. As a result, our interest in Iroquois has increased to 50 per cent.
 
 
LNG PIPELINE PROJECTS
 
 
Alaska LNG Project
 
 
April 2014
The State of Alaska passed new legislation to provide a framework for us, the three major North Slope producers (the ANS Producers), and the Alaska Gasline Development Corp. (AGDC) to advance the development of an LNG export project.
June 2014
We executed an agreement with the State of Alaska to abandon the previous Alaska to Alberta project governance and framework and executed a new precedent agreement where we will act as the transporter of the State’s portion of natural gas under a long-term shipping contract in the Alaska LNG Project. We also entered into a Joint Venture Agreement with the three major ANS Producers and AGDC to commence the pre-front end engineering and design (pre-FEED) phase of Alaska LNG Project. The pre-FEED work was anticipated to take two years to complete with our share of the cost to be approximately US$100 million. The precedent agreement also provided us with full recovery of development costs in the event the project did not proceed.
November 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.

 
 
TransCanada Annual information form 2016
11


Developments in the Mexico Natural Gas Pipelines segment
Date
Description of development
 
 
Mexico Natural Gas Pipelines
 
Topolobampo
 
First Quarter 2017
The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a cost of US$1.0 billion that will receive natural gas from upstream pipelines near El Encino in the state of Chihuahua. The pipeline will deliver natural gas from these interconnecting pipelines to delivery points along the pipeline route including our Mazatlán pipeline at El Oro in the state of Sinaloa. Construction of the pipeline is supported by a 25-year natural gas Transportation Service Agreement (TSA) for 670 MMcf/d with the CFE. Completion of construction is delayed into 2017 due to delays with Indigenous consultations by others. Under the terms of the TSA, this delay is recognized as a force majeure event with provisions allowing for the collection of revenue as per the original TSA service commencement date of July 2016.
 
Mazatlán
 
 
November 2015
The Mazatlán project is a 413 km (257 miles), 24-inch diameter pipeline running from El Oro to Mazatlán within the state of Sinaloa with an estimated cost of US$0.4 billion. This pipeline is supported by a 25-year natural gas TSA for 200 MMcf/d with the CFE.
Third Quarter 2016
Physical construction is complete and is awaiting natural gas supply from upstream interconnecting pipelines. We have met our obligations and thus are collecting revenue as per provisions in the contract and per the original TSA service commencement date of December 2016.

 
Tula
 
 
November 2015
We were awarded the contract to build, own and operate the US$0.6 billion, 36 inch, 300 km (186 miles) pipeline supported by a 25-year natural gas TSA for 886 MMcf/d with the CFE. The pipeline will transport natural gas from Tuxpan, Veracruz to markets near Tula, Querétaro extending through the states of Puebla and Hidalgo.
Third Quarter 2016
Construction commenced in the region that does not require Indigenous community consultations by others. Completion of construction is revised to 2018 due to delays with Indigenous consultation.
 
Villa de Reyes Pipeline
 
 
April 2016
We announced that we were awarded the contract to build, own and operate the Villa de Reyes pipeline in Mexico. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 886 MMcf/d with the CFE. We expect to invest approximately US$0.6 billion to construct 36- and 24-inch diameter pipelines totaling 420 km (261 miles) with an anticipated in-service date of early 2018. The bi-directional pipeline will transport natural gas between Tula, in the state of Hidalgo, and Villa de Reyes, in the state of San Luis Potosí. The project will interconnect with our Tamazunchale and Tula pipelines as well as with other transporters in the region.
 
Sur de Texas
 
 
June 2016
We announced that our joint venture with IEnova had been chosen to build, own and operate the US$2.1 billion Sur de Texas pipeline in Mexico. We will have a 60 per cent interest in this project. Construction of the pipeline is supported by a 25-year natural gas transportation service contract for 2.6 bcf/d with the CFE. We expect to invest approximately US$1.3 billion in the joint venture to construct the 42-inch diameter, approximately 800 km (497 miles) pipeline with an anticipated in-service date of late 2018. The pipeline will start offshore in the Gulf of Mexico, at the border point near Brownsville, Texas, and end in Tuxpan, Mexico in the state of Veracruz. The project will deliver natural gas to our Tamazunchale and Tula pipelines and to other transporters in the region.
 
Tamazunchale Pipeline Extension Project
 
 
November 2014

Construction of the US$600 million extension was completed. Delays from the original service commencement date in March 2014 were attributed primarily to archeological findings along the pipeline route. Under the terms of the transportation service agreement, these delays were recognized as a force majeure with provisions allowing for collection of revenue from the original service commencement date.
 
 
Further information about developments in the Natural Gas Pipelines business, including changes that we expect will occur in the current financial year, can be found in the MD&A in the About our business – Our strategy and Natural Gas Pipelines business sections; Canadian Natural Gas Pipelines – Financial results, Outlook, Understanding the Canadian Natural Gas Pipelines segment and Significant events sections; U.S. Natural Gas Pipelines – Financial results, Outlook, Understanding the U.S. Natural Gas Pipelines segment and Significant events sections; and Mexico Natural Gas Pipelines – Financial results, Outlook, Understanding the Mexico Natural Gas Pipelines segment, and Significant events sections, which sections of the MD&A are incorporated by reference herein.

 
12   
TransCanada Annual information form 2016
 


LIQUIDS PIPELINES
Date
Description of development
 
 
Keystone Pipeline System
 
 
Second Quarter 2015
We entered into an agreement with CITGO Petroleum (CITGO) to construct a US$65 million pipeline connection between the Keystone Pipeline and 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.
Fourth Quarter 2015
We secured additional long term contracts bringing our total contract position up to 545,000 Bbl/d.
January 2016
We entered into an agreement with Magellan Midstream Partners L.P. (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 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.
Second Quarter 2016
On April 2, 2016, we shut down the Keystone Pipeline after a leak was detected along the pipeline right-of-way in Hutchinson County, South Dakota. We reported the total volume of the release of 400 barrels to the National Response Center and the Pipeline and Hazardous Materials Safety and Administration (PHMSA). Temporary repairs were completed and the Keystone Pipeline was restarted by mid-April 2016. Shortly thereafter in early May 2016, permanent pipeline repairs were completed and restoration work was completed by early July 2016. Corrective measures required by PHMSA were completed in September 2016. This shutdown did not significantly impact our 2016 earnings.
August 2016
The Houston Lateral pipeline and terminal, an extension from the Keystone Pipeline to Houston, Texas, went into service. The terminal has an initial storage capacity for 700,000 barrels of crude oil.
December 2016
The HoustonLink pipeline which connects the Houston Terminal to Magellan's Houston and Texas City, Texas delivery system was completed.
December 2016
The CITGO Sour Lake pipeline connection between the Keystone Pipeline and CITGO's Sour Lake, Texas terminal was placed into service.
 
 
Keystone XL
 
 
January 2015
The Nebraska State Supreme Court vacated the lower court’s ruling that the law was unconstitutional. As a result, the Governor’s January 2013 approval of the alternate route through Nebraska for Keystone XL remains valid. Landowners have filed lawsuits in two Nebraska counties seeking to enjoin Keystone XL from condemning easements on state constitutional grounds.
November 2015
The decision on the Keystone XL Presidential permit application was delayed throughout 2015 by the Department of State (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 aftertax). 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 calculation of this impairment is discussed further in the Other information – Critical accounting estimates section of the MD&A. The Keystone Hardisty Terminal remains on hold with an estimated in-service date to be driven by market need. Also 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.
January 2016
On January 5, 2016, the South Dakota PUC accepted Keystone XL’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 North American Free Trade Agreement (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. In June 2016, we filed a Request for Arbitration in a dispute against the U.S. Government pursuant to the Convention on Settlement of Investment Disputes between States and Nationals of Other States, the Rules of Procedure for the Institution of Conciliation and Arbitration Proceedings and Chapter 11 of NAFTA. This arbitration 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. On January 5, 2016, we also 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.
January 2017
On January 24, 2017, the U.S. President signed a Presidential Memorandum inviting TransCanada to refile an application for the U.S. Presidential Permit. On January 26, 2017, we filed a Presidential Permit application with the U.S. Department of State for the project. The pipeline will begin in Hardisty, Alberta, and extend south to Steele City, Nebraska. Given the passage of time since the November 6, 2015 denial of the Presidential Permit, we are updating our shipping contracts and some shippers may increase or decrease their volume commitments. We expect the project to retain sufficient commercial support for us to make a FID.
 
 

 
 
TransCanada Annual information form 2016
13


Date
Description of development
Energy East
 
 
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.
November 2015
Following consultation with stakeholders and shippers, we announced the intention to amend the Energy East pipeline application to remove a port in Québec and proceed with a single marine terminal in Saint John, New Brunswick.
December 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, contributed to a revised project capital cost estimate of $15.7 billion, excluding the transfer of Canadian Mainline natural gas assets.
March 2016
On March 1, 2016, the Province of Québec filed a court action seeking an injunction to compel the Energy East Pipeline to comply with the province’s environmental regulations. On March 30, 2016, the Québec Superior Court joined the injunction action led by the Province of Québec with the prior action led by Québec Environmental Law Centre / Centre québécois du droit de l’environnement (CQDE), which sought a declaration to compel the Energy East pipeline to submit to the mandatory provincial environmental review process. As a result of communication with the Ministère du Développement durable, Environnement et la Lutte contre les changements climatiques, on April 22, 2016, we filed a project review engaging an environmental assessment under the Environmental Quality Act (Québec) according to an agreed upon schedule for key steps in that process. This process was in addition to environmental assessment required under the NEB Act and the Canadian Environmental Assessment Act, 2012. The Attorney General for Québec agreed to suspend its litigation against TransCanada and Energy East and to withdraw it once the provincial environmental assessment process has been completed. The CQDE similarly agreed to suspend the action. These suspensions were in effect until early November 2016, but may have to be extended given the delay in the NEB process noted below. The first phase of Energy East public hearings for the voluntary Québec le Bureau d’audiences publiques sur l’environnement (BAPE) process was completed. The voluntary BAPE hearing process is intended to inform the Province of Québec in its participation in the federal process and provides project information to the public. A second phase, consisting of a series of public input sessions, has been suspended as it has been replaced with the environmental assessment as described above.
May 2016
We filed a consolidated application with the NEB for the Energy East pipeline. In June 2016, Energy East achieved a major milestone with the NEB’s announcement determining the Energy East pipeline application is sufficiently complete to initiate the formal regulatory review process. However, in August 2016, panel sessions were cancelled as three NEB panelists recused themselves from continuing to sit on the panel to review the project due to allegations of reasonable apprehension of bias. The Chair of the NEB and the Vice Chair, who is also a panel member, have recused themselves of any further duties related to the project. As a result, all hearings for the project were adjourned until further notice.
January 2017
On January 9, 2017, the NEB appointed three new permanent panel members to undertake the review of the Energy East and Eastern Mainline projects. On January 27, 2017, the new NEB panel members voided all decisions made by the previous hearing panel members and all decisions will be removed from the official hearing record. We are not required to refile the application and parties will not be required to reapply for intervener status. However, all other proceedings and associated deadlines are no longer applicable. It is expected the next step will be a determination of the application’s completeness and the issuance of a hearing order which triggers the 21-month time limit for the NEB to adjudicate the application. 
 
 

 
14   
TransCanada Annual information form 2016
 


Date
Description of development
White Spruce
 
 
December 2016
We finalized a long term transportation agreement to develop and construct the 20-inch diameter White Spruce pipeline, which will transport crude oil from a major oil sands plant in northeast Alberta, into the Grand Rapids pipeline system. The total capital cost for the project is approximately $200 million and it is expected to be in service in 2018 subject to regulatory approvals.
 
 
Northern Courier
 
 
Fourth Quarter 2016
Construction continued on the Northern Courier pipeline 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 to begin commercial operation in fourth quarter 2017.
 
 
Grand Rapids
 
 
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 .The joint venture will be incorporated into Grand Rapids and it will provide enhanced diluent supply alternatives to our shippers.
Fourth Quarter 2016
Construction continued on the Grand Rapids pipeline. We entered into a partnership with Brion Energy to develop Grand Rapids with each party owning 50 per cent of the pipeline project. Our partner has also entered into a long-term transportation service contract in support of the project. We will operate Grand Rapids once it is complete and we expect crude oil transportation to begin in the second half of 2017. Construction is also progressing on the 20-inch diameter diluent joint venture pipeline between Edmonton and Fort Saskatchewan, Alberta. The joint venture between Grand Rapids and Keyera Corp. will be incorporated into Grand Rapids and will provide enhanced diluent supply alternatives to our shippers. We anticipate the pipeline to be in service in late 2017.
 
Upland Pipeline
 
 
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 pipeline project proceeding.
January 2016
We are reviewing the Canadian federal government's interim measures for pipeline reviews and to assess their impact to Upland Pipeline.
 
 
Liquids Marketing
 
 
2015
We established a liquids marketing business to expand into other areas of the liquids business value chain. 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 the Other information - Risks and risk management section of the MD&A.
Further information about developments in the Liquids Pipelines business, including changes that we can expect will occur in the current financial year, can be found in the MD&A in the About our business – Our strategy, Liquids Pipelines – Financial results, Liquids Pipelines – Outlook, Liquids Pipelines – Understanding the Liquids Pipelines business and Liquids Pipelines – Significant events sections, which sections of the MD&A are incorporated by reference herein.

 
 
TransCanada Annual information form 2016
15


ENERGY
Date
Description of development
 
 
CANADIAN POWER
 
 
Alberta PPAs
 
 
June 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.
2016
On March 7, 2016, we issued notice to the Balancing Pool to terminate our Alberta PPAs. On July 22, 2016, we, along with the ASTC Power Partnership, issued a notice referring the matter to be resolved by binding arbitration pursuant to the dispute resolution provisions of the PPAs. On July 25, 2016, the Government of Alberta brought an application in the Court of Queen’s Bench to prevent the Balancing Pool from allowing termination of a PPA held by another party which contains identically worded termination provisions to our PPAs. The outcome of this court application could have affected resolution of the arbitration of the Sheerness, Sundance A and Sundance B PPAs. In December 2016, management engaged in settlement negotiations with the Government of Alberta and finalized terms of the settlement of all legal disputes related to the PPA terminations. The Government and the Balancing Pool agreed to our termination of the PPAs resulting in the transfer of all our obligations under the PPAs to the Balancing Pool. Upon final settlement of the PPA terminations, we transferred to the Balancing Pool a package of environmental credits held to offset the PPA emissions costs and recorded a non-cash charge of $92 million before tax ($68 million after tax) related to the carrying value of our environmental credits. In first quarter 2016, as a result of our decision to terminate the PPAs, we recorded a non-cash impairment charge of $240 million before tax ($176 million after tax) comprised of $211 million before tax ($155 million after tax) related to the carrying value of our Sundance A and Sheerness PPAs and $29 million before tax ($21 million after tax) on our equity
investment in the ASTC Power Partnership which previously held the Sundance B PPA.
 
 
Ontario Cap and Trade
 
 
May 2016
Legislation enabling Ontario’s cap and trade program was signed into law with the new regulation taking effect July 1, 2016. This regulation sets a limit on annual province-wide greenhouse gas emissions beginning in January 2017 and introduces a market to administer the purchase and trading of emissions allowances. The regulation places the compliance obligation for emissions from our natural gas fired power facilities on local gas distributors, with the distributors then flowing the associated costs to the facilities themselves. The IESO has proposed contract amendments for contract holders to address costs and other issues associated with this change in law. We continue to work with the IESO to finalize these amendments. We do not expect a significant overall impact to our Energy business as a result of this new regulation.
 
 
Napanee
 
 
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. Production from the facility is fully contracted with the IESO.
First Quarter 2016
Construction continues and we expect to invest approximately $1.1 billion in the Napanee facility during construction and commercial operations are expected to begin in 2018.
 
 
Bécancour
 
 
May 2014
We received final approval from the Régie de l’énergie for the December 2013 amendment to the original suspension agreement with Hydro-Québec Distribution (HQ). Under the amendment, HQ continued to have the option (subject to certain conditions) to further extend the suspension of all electricity generation from the Bécancour power plant past 2017. The amendment also includes revised provisions intended to reduce HQ’s payments to us for Bécancour's natural gas transportation costs during the suspension period, although we retain our ability to recover our full capacity costs under the Electricity Supply Contract with HQ while the facility is suspended. In addition, HQ exercised its option in the amended suspension agreement to extend suspension of all electricity generation to the end of 2017, and requested further suspension of generation to the end of 2018. In June 2015, HQ had requested further suspension of generation to the end of 2019. In June 2016, HQ requested further suspension of generation to the end of 2020.
August 2015
We executed an agreement with HQ allowing HQ to dispatch up to 570 MW of peak winter capacity from our Bécancour facility for a term of 20 years commencing in December 2016.
November 2016
HQ released a new ten year supply plan indicating additional peak winter capacity from Bécancour is not required at this time. Prior to this development, the regulator in Québec, Régie de l'énergie, reversed its initial decision to approve this agreement. Management does not expect further developments at Bécancour until November 2019 when the next 10 year supply plan is filed.

 
16   
TransCanada Annual information form 2016
 


Date
Description of development
 
 
Bruce Power
 
 
March 2014
Cameco Corporation sold its 31.6 per cent limited partnership interest in Bruce B to BPC Generation Infrastructure Trust.
Fourth Quarter 2014
New Canadian federal legislation was passed in 2015 respecting the determination of liability and compensation for a nuclear incident in Canada resulting in personal injuries and damages. In 2016 the act was proclaimed to come into force by cabinet and the provisions are effective as of January 1, 2017. This legislation will replace existing legislation which currently provides that the licensed operator of a nuclear facility has absolute and exclusive liability and limits the liability to a maximum of $75 million. The new law is fundamentally consistent with the existing regime although the maximum liability will increase to $650 million and increase in increments over three years to a maximum of $1 billion. The operator will also be required to maintain financial assurances such as insurance in the amount of the maximum liability. Our indirect subsidiary owns 50 per cent of the common shares of Bruce Power Inc., the licensed operator of Bruce Power, and as such Bruce Power Inc. is subject to this liability in the event of an incident as well as the legislation’s other requirements.
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 estimated 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 estimated 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 January 2016, Bruce Power receives a uniform price of $65.73 per MWh for all units, which includes certain flow-through items such as fuel and lease expense recovery. Over time, the uniform price will be subject to adjustments for the return of and on capital invested at Bruce Power 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. 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 the Ontario Municipal Employees Retirement System. Subsequent to this acquisition, Bruce A and Bruce B were merged to form a single partnership 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. We now hold a 48.5 per cent interest in this newly merged partnership structure.
Second Quarter 2016
Bruce Power issued bonds and borrowed under its bank credit facility as part of a financing program to fund its capital program and make distributions to its partners. Distributions received by us from Bruce Power in second quarter 2016 included $725 million from this financing program.
February 2017
Bruce Power issued additional bonds under its financing program and distributed $362 million to TransCanada.
 
 
Cancarb Limited and Cancarb Waste Heat Facility
 
 
January 2014
We announced we had reached an agreement for the sale of Cancarb Limited, our thermal carbon black facility, and its related power generation facility.
April 2014
The sale of Cancarb Limited and its related power generation facility closed for gross proceeds of $190 million. We recognized a gain of $99 million, net of tax, in second quarter 2014.
 
 
Ontario Solar
 
 
September 2014
We completed the acquisition of three solar facilities for $181 million as per our December 2011 agreement, pursuant to which we agreed to buy Ontario solar generation facilities with combined capacity of 86 MW from Canadian Solar Solutions Inc. for approximately $500 million.
December 2014
We acquired an additional solar facility for $60 million. Our total investment in the eight solar facilities we have purchased is $457 million. All power produced by the solar facilities is sold under 20-year feed-in tariff contracts with the IESO.
 
U.S. Power
 
Monetization of U.S. Northeast power business
 
 
November 2016
We announced the sale of Ravenswood, Ironwood, Ocean State Power and Kibby Wind to Helix Generation, LLC, an affiliate of LS Power Equity Advisors for US$2.2 billion and the sale of TC Hydro to Great River Hydro, LLC, an affiliate of ArcLight Capital Partners, LLC for US$1.065 billion. These two sale transactions are expected to close in the first half of 2017 subject to certain regulatory and other approvals and will include closing adjustments. These sales are expected to result in an approximate net loss of $1.2 billion before tax ($1.1 billion after tax) which is comprised of a $1,085 million goodwill impairment charge ($656 million after tax), a net loss of $829 million ($863 million after tax) on the sale of the thermal and wind package and an approximate gain of $710 million ($440 million after tax) on sale of the hydro assets to be recorded upon the close of that transaction. A process to monetize our marketing business, TCPM, is underway.

 
 
TransCanada Annual information form 2016
17


Date
Description of development
 
 
Ravenswood
 
 
May 2015
The Ravenswood Generating Station returned to service after the September 2014 unplanned outage which resulted from a problem with the generator associated with the high pressure turbine. Insurance recoveries, net of deductibles, for this event have been received and are being recognized in capacity revenues to offset amounts lost during the periods impacted by the lower forced outage rate. As a result of these insurance recoveries, the Unit 30 unplanned outage has not had a significant impact on our earnings, although the recording of earnings has not coincided exactly with lost revenues due to timing of the insurance proceeds. In addition, insurance recoveries related to an unplanned outage at the Ravenswood facility that occurred in 2008 were received in June 2016 and a portion of the proceeds were recognized in power revenue. Refer to the Monetization of U.S. Northeast power business section above.
 
 
Ironwood
 
 
February 2016

We acquired the 778 MW Ironwood natural gas fired, combined cycle power plant located in Lebanon, Pennsylvania for US$653 million in cash after post-acquisition adjustments. The Ironwood power plant delivers energy into the PJM Interconnection area power market. Refer to the Monetization of U.S. Northeast power business section above.
Further information about developments in the Energy business, including changes that we expect will occur in the current financial year, can be found in the MD&A in the About our business – Our strategy, Energy – Financial results, Energy – Outlook, Energy – Understanding the Energy business and Energy – Significant events sections, which sections of the MD&A are incorporated by reference herein.
Business of TransCanada
We are a leading North American energy infrastructure company focused on Natural Gas Pipelines, Liquids Pipelines and Energy. Refer to the About our business – Three core businesses – Total revenues section of the MD&A for our revenues from operations by segment, for the years ended December 31, 2016 and 2015, which section of the MD&A is incorporated by reference herein.
The following is a description of each of TransCanada's three core businesses.
NATURAL GAS PIPELINES     
Our natural gas pipeline network transports natural gas from supply basins to local distribution companies, power generation facilities, interconnecting pipelines and other businesses across Canada, the U.S. and Mexico. Our Natural Gas Pipelines business is split into three operating segments representing its geographic diversity: Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines.
A description of the natural gas pipelines and regulated natural gas storage assets we operate in addition to further information about our pipeline holdings, developments and opportunities, significant regulatory developments and competitive position which relate to our Natural Gas Pipelines business can be found in the Natural Gas Pipelines business, Canadian Natural Gas Pipelines, U.S. Natural Gas Pipelines and Mexico Natural Gas Pipelines sections of the MD&A, which sections of the MD&A are incorporated by reference herein.
LIQUIDS PIPELINES
Our existing liquids pipeline infrastructure connects Alberta 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 access to U.S. markets.
A description of pipelines and properties we operate, in addition to further information about our pipeline holdings, developments and opportunities, significant regulatory developments and competitive position which relate to our Liquids Pipelines business can be found in the MD&A in the Liquids Pipelines section, which section of the MD&A is incorporated by reference herein.

 
18   
TransCanada Annual information form 2016
 


REGULATION OF NATURAL GAS PIPELINES AND LIQUIDS PIPELINES
Canada
Natural Gas Pipelines
The Canadian Mainline, NGTL System and Foothills System (collectively, the Systems) are regulated by the NEB under the National Energy Board Act (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for these Canadian regulated natural gas transmission systems.
The NEB generally sets tolls that provide TransCanada the opportunity to recover costs of transporting natural gas, including the return of capital (depreciation) and return on the average investment base for each of the Systems. 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 service and has the flexibility to price its shorter term and discretionary services in order to maximize its revenue. Further information relating to the decision from the NEB regarding the Canadian Restructuring Proposal as well as the LDC Settlement can be found in the General developments of the business - Natural Gas Pipelines - Developments in the Canadian Natural Gas Pipelines segment - Canadian Mainline Settlement above. In addition, the NEB approved the NGTL revenue requirement settlement application that was filed in December 2015, subject to certain reporting requirements that were subsequently met and approved by the NEB.
New facilities on or associated with the Systems are approved by the NEB before construction begins and the NEB regulates the operations of each of the Systems. Net earnings of the Systems may be affected by changes in investment base, the allowed ROE, and any incentive earnings.
West Coast LNG Natural Gas Pipeline Projects
The Coastal GasLink and PRGT natural gas pipeline projects are being proposed and developed primarily under the regulatory regime administered by the OGC and the EAO. The OGC is responsible for overseeing oil and gas operations in B.C., including exploration, development, pipeline transportation and reclamation. The EAO is an agency that manages the review of proposed major projects in B.C., as required by the B.C. Environmental Assessment Act.
Liquids Pipelines
The NEB regulates the terms and conditions of service, including rates, construction and operation of the Canadian portion of the Keystone Pipeline System. The rates for transportation service on the Keystone Pipeline System are calculated in accordance with a methodology agreed to in transportation service agreements between Keystone and its shippers, and approved by the NEB.
Liquids Pipelines Projects
The Northern Courier Pipeline and Grand Rapids Pipeline projects are currently under construction and the White Spruce pipeline is under development, all of which are primarily under the regulatory regime administered by the AER. The AER administers approvals required to construct and operate the pipelines and associated facilities in accordance with Directive 56, approvals to obtain land access under the Public Land Act, and environmental approvals under the Environmental and Protection Enhancement Act.
Energy East Pipeline is being developed under the regulatory regime administered by the NEB.

 
 
TransCanada Annual information form 2016
19


United States
Natural Gas Pipelines
TransCanada is subject to regulation by various federal, state and local governmental agencies, including those specifically described below.
The Company's wholly owned and partially owned U.S. pipelines are considered natural gas companies operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and are subject to the jurisdiction of the FERC. The Natural Gas Act of 1938 grants the FERC authority over the construction, acquisition and operation of pipelines and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement or abandonment of service using such facilities. The FERC also has authority to regulate rates and charges for transportation and storage of natural gas in interstate commerce.
TransCanada holds certificates of public convenience and necessity issued by FERC, authorizing them to operate the pipelines, facilities and properties now in operation and to transport and store natural gas in interstate commerce. Our regulated natural gas storage business also has facilities that are regulated by FERC. The Company is also subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of natural gas pipelines.
Liquids Pipelines
The FERC regulates the terms and conditions of service, including transportation rates, of interstate liquids pipelines, including the U.S. portion of the Keystone Pipeline System and Marketlink. The siting and construction of pipeline facilities are regulated by the specific state regulator in which the pipeline facilities are located. Pipeline safety is regulated by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration. Liquids pipelines that cross the international border between Canada and the United States, such as the proposed Upland pipeline, will require a Presidential Permit from the U.S. DOS.
Mexico
Natural Gas Pipelines
TransCanada’s pipelines in Mexico are regulated by the Comisión Reguladora de Energía or Energy Regulatory Commission who approve construction of new pipeline facilities and ongoing operations of the infrastructure. Our Mexican pipelines have approved tariffs, services and related rates, however, the contracts underpinning the construction and operation of the facilities are long-term negotiated fixed rate contracts. These rates are only subject to change under specific circumstances such as certain types of force majeure events or changes in law.
ENERGY
Our Energy business is made up of three groups:
Canadian Power
Natural Gas Storage (Canadian, non-regulated)
U.S. Power (monetization expected to close in the first half of 2017).
Further information about Energy assets we operate, power supply that we own or have the rights to, power generation capacity we own or are developing and Energy assets currently under construction, along with our Energy holdings and significant developments, and opportunities in relation to our Energy business, can be found in the MD&A in the Energy section, which section of the MD&A is incorporated by reference herein.

 
20   
TransCanada Annual information form 2016
 


General
EMPLOYEES
At Year End, TransCanada's principal operating subsidiary, TCPL, had 7,165 employees, substantially all of whom were employed in Canada and the U.S., as set forth in the following table.
Calgary (includes U.S. employees working in Canada)
2,570

Western Canada (excluding Calgary)
581

Eastern Canada
300

Houston (includes Canadian employees working in the U.S.)
712

U.S. Midwest
747

U.S. Northeast
653

U.S. Southeast/Gulf Coast (excluding Houston)
1,313

U.S. West Coast
79

Mexico and South America
210

Total
7,165

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 had undertaken this initiative to reduce overall costs and maximize the effectiveness and efficiency of our existing
operations. For more information about our corporate restructuring and business transformation, refer to the Corporate – Corporate restructuring and business transformation section of the MD&A, which section of the MD&A is incorporated by reference herein.
ACQUISITION OF COLUMBIA PIPELINE GROUP, INC.
On July 1, 2016, we acquired 100 per cent ownership of Columbia for a purchase price of US$10.3 billion in cash. The acquisition was initially financed through proceeds of $4.4 billion from the sale of subscription receipts, draws on acquisition bridge facilities in the aggregate amount of US$6.9 billion and existing cash on hand. The sale of the subscription receipts was completed on April 1, 2016 through a public offering and, following the closing of the acquisition, the subscription receipts were exchanged into 96.6 million TransCanada common shares. For more information about the acquisition of Columbia, refer to the About our business – Acquisition of Columbia Pipeline Group, Inc. section of the MD&A, which section of the MD&A is incorporated by reference herein.

 
 
TransCanada Annual information form 2016
21


HEALTH, SAFETY AND ENVIRONMENTAL PROTECTION AND SOCIAL POLICIES
The Health, Safety and Environment (HSE) committee of TransCanada’s Board of Directors (the Board) oversees operational risk, people and process safety, security of personnel and environmental risks, and monitors compliance with our HSE corporate policy through regular reporting from management. We have a management system that establishes a framework for managing HSE issues that is used to capture, organize, document, monitor and improve our related policies, programs and procedures.
Our management system for HSE is modeled after international standards, conforms to external industry consensus standards and voluntary programs, and complies with applicable legislative and regulatory requirements and various other internal management systems. It follows a continuous improvement cycle organized into four key areas:
Planning: risk and regulatory assessment, objectives and targets, and structure and responsibility
Implementing: development and implementation of programs, plans, procedures and practices aimed at operational risk management
Reporting: document and records management, communication and reporting, and
Action: ongoing audit and review of HSE performance.
The committee reviews HSE performance and operational risk management. It receives detailed reports on:
overall HSE corporate governance
operational performance and preventive maintenance metrics
asset integrity programs
emergency preparedness, incident response and evaluation
people and process safety performance metrics, and
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 flowing from internal and third party audits. Information about the financial and operational effects of environmental protection requirements on the capital expenditures, profit or loss and competitive position of TransCanada can be found in the MD&A in the Other information – Risks and risk management – Health, safety and environment section, which section of the MD&A is incorporated by reference herein. Generally, each year the committee or the committee Chair tours one of our existing assets or projects under development as part of its responsibility to monitor and review our HSE practices. Additionally, the Board and the committee have a joint site visit annually. In 2016, the committee held a special session devoted to operational safety.
Environmental policies
TransCanada’s facilities are subject to federal, state, provincial, and local environmental statutes and regulations governing environmental protection, including, but not limited to, air emissions and GHG emissions, water quality, wastewater discharges and waste management. Such laws and regulations generally require facilities to obtain or comply with a wide variety of environmental registrations, licences, permits and other approvals and requirements. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements and/or the issuance of orders respecting future operations. We have implemented audit and inspection programs designed to ensure our facilities remain in compliance with environmental requirements.
Safety and asset integrity
As one of TransCanada's corporate values, safety is an integral part of the way our employees work. Each year we develop goals predicated on achieving year over year sustainable improvement in our safety performance, and meeting or exceeding industry benchmarks.
The safety and integrity of our existing and newly developed infrastructure is a top priority. All new 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.
TransCanada annually conducts emergency response exercises to practice effective coordination between the Company, local emergency responders, regulatory agencies and government officials in the event of an emergency. TransCanada uses the Incident Command System which supports a unified approach to emergency response with these community members. TransCanada also provides annual training to all field staff in the form of table top exercises, online and vendor lead training.

 
22   
TransCanada Annual information form 2016
 


Social Policies
TransCanada has a number of policies, guiding principles and practices in place to help manage Indigenous and stakeholder relations. We have adopted a Code of Business Ethics (Code) which applies to all employees, officers and directors as well as contract workers of TransCanada and its wholly-owned subsidiaries and operated entities in countries where we conduct business. All employees (including executive officers) and directors must certify their compliance with the Code.
Our approach to Indigenous and stakeholder engagement is based on building relationships, mutual respect and trust while recognizing the unique values, needs and interests of each community. Our Stakeholder Engagement Commitment Statement provides the structure to guide our teams’ behavior and actions, so they understand their responsibility and extend respect, courtesy and the opportunity to respond to every stakeholder.
TransCanada’s Aboriginal Relations and Native American Relations Policies are guided by principles of trust, respect and responsibility. We work together with Indigenous communities to find mutually acceptable solutions and benefits. These Policies recognize the diversity and uniqueness of each Indigenous community, the importance of the land, and the imperative of building relationships based on mutual respect and trust.
TransCanada also has an Avoiding Bribery and Corruption Program which includes an Avoiding Bribery and Corruption Policy, annual online training provided to all personnel, face to face training provided to personnel in higher risk areas of our business, a supplier and contractor due diligence review process, and auditing of certain types of transactions.
We strive for continuous improvement in how we navigate the interconnections and complexity of environmental, social and economic issues related to our business. These issues are of great importance to our stakeholders and Indigenous communities, and have an impact on our ability to build and operate energy infrastructure.
Risk factors
A discussion of our risk factors can be found in the MD&A in the Natural Gas Pipelines business – Natural Gas Pipelines – Business risks, Liquids Pipelines – Business risks, Energy – Business risks and Other information – Risks and risk management sections, which sections of the MD&A are incorporated by reference into this AIF.

 
 
TransCanada Annual information form 2016
23


Dividends
Our Board has not adopted a formal dividend policy. The Board reviews the financial performance of TransCanada quarterly and makes a determination of the appropriate level of dividends to be declared in the following quarter. Currently, our payment of dividends is primarily funded from dividends TransCanada receives as the sole common shareholder of TCPL. Provisions of various trust indentures and credit arrangements to which TCPL is a party restrict TCPL's ability to declare and pay dividends to TransCanada under certain circumstances and, if such restrictions apply, they may, in turn, have an impact on our ability to declare and pay dividends. Pursuant to the terms of the trust notes issued by TransCanada Trust (a financing trust subsidiary wholly owned by TCPL) and related agreements, in certain circumstances including where holders of the trust notes receive deferral preferred shares of TCPL in lieu of cash interest payments and where exchange preferred shares are issued to holders of the trust notes as a result of certain bankruptcy related events, 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 such exchange or deferral preferred shares are redeemed by TCPL. Further information about such trust notes can be found in the Financial condition – Junior subordinated notes issued section of the MD&A. In the opinion of TransCanada's management, such provisions do not currently restrict or alter TransCanada's ability to declare or pay dividends.
Dividends on our preferred shares are payable quarterly, as and when declared by the Board. The dividends declared on our common and preferred shares during the past three completed financial years, and the increase to the quarterly dividend on our outstanding common shares per common share for the quarter ending March 31, 2017, are set out in the MD&A under the heading About our business – 2016 financial highlights – Dividends, which section of the MD&A is incorporated by reference herein.
Description of capital structure
SHARE CAPITAL
TransCanada’s authorized share capital consists of an unlimited number of common shares, of which 863,759,075 were issued and outstanding at Year End, and an unlimited number of first preferred shares and second preferred shares, issuable in series.

The number of preferred shares issued and outstanding as at Year End, or as otherwise indicated, is set out in the MD&A under the About our business – Three Core Businesses heading, which section of the MD&A is incorporated by reference herein. The following is a description of the material characteristics of each of these classes of shares.
Common shares
The common shares entitle the holders thereof to one vote per share at all meetings of shareholders, except meetings at which only holders of another specified class of shares are entitled to vote, and, subject to the rights, privileges, restrictions and conditions attaching to the first preferred shares and the second preferred shares, whether as a class or a series, and to any other class or series of shares of TransCanada which rank prior to the common shares, entitle the holders thereof to receive (i) dividends if, as and when declared by the Board out of the assets of TransCanada properly applicable to the payment of the dividends in such amount and payable at such times and at such place or places as the Board may from time to time determine, and (ii) the remaining property of TransCanada upon a dissolution.
We have a shareholder rights plan that is designed to ensure, to the extent possible, that all shareholders of TransCanada are treated fairly in connection with any take-over bid for the Company. The plan creates a right attaching to each common share outstanding and to each common share subsequently issued. Each right becomes exercisable ten trading days after a person has acquired (an acquiring person), or commences a take-over bid to acquire, 20 per cent or more of the common shares, other than by an acquisition pursuant to a take-over bid permitted under the terms of the plan (a permitted bid). Prior to a flip-in event (as described below), each right permits registered holders to purchase from the Company common shares of TransCanada at an exercise price equal to three times the market price of such shares, subject to adjustments and anti-dilution provisions (the exercise price). The beneficial acquisition by any person of 20 per cent or more of the common shares, other than by way of permitted bid, is referred to as a flip-in event. Ten trading days after a flip-in event, each right will permit registered holders other than an acquiring person to receive, upon payment of the exercise price, the number of common shares with an aggregate market price equal to twice the exercise price.
TransCanada has a dividend reinvestment and share purchase plan (DRP) under which eligible holders of common and preferred shares of TransCanada can reinvest their dividends and make optional cash payments to obtain additional TransCanada common shares. Commencing with dividends declared on July 27, 2016, common shares will be issued from treasury at a discount of two per cent rather than purchased on the open markets to satisfy participation in the DRP. Participants may also make additional cash payments

 
24   
TransCanada Annual information form 2016
 


of up to $10,000 per quarter to purchase additional common shares, which optional purchases are not eligible for any discount on the price of common shares. Participants are not responsible for payment of brokerage commissions or other transaction expenses for purchases made pursuant to the DRP.
TransCanada also has a stock based compensation plan that allows some employees to purchase common shares of TransCanada. Option exercise prices are equal to the closing price on the Toronto Stock Exchange (TSX) on the last trading day immediately preceding the grant date. Options granted under the plan are generally fully exercisable after three years and expire seven years after the date of grant.
First preferred shares
Subject to certain limitations, the Board may, from time to time, issue first preferred shares in one or more series and determine for any such series, its designation, number of shares and respective rights, privileges, restrictions and conditions. The first preferred shares as a class have, among others, the provisions described below.
The first preferred shares of each series rank on a parity with the first preferred shares of every other series, and are entitled to preference over the common shares, the second preferred shares and any other shares ranking junior to the first preferred shares with respect to the payment of dividends, the repayment of capital and the distribution of assets of TransCanada in the event of its liquidation, dissolution or winding up.
Except as provided by the CBCA, the holders of the first preferred shares will not have any voting rights nor will they be entitled to receive notice of or to attend shareholders' meetings. The holders of any particular series of first preferred shares will, if the directors so determine prior to the issuance of such series, be entitled to such voting rights as may be determined by the directors if TransCanada fails to pay dividends on that series of preferred shares for any period as may be so determined by the directors.
The provisions attaching to the first preferred shares as a class may be modified, amended or varied only with the approval of the holders of the first preferred shares as a class. Any such approval to be given by the holders of the first preferred shares may be given by the affirmative vote of the holders of not less than sixty-six and two thirds per cent of the first preferred shares represented and voted at a meeting or adjourned meeting of such holders.
The holders of Series 1, 3, 5, 7, 9, 11, 13 and 15 preferred shares will be entitled to receive quarterly fixed rate cumulative preferential cash dividends, as and when declared by the Board, to be reset periodically on established dates to an annualized rate equal to the sum of the then five-year Government of Canada bond yield, calculated at the start of the applicable five-year period, and a spread as set forth in the table below (subject, in the case of the Series 13 and 15 preferred shares, to a fixed minimum reset rate) and have the right to convert their shares into cumulative redeemable Series 2, 4, 6, 8, 10, 12, 14 and 16 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series 1, 3, 5, 7, 9, 11, 13 and 15 preferred shares are redeemable by TransCanada in whole or in part on such redemption dates as set forth in the table below, by the payment of an amount in cash for each share to be redeemed equal to $25.00 plus all accrued and unpaid dividends thereon.
The holders of Series 2, 4, 6, 8, 10, 12, 14 and 16 preferred shares will be entitled to receive quarterly floating rate cumulative preferential cash dividends, as and when declared by the Board, at an annualized rate equal to the sum of the then 90-day Government of Canada treasury bill rate, recalculated quarterly, and a spread as set forth in the table below and have the right to convert their shares into Series 1, 3, 5, 7, 9, 11, 13 and 15 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series 2, 4, 6, 8, 10, 12, 14 and 16 preferred shares are redeemable by TransCanada in whole or in part after their respective initial redemption date as set forth in the table below, by the payment of an amount in cash for each share to be redeemed equal to (i) $25.00 in the case of redemptions on such redemption dates as set out in the table below, or (ii) $25.50 in the case of redemptions on any other date, in each case plus all accrued and unpaid dividends thereon.
In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15 and 16 preferred shares shall be entitled to receive $25.00 per preferred share plus all accrued and unpaid dividends thereon in preference over the common shares or any other shares ranking junior to the first preferred shares.

 
 
TransCanada Annual information form 2016
25


Series of first preferred shares
Initial redemption date
Redemption/conversion dates
Spread
(%)

Series 1 preferred shares
December 31, 2014
December 31, 2019 and every fifth year thereafter
1.92

Series 2 preferred shares
December 31, 2019 and every fifth year thereafter
1.92

Series 3 preferred shares
June 30, 2015
June 30, 2020 and every fifth year thereafter
1.28

Series 4 preferred shares
June 30, 2020 and every fifth year thereafter
1.28

Series 5 preferred shares
January 30, 2016

January 30, 2016 and every fifth year thereafter
1.54

Series 6 preferred shares
January 30, 2021 and every fifth year thereafter
1.54

Series 7 preferred shares
April 30, 2019
April 30, 2019 and every fifth year thereafter
2.38

Series 8 preferred shares
April 30, 2024 and every fifth year thereafter
2.38

Series 9 preferred shares
October 30, 2019
October 30, 2019 and every fifth year thereafter
2.35

Series 10 preferred shares
October 30, 2024 and every fifth year thereafter
2.35

Series 11 preferred shares
November 30, 2020

November 30, 2020 and every fifth year thereafter
2.96

Series 12 preferred shares
November 30, 2025 and every fifth year thereafter
2.96

Series 13 preferred shares
May 31, 2021

May 31, 2021 and every fifth year thereafter
4.69

Series 14 preferred shares
May 31, 2026 and every fifth year thereafter
4.69

Series 15 preferred shares
May 31, 2022

May 31, 2022 and every fifth year thereafter
3.85

Series 16 Preferred shares
May 31, 2027 and every fifth year thereafter
3.85

Except as provided by the CBCA, the respective holders of the first preferred shares of each outstanding series are not entitled to receive notice of, attend at, or vote at any meeting of shareholders unless and until TransCanada shall have failed to pay eight quarterly dividends on such series of preferred shares, whether or not consecutive, in which case the holders of the first preferred shares of such series shall have the right to receive notice of and to attend each meeting of shareholders at which directors are to be elected and which take place more than 60 days after the date on which the failure first occurs, and to one vote with respect to resolutions to elect directors for each of the first preferred share of such series, until all arrears of dividends have been paid. Subject to the CBCA, the series provisions attaching to the first preferred shares may be amended with the written approval of all the holders of such series of shares outstanding or by at least two thirds of the votes cast at a meeting of the holders of such shares duly called for the purpose and at which a quorum is present.
Second preferred shares
The rights, privileges, restrictions and conditions attaching to the second preferred shares are substantially identical to those attaching to the first preferred shares, except that the second preferred shares are junior to the first preferred shares with respect to the payment of dividends, repayment of capital and the distribution of assets of TransCanada in the event of a liquidation, dissolution or winding up of TransCanada.

 
26   
TransCanada Annual information form 2016
 


Credit ratings
Although TransCanada Corporation has not issued debt to the public, it has been assigned credit ratings by Moody's Investors Service, Inc. (Moody's) and S&P Global Ratings (S&P) and its outstanding preferred shares have also been assigned credit ratings by Moody’s, S&P and DBRS Limited (DBRS). Moody's has assigned an issuer rating of Baa1 with a stable outlook and S&P has assigned a long-term corporate credit rating of A- with a negative outlook. TransCanada Corporation does not presently intend to issue debt securities to the public in its own name and any future debt financing requirements are expected to continue to be funded primarily through its subsidiary, TCPL, and TransCanada Trust, a wholly owned financing trust subsidiary of TCPL. The following table sets out the current credit ratings assigned to those outstanding classes of securities of the Company, TCPL, TransCanada Trust and various group entities which have been rated by DBRS, Moody's and S&P:
 
 
DBRS
Moody's
S&P
 
TCPL - Senior unsecured debt
     Debentures
     Medium-term notes
A (low)
A (low)
A3
A3
A-
A-
 
 
TCPL - Junior subordinated notes
BBB
Baa1
BBB
 
TransCanada Trust - Subordinated trust notes
Not rated
Baa2
BBB
 
TransCanada Corporation - Preferred shares
Pfd-2 (low)
Baa2
P-2
 
Commercial paper (TCPL and TCPL guaranteed)
R-1 (low)
P-2
A-2
 
Trend/rating outlook
Under review
with developing
implications
Stable
Negative
Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.
Each of the Company, TCPL, TransCanada Trust and various group entities paid fees to each of DBRS, Moody’s and S&P for the credit ratings rendered in respect of their outstanding classes of securities noted above. In addition to annual monitoring fees for the Company and TCPL and their rated securities, additional payments were made to DBRS, Moody’s and S&P in respect of other services provided in connection with the acquisition of Columbia.
The information concerning our credit ratings relates to our financing costs, liquidity and operations. The availability of our funding options may be affected by certain factors, including the global capital market environment and outlook as well as our financial performance. Our access to capital markets at competitive rates is dependent on our credit rating and rating outlook, as determined by credit rating agencies such as DBRS, Moody's and S&P, and if our ratings were downgraded TransCanada's financing costs and future debt issuances could be unfavorably impacted. A description of the rating agencies' credit ratings listed in the table above is set out below.

 
 
TransCanada Annual information form 2016
27


DBRS
DBRS has different rating scales for short- and long-term debt and preferred shares. High or low grades are used to indicate the relative standing within all rating categories other than AAA and D and other than in respect of DBRS’ ratings of commercial paper and short-term debt, which utilize high, middle and low subcategories for its R-1 and R-2 rating categories. In respect of long-term debt and preferred share ratings, the absence of either a high or low designation indicates the rating is in the middle of the category. The R-1 (low) rating assigned to TCPL's and TCPL guaranteed short-term debt is in the third highest of 10 rating categories and indicates good credit quality. The capacity for payment of short-term financial obligations as they fall due is substantial. The overall strength is not as favourable as higher rating categories. Short-term debt rated R-1 (low) may be vulnerable to future events, but qualifying negative factors are considered manageable. The A (low) rating assigned to TCPL's senior unsecured debt is in the third highest of 10 categories for long-term debt. Long-term debt rated A is good credit quality. The capacity for the payment of financial obligations is substantial, but of lesser credit quality than that of AA rated securities. Long-term debt rated A may be vulnerable to future events but qualifying negative factors are considered manageable. The BBB rating assigned to junior subordinated notes is in the fourth highest of the 10 categories for long-term debt. Long-term debt rated BBB is of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but long-term debt rated BBB may be vulnerable to future events. The Pfd-2 (low) rating assigned to TransCanada's preferred shares is in the second highest of six rating categories for preferred shares. Preferred shares rated Pfd-2 are of satisfactory credit quality. Protection of dividends and principal is still substantial; however, earnings, the balance sheet and coverage ratios are not as strong as Pfd-1 rated companies. In general, Pfd-2 ratings correspond with companies whose long-term debt is rated in the A category.
MOODY’S
Moody's has different rating scales for short- and long-term obligations. Numerical modifiers 1, 2 and 3 are appended to each rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and a modifier 3 indicates a ranking in the lower end of that generic rating category. The A3 rating assigned to TCPL's senior unsecured debt is in the third highest of nine rating categories for long-term obligations. Obligations rated A are judged to be upper medium-grade and are subject to low credit risk. The P-2 rating assigned to TCPL's and TCPL guaranteed U.S. commercial paper programs is the second highest of four rating categories for short-term debt issuers. Issuers rated P-2 have a strong ability to repay short-term debt obligations. The Baa1 and Baa2 ratings assigned to TCPL's junior subordinated notes and to both TransCanada's preferred shares and the TransCanada Trust subordinated trust notes, respectively, are in the fourth highest of nine rating categories for long-term obligations, with the junior subordinated notes ranking higher within the Baa rating category with a modifier of 1 as opposed to the modifier of 2 on the subordinated trust notes and preferred shares. Obligations rated Baa are judged to be medium-grade and are subject to moderate credit risk and, as such, may possess certain speculative characteristics.
S&P
S&P has different rating scales for short- and long-term obligations. Ratings from AA through CCC may be modified by the addition of a plus (+) or minus (-) sign to show the relative standing within a particular rating category. The A- rating assigned to TCPL's senior unsecured debt is in the third highest of 10 rating categories for long-term obligations. An A rating indicates the obligor's capacity to meet its financial commitment is strong; however, the obligation is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rated categories. TCPL's and TCPL guaranteed U.S. commercial paper programs are each rated A-2 which is the second highest of eight rating categories for short-term debt issuers. Short-term debt issuers rated A-2 have satisfactory capacity to meet their financial commitments, however they are somewhat more susceptible to adverse effects of changes in circumstances and economic conditions than obligors in the highest rating category. The BBB rating assigned to TCPL’s junior subordinated notes and to the TransCanada Trust subordinated trust notes is in the fourth highest of 10 rating categories for long-term debt obligations and the P-2 rating assigned to TransCanada’s preferred shares is the second highest of eight rating categories for Canadian preferred shares. The BBB and P-2 ratings assigned to TCPL's junior subordinated notes, the TransCanada Trust subordinated trust notes and TransCanada's preferred shares exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitment on the obligation.

 
28   
TransCanada Annual information form 2016
 


Market for securities
TransCanada's common shares are listed on the TSX and the New York Stock Exchange (NYSE) under the symbol TRP. The following table sets out our preferred shares listed on the TSX.
Type
Issue Date
Stock Symbol
Series 1 preferred shares
September 30, 2009
TRP.PR.A
Series 2 preferred shares
December 31, 2014
TRP.PR.F

Series 3 preferred shares
March 11, 2010
TRP.PR.B
Series 4 preferred shares
June 30, 2015
TRP.PR.H
Series 5 preferred shares
June 29, 2010
TRP.PR.C
Series 6 preferred shares
February 1, 2016
TRP.PR.I
Series 7 preferred shares
March 4, 2013
TRP.PR.D
Series 9 preferred shares
January 20, 2014
TRP.PR.E
Series 11 preferred shares
March 2, 2015
TRP.PR.G
Series 13 preferred shares
April 20, 2016
TRP.PR.J
Series 15 preferred shares
November 21, 2016
TRP.PR.K
The following tables set out the reported monthly high, low, and month end closing trading prices and monthly trading volumes of the common shares of TransCanada on the TSX and the NYSE, and the respective Series 1, 2, 3, 4, 5, 6, 7, 9, 11, 13 and 15 preferred shares on the TSX, for the periods indicated:
COMMON SHARES
Month
TSX (TRP)
 
NYSE (TRP)
High
($)

Low
($)

Close
($)

Volume traded

 
High
(US$)
Low
(US$)
Close
(US$)
Volume traded
December 2016
$62.84

$58.12

$60.54

35,638,977

 
$46.47
$43.71
$45.15
14,907,022
November 2016
61.73

57.36

60.33

58,022,527

 
$46.06
$42.69
$44.83
29,182,574
October 2016
$63.00
$60.11
$60.72
21,743,805

 
$47.92
$45.18
$45.28
17,275,213
September 2016
$63.41
$58.98
$62.31
30,764,941
 
$48.52
$45.23
$47.56
21,637,139
August 2016
$62.44
$58.76
$59.47
30,263,105
 
$48.34
$44.78
$45.45
17,955,730
July 2016
$61.44
$58.15
$60.54
43,506,816
 
$47.49
$44.77
$46.35
21,717,652
June 2016
$58.83
$54.11
$58.46
36,501,700
 
$45.34
$41.29
$45.22
23,263,530
May 2016
$54.80
$50.82
$54.34
26,448,076
 
$42.11
$39.13
$41.46
21,031,742
April 2016
$52.45
$48.46
$52.10
44,246,230
 
$41.81
$36.76
$41.49
23,621,043
March 2016
$51.55
$46.81
$51.06
52,762,816
 
$39.70
$35.06
$39.31
37,140,297
February 2016
$51.25
$46.63
$49.65
32,492,217
 
$37.25
$33.20
$36.70
23,015,060
January 2016

$48.83


$41.51


$48.65

38,245,477

 
$34.85
$28.40
$34.56
26,228,465
PREFERRED SHARES
Month
Preferred Shares
 
Series 1
Series 2
Series 3
Series 4
Series 5
Series 6
Series 7
Series 9
Series 11
Series 13
Series 15
December 2016
High
Low
Close
Volume traded

$16.73
$15.12
$16.26
261,560


$15.51
$14.52
$15.01
277,108

$13.40
$11.96
$13.30
212,592

$12.38
$11.11
$12.14
256,406

$13.93
$12.52
$13.86
413,388

$13.49
$12.30
$13.17
52,938

$18.93
$17.86
$18.85
873,510

$19.76
$18.40
$19.76
424,662

$22.14
$20.22
$22.00
218,142

$26.72
$25.91
$26.66
474,069

$25.49
$24.88
$25.46
2,809,717

November 2016
High
Low
Close
Volume traded

$16.26
$14.93
$15.76
358,669

$16.06
$14.02
$14.96
272,090

$12.66
$11.85
$12.30
249,686

$11.50
$10.60
$11.15
389,358

$13.97
$12.81
$13.37
269,182

$12.61
$11.55
$12.40
70,081

$18.75
$17.52
$18.04
1,394,860

$19.23
$18.10
$18.50
602,166

$21.88
$19.75
$20.39
514,149

$26.98
$25.81
$26.05
813,487

$24.99
$24.74
$24.91
4,524,844


 
 
TransCanada Annual information form 2016
29


Month
Preferred Shares
 
Series 1
Series 2
Series 3
Series 4
Series 5
Series 6
Series 7
Series 9
Series 11
Series 13
Series 15
October 2016
High
Low
Close
Volume traded

$16.09
$15.35
$15.50
212,127

$14.84
$13.82
$14.68
305,357

$12.49
$11.97
$12.18
272,961

$11.08
$10.42
$10.80
227,124

$13.94
$13.45
$13.58
245,586

$12.39
$11.51
$12.24
28,700

$18.75
$17.49
$18.47
753,435

$19.25
$17.99
$18.80
182,357

$21.52
$20.17
$21.12
324,487

$26.84
$26.32
$26.75
627,251
__
__
__
__
September 2016
High
Low
Close
Volume traded

$15.49
$14.85
$15.39
197,211

$14.25
$13.32
$13.94
195,416

$12.24
$11.72
$12.00
74,008

$10.84
$10.34
$10.70
87,305

$13.60
$12.98
$13.50
116,045

$12.83
$11.54
$11.65
15,910

$18.35
$17.65
$17.97
262,053

$19.12
$18.34
$18.55
227,501

$20.85
$20.04
$20.58
151,268

$26.83
$26.17
$26.67
758,738
__
__
__
__
August 2016
High
Low
Close
Volume traded

$15.59
$14.82
$15.38
134,779

$14.30
$13.49
$13.80
172,200

$12.49
$11.74
$12.09
191,065

$10.85
$10.38
$10.55
68,496

$13.51
$12.51
$13.44
159,674

$12.50
$11.05
$11.80
14,500

$18.65
$17.68
$18.27
483,364

$19.64
$18.51
$19.06
261,901

$21.64
$20.14
$20.54
184,520

$26.89
$26.15
$26.35
666,758
__
__
__
__
July 2016
High
Low
Close
Volume traded

$15.41
$13.64
$15.10
222,195

$13.80
$12.67
$13.75
112,725

$12.29
$10.86
$12.00
183,268

$10.74
$9.63
$10.45
64,255

$13.06
$11.51
$12.65
172,074

$12.00
$11.40
$11.68
27,125

$18.22
$16.84
$17.95
589,105

$19.00
$17.10
$18.75
351,427

$20.49
$17.81
$20.38
266,702

$26.74
$26.04
$26.64
1,284,668
__
__
__
__
June 2016
High
Low
Close
Volume traded

$15.71
$13.70
$14.23
265,533

$14.75
$12.53
$13.08
124,274

$12.01
$10.65
$11.30
106,871

$10.77
$9.84
$10.18
55,737

$12.83
$11.05
$11.89
209,863

$12.16
$11.30
$11.75
14,664

$18.44
$16.69
$17.30
793,301

$18.92
$17.10
$17.60
178,922

$20.19
$17.99
$18.36
208,206

$26.05
$25.60
$26.04
1,624,412
__
__
__
__
May 2016
High
Low
Close
Volume traded

$15.07
$14.05
$14.70
197,026

$13.90
$12.54
$13.90
123,304

$12.24
$11.27
$12.03
78,741

$10.60
$10.12
$10.30
46,565

$12.68
$11.80
$12.68
322,712

$12.96
$10.75
$11.47
21,909

$17.79
$17.05
$17.76
570,601

$18.65
$17.81
$18.36
188,858

$20.00
$18.95
$19.43
79,607

$25.94
$25.63
$25.73
1,907,966
__
__
__
__
April 2016
High
Low
Close
Volume traded

$15.70
$14.45
$14.82
87,907

$13.25
$12.10
$12.70
137,657

$12.35
$10.41
$11.45
96,957

$10.50
$9.45
$10.20
67,354

$12.94
$11.36
$12.00
294,677

$11.76
$10.20
$11.00
12,119

$19.12
$16.36
$17.48
332,789

$19.80
$17.05
$18.40
255,803

$20.94
$18.03
$19.17
202,866

$25.72
$25.49
$25.63
2,624,209
__
__
__
__
March 2016
High
Low
Close
Volume traded

$15.50
$12.78
$14.98
120,246

$12.91
$10.30
$12.63
133,058

$11.43
$9.82
$11.07
235,736

$9.73
$8.52
$9.70
79,500

$12.32
$10.25
$11.63
727,669

$12.00
$9.55
$11.02
22,308

$18.09
$15.29
$17.20
351,244

$18.93
$16.22
$17.93
292,464

$19.98
$16.85
$18.48
218,057
__
__
__
__
__
__
__
__
February 2016
High
Low
Close
Volume traded

$14.87
$12.28
$12.97
84,384

$12.19
$10.19
$10.45
99,909

$10.69
$9.42
$10.10
94,198

$9.50
$8.45
$8.47
51,032

$11.93
$10.09
$10.25
266,717

$12.00
$9.00
$10.10
11,680

$16.92
$15.06
$15.50
262,614

$17.78
$16.00
$16.45
245,104

$18.83
$16.41
$16.75
152,148
__
__
__
__
__
__
__
__
January 2016
High
Low
Close
Volume traded

$16.50
$11.83
$14.55
370,530

$13.70
$10.37
$11.94
304,071

$12.22
$9.37
$10.35
244,751

$10.40
$8.85
$9.15
236,813

$12.55
$9.50
$11.29
496,866
__
__
__
__

$18.78
$14.05
$16.70
289,007

$19.66
$14.65
$17.31
180,053

$20.55
$15.60
$18.64
163,077
__
__
__
__
__
__
__
__

 
30   
TransCanada Annual information form 2016
 


Directors and officers
As of February 15, 2017, the directors and officers of TransCanada as a group beneficially owned, or exercised control or direction over, directly or indirectly, an aggregate of 606,910 common shares of TransCanada. This constitutes less than one per cent of TransCanada's common shares. The Company collects this information from our directors and officers but otherwise we have no direct knowledge of individual holdings of TransCanada's securities.
DIRECTORS
The following table sets forth the names of the directors who serve on the Board, as of February 15, 2017 (unless otherwise indicated), together with their jurisdictions of residence, all positions and offices held by them with TransCanada, their principal occupations or employment during the past five years and the year from which each director has continually served as a director of TransCanada and, prior to the Arrangement, with TCPL. Positions and offices held with TransCanada are also held by such person at TCPL. Each director holds office until the next annual meeting or until his or her successor is earlier elected or appointed.
Name and
place of residence
 
Principal occupation during the five preceding years 
 
Director since
Kevin E. Benson
Calgary, Alberta
Canada
 
Corporate director. Director, Winter Sport Institute (non-profit) since February 2015. Director, Calgary Airport Authority from January 2010 to December 2013.
 
2005
Derek H. Burney, O.C.
Ottawa, Ontario
Canada
 
Senior strategic advisor, Norton Rose Fulbright (law firm). Chairman, GardaWorld International Advisory Board (risk management and security services) since April 2008. Advisory Board member, Paradigm Capital Inc. (investment dealer) since May 2011.
 
2005
Stéphan Crétier1

 
Corporate director. Chairman, President and Chief Executive Officer of Garda World Security Corporation (Garda World) (private security services) and director of a number of Garda World’s direct and indirect subsidiaries, since 1999. Director, ORTHOsoft Inc. (formerly ORTHOsoft Holdings Inc.) (medical software technology) from August 2004 to November 2004. Director, BioEnvelop Technologies Corp. (manufacturing) from 2001 to 2003. Director, President and Chief Executive Officer, Rafale Capital Corp. (manufacturing) from 1999 to 2001.
 
2017
Russell K. Girling2
Calgary, Alberta
Canada
 
President and Chief Executive Officer, TransCanada since July 2010. Chief Operating Officer from July 2009 to June 2010, and President, Pipelines from June 2006 to June 2010. Director, American Petroleum Institute since January 2015. Director, Agrium Inc. (agricultural) since May 2006.
 
2010
S. Barry Jackson
Calgary, Alberta
Canada
 
Corporate director. Chair of the Board, TransCanada since April 2005. Director, WestJet Airlines Ltd. (airline) since February 2009. Director, Laricina Energy Ltd. (oil and gas, exploration and production) since December 2005. Director, Nexen Inc. (Nexen) (oil and gas, exploration and production) from 2001 to June 2013, and Chair of the board, Nexen from 2012 to June 2013.
 
2002
John E. Lowe
Houston, Texas
U.S.A.
 
Non-executive Chairman of the Board of Directors, Apache Corporation (Apache) (oil and gas) since May 2015. Director, Apache from July 2013 to May 2015. Senior Executive Adviser at Tudor Pickering, Holt & Co. LLC (energy investment and merchant banking) since September 2012. Director, Phillips 66 Company (energy infrastructure) since May 2012. Director, Agrium Inc. (agriculture) from May 2010 to August 2015. Director, DCP Midstream LLC and DCP Midstream GP, LLC (energy infrastructure) from October 2008 to April 2012. Assistant to the Chief Executive Officer, ConocoPhillips (oil and gas, exploration and production) from October 2008 to April 2012. Director, Chevron Phillips Chemical Co. LLC (global petrochemicals) from October 2008 to January 2011.
 
2015
Paula Rosput Reynolds
Seattle, Washington
U.S.A.
 
President and Chief Executive Officer, PreferWest, LLC (business advisory group) since October 2009. Director, CBRE Group, Inc. (commercial real estate) since March 2016. Director, BP p.l.c. (oil and gas) since May 2015. Director, Siluria Technologies Inc. (natural gas) since February 2015. Director, BAE Systems plc. (aerospace, defence, information security) since April 2011. Director, Delta Air Lines, Inc. (airline) from August 2004 to June 2015. Director, Anadarko Petroleum Corporation (oil and gas, exploration and production) from August 2007 to May 2014.
 
2011
John Richels
Nichols Hills, Oklahoma
U.S.A.
 
Corporate director. Chairman, Devon Energy Corporation (oil and gas, exploration and production, energy infrastructure) since June 2016, and Director since June 2007 (Vice Chair from December 2014 to June 2016). Director, Independent Petroleum Association of America (oil and gas) since November 2007. Chairman of EnLink Midstream, LLC and EnLink Midstream Partner, LP (energy infrastructure) from March 2014 to June 2016. Director, BOK Financial Corporation (financial services) from January 2013 to April 2016. Chairman, American Exploration and Production Council from May 2012 to June 2015. Former Vice-Chairman of the board of governors, Canadian Association of Petroleum Producers.
 
2013

 
 
TransCanada Annual information form 2016
31


Name and
place of residence
 
Principal occupation during the five preceding years 
 
Director since
Mary Pat Salomone
Naples, Florida
U.S.A.
 
Corporate director. Director, Herc Rentals (equipment rental) since July 2016. Director, Intertape Polymer Group (manufacturing) since November 2015. Senior Vice-President and Chief Operating Officer, The Babcock & Wilcox Company (energy infrastructure) from January 2010 to June 2013. Director, United States Enrichment Corporation (basic materials, nuclear) from December 2011 to October 2012.
 
2013
Indira Samarasekera
Vancouver, British Columbia
Canada
 
Senior Advisor, Bennett Jones LLP (law firm) since September 2015. Director, Magna International (automotive manufacturing) since May 2014 and the Bank of Nova Scotia(Scotiabank) (chartered bank) since May 2008. Member, The TriLateral Commission since August 2016. Federal member, Independent Advisory Board for Senate Appointments since January 2016.
 
2016
D. Michael G. Stewart
Calgary, Alberta
Canada
 
Corporate director. Director, Pengrowth Energy Corporation (oil and gas, exploration and production) since December 2010. Director, Canadian Energy Services & Technology Corp. (chemical, oilfield services) since January 2010. Director, Northpoint Resources Ltd. (oil and gas, exploration and production) from July 2013 to February 2015. Director, C&C Energia Ltd. (oil and gas) from May 2010 to December 2012. 
 
2006
Siim A. Vanaselja
Westmount, Québec
Canada
 
Corporate director. Director, Great-West Lifeco Inc. (financial services) since May 2014. Director , Maple Leaf Sports and Entertainment Ltd. (sports, property management) since August 2012. Executive Vice-President and Chief Financial Officer, BCE Inc. and Bell Canada (telecommunications and media) from January 2001 to June 2015.
 
2014
Richard E. Waugh
Calgary, Alberta
Canada
 
Corporate director. Advisor, Acasta Enterprises Inc. (asset management/investment) since June 23, 2015. Deputy Chairman, Scotiabank from November 2013 to January 2014. President and Chief Executive Officer, Scotiabank from March 2003 to November 2013, and Deputy Chairman until January 2014. Director, Catalyst Inc. (non-profit) from February 2007 to November 2013, and Chair, Catalyst Canada Inc. Advisory Board from February 2007 to October 2013.
 
2012
1 Effective February 17, 2017.
2 As President and CEO of TransCanada, Mr. Girling is not a member of any Board Committees, but is invited to attend committee meetings as required.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions
Except as indicated below, no other director or executive officer of the Corporation is or was a director, chief executive officer or chief financial officer of another company in the past 10 years that:
was the subject of a cease trade or similar order, or an order denying that company any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days
was involved in an event that resulted in the company being subject to one of the above orders after the director or executive officer no longer held that role with the company, which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer
while acting in that capacity, or within a year of acting in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of that company.
Canwest Global Communications Corp. voluntarily entered into the Companies’ Creditors Arrangement Act (CCAA) and obtained an order from the Ontario Superior Court of Justice to start proceedings on October 6, 2009. Although no cease trade orders were issued, Canwest shares were de-listed by the TSX after the filing and started trading on the TSX Venture Exchange. Canwest emerged from CCAA protection and Postmedia Network acquired its newspaper business on July 13, 2010 while Shaw Communications Inc. acquired its broadcast media business on October 27, 2010. Mr. Burney was a director of Canwest from April 2005 to October 2010.
Laricina Energy (Laricina) voluntarily entered into the CCAA and obtained an order from the Court of Queen's Bench of Alberta, Judicial Centre of Calgary for creditor protection and stay of proceedings effective March 26, 2015.  A final court order was granted on January 28, 2016, allowing Laricina to exit from protection under the CCAA and concluding the stay of proceedings against Laricina and its subsidiaries. Mr. Jackson has been a director of Laricina since December 2005.

 
32   
TransCanada Annual information form 2016
 


On May 6, 2009, Crucible Materials Corp. (Crucible) and one of its affiliates filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the U.S. Bankruptcy Court for the District of Delaware (the Bankruptcy Court). On August 26, 2010, the Bankruptcy Court entered an order confirming Crucible’s Second Amended Chapter 11 Plan of Liquidation. Ms. Salomone was a director of Crucible from May 2008 to May 1, 2009.

No director or executive officer of the Corporation has within the past 10 years:
become bankrupt
made a proposal under any legislation relating to bankruptcy or insolvency
become subject to or launched any proceedings, arrangement or compromise with any creditors, or
had a receiver, receiver manager or trustee appointed to hold any of their assets.
No director or executive officer of the Corporation has been subject to:
any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, or
any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to    a reasonable investor in making an investment decision.
BOARD COMMITTEES
TransCanada has four committees of the Board: the Audit committee, the Governance committee, the Health, Safety & Environment committee and the Human Resources committee. The voting members of each of these committees, as of February 15, 2017 (unless otherwise indicated), are identified below. Information about the Audit committee can be found in this AIF under the heading Audit committee.
Director
Audit
committee
Governance committee
Health, Safety & Environment
committee
Human Resources
committee
Kevin E. Benson
ü
ü
 
 
Derek H. Burney
ü
Chair
 
 
Stéphan Crétier1
ü
 
ü
 
S. Barry Jackson (Chair)
 
ü
 
ü
John E. Lowe
ü
 
ü
 
Paula Rosput Reynolds
 
 
ü
Chair
John Richels
 
 
ü
ü
Mary Pat Salomone
 
 
ü
ü

Indira Samarasekera
ü

ü

 
 
D. Michael G. Stewart
ü
 
Chair
 
Siim A. Vanaselja
Chair
ü
 
 
Richard E. Waugh
 
ü
 
ü
1Effective February 17, 2017.

 
 
TransCanada Annual information form 2016
33


OFFICERS
All of the executive officers and corporate officers of TransCanada reside in Calgary, Alberta, Canada. Positions and offices held with TransCanada are also held by such person at TCPL. As of the date hereof, the officers of TransCanada, their present positions within TransCanada and their principal occupations during the five preceding years are as follows:
Executive officers
Name
Present position held 
Principal occupation during the five preceding years
Russell K. Girling
President and Chief Executive Officer
President and Chief Executive Officer.
Kristine L. Delkus
Executive Vice-President, Stakeholder Relations and General Counsel
Prior to October 2015, Executive Vice-President, General Counsel and Chief Compliance Officer. Prior to March 2014, Senior Vice-President, Pipelines Law and Regulatory Affairs. Prior to June 2012, Deputy General Counsel, Pipelines and Regulatory Affairs (TCPL).
Wendy L. Hanrahan
Executive Vice-President, Corporate Services
Executive Vice-President, Corporate Services.

Karl R. Johannson
Executive Vice-President and President, Natural Gas Pipelines
Prior to November 2012, Senior Vice-President, Canadian and Eastern U.S. Pipelines.
Donald R. Marchand
Executive Vice-President and Chief Financial Officer
Prior to February 1, 2017, Executive Vice-President, Corporate Development and Chief Financial Officer. Prior to October 2015, Executive Vice-President and Chief Financial Officer.
Paul E. Miller
Executive Vice-President and President, Liquids Pipelines
Prior to March 2014, Senior Vice-President, Oil Pipelines.
Francois L. Poirier
Executive Vice President, Strategy and Corporate Development
Prior to February 1, 2017, Senior Vice-President, Strategy and Corporate Development (Corporate Services Division) since October 2015. President, Energy East Pipeline (Development Division) from April 1, 2014 to September 30, 2015. President, Wells Fargo Securities Canada, Ltd., from January 1, 2012 to March 31, 2014.
Alexander J. Pourbaix
Chief Operating Officer
Prior to October 2015, Executive Vice-President and President, Development. Prior to March 2014, President, Energy and Oil Pipelines.
William C. Taylor
Executive Vice-President and President, Energy
Prior to March 2014, Senior Vice-President, U.S. and Canadian Power. Prior to May 2013, Senior Vice-President, Eastern Power.
Corporate officers
Name
Present position held 
Principal occupation during the five preceding years
Sean M. Brett
Vice-President, Risk Management
Prior to August 2015, Vice-President and Treasurer.
Ronald L. Cook
Vice-President, Taxation
Vice-President, Taxation (TCC) and Vice-President, Taxation (TCPL).
Joel E. Hunter
Vice-President, Finance and Treasurer
Prior to August 2015, Vice-President, Finance.
Christine R. Johnston
Vice-President, Law and Corporate Secretary
Prior to June 2014, Vice-President and Corporate Secretary. Prior to March 2012, Vice-President, Finance Law.
G. Glenn Menuz
Vice-President and Controller
Vice-President and Controller.

 
34   
TransCanada Annual information form 2016
 


CONFLICTS OF INTEREST
Directors and officers of TransCanada and its subsidiaries are required to disclose any existing or potential conflicts in accordance with TransCanada policies governing directors and officers and in accordance with the CBCA. The Code covers potential conflicts of interest.
Serving on other boards
The Board believes that it is important for it to be composed of qualified and knowledgeable directors. As a result, due to the specialized nature of the energy infrastructure business, some of our directors are associated with or sit on the boards of companies that ship natural gas or liquids through our pipeline systems. Transmission services on most of TransCanada’s pipeline systems in Canada and the U.S. are subject to regulation and accordingly we generally cannot deny transportation services to a creditworthy shipper. The Governance committee monitors relationships among directors to ensure that business associations do not affect the Board’s performance.
The Board considers whether directors serving on the boards of other entities including public and private companies, Crown corporations and other state-owned entities, and non-profit organizations pose any potential conflict. The Board reviews these relationships annually to determine that they do not interfere with any of our director’s ability to act in our best interests. If a director declares a material interest in any material contract or material transaction being considered at the meeting, the director is not present during the discussion and does not vote on the matter.
Our Code requires employees to receive consent before accepting a directorship with an entity that is not an affiliate. The chief executive officer and executive vice-presidents (our executive leadership team) must receive the consent of the Governance committee. All other employees must receive the consent of the Corporate Secretary or her delegate.
Affiliates
The Board oversees relationships between TransCanada and any affiliates to avoid any potential conflicts of interest. This includes our relationship with TCLP, a master limited partnership listed on the NYSE.
Corporate governance
Our Board and management are committed to the highest standards of ethical conduct and corporate governance.
TransCanada is a public company listed on the TSX and the NYSE, and we recognize and respect rules and regulations in both Canada and the U.S.
Our corporate governance practices comply with the Canadian governance guidelines, which include the governance rules of the TSX and Canadian Securities Administrators:
National Instrument 52-110, Audit Committees
National Policy 58-201, Corporate Governance Guidelines, and
National Instrument 58-101, Disclosure of Corporate Governance Practices.
We also comply with the governance listing standards of the NYSE and the governance rules of the SEC that apply, in each case, to foreign private issuers.
Our governance practices comply with the NYSE standards for U.S. companies in all significant respects, except as summarized on our website (www.transcanada.com). As a non-U.S. company, we are not required to comply with most of the governance listing standards of the NYSE. As a foreign private issuer, however, we must disclose how our governance practices differ from those followed by U.S. companies that are subject to the NYSE standards.
We benchmark our policies and procedures against major North American companies to assess our standards and we adopt best practices as appropriate. Some of our best practices are derived from the NYSE rules and comply with applicable rules adopted by the SEC to meet the requirements of the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Wall Street Reform and Consumer Protection Act.

 
 
TransCanada Annual information form 2016
35


Audit committee
The Audit committee is responsible for assisting the Board in overseeing the integrity of our financial statements and our compliance with legal and regulatory requirements. It is also responsible for overseeing and monitoring the internal accounting and reporting process and the process, performance and independence of our internal and external auditors. The charter of the Audit committee can be found in Schedule B of this AIF.
RELEVANT EDUCATION AND EXPERIENCE OF MEMBERS    
The members of the Audit committee as of February 15, 2017 are Siim A. Vanaselja (Chair), Kevin E. Benson, Derek H. Burney, John E. Lowe, Indira Samarasekera, and D. Michael G. Stewart. Mary Pat Salomone was a voting member of the committee from April 26, 2013 until April 29, 2016. Ms. Samarasekera joined the Committee effective April 29, 2016 and Stéphan Crétier will join the committee effective February 17, 2017.
The Board believes that the composition of the Audit committee reflects a high level of financial literacy and expertise. Each member of the Audit committee has been determined by the Board to be independent and financially literate within the meaning of the definitions under Canadian and U.S. securities laws and the NYSE rules. In addition, the Board has determined that Mr. Vanaselja, Mr. Benson and Mr. Lowe are Audit Committee Financial Experts as that term is defined under U.S. securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the Audit committee. The following is a description of the education and experience, apart from their respective roles as directors of TransCanada, of each member of the Audit committee that is relevant to the performance of his responsibilities as a member of the Audit committee.
Siim A. Vanaselja
Mr. Vanaselja is a member of the Chartered Professional Accountants of Ontario and holds an Honours Bachelor of Business degree from the Schulich School of Business. He was the Executive Vice-President and Chief Financial Officer of BCE Inc. and Bell Canada from January 2001 until June 2015, having previously served as Executive Vice-President and Chief Financial Officer of Bell Canada International from 1996 to 2001. Prior to that, he was a partner at the accounting firm KPMG Canada in Toronto. Mr. Vanaselja serves as director for Great-West Lifeco Inc. and Maple Leaf Sports and Entertainment Ltd. He has served as a member of the Conference Board of Canada’s National Council of Financial Executives, the Corporate Executive Board’s Working Council for Chief Financial Officers and Moody’s Council of Chief Financial Officers.
Kevin E. Benson
Mr. Benson is a Chartered Accountant (South Africa) and was a member of the South African Society of Chartered Accountants. He serves as a director of the Winter Sport Institute, and was the President and Chief Executive Officer of Laidlaw International, Inc. from June 2003 until October 2007. In prior years, he has held several executive positions including as President and Chief Executive Officer of The Insurance Corporation of British Columbia and has served on other public company boards and on the audit committees of all of those boards.
Derek H. Burney
Mr. Burney earned a Bachelor of Arts (Honours) and Master of Arts from Queen’s University. He is currently a senior strategic advisor at Norton Rose Fulbright. He previously served as President and Chief Executive Officer of CAE Inc. and as Chair and Chief Executive Officer of Bell Canada International Inc. Mr. Burney was the lead director at Shell Canada Limited from April 2001 until May 2007 and was the Chair of Canwest Global Communications Corp. from August 2006 until October 2010. He has served on one other organization’s audit committee and has participated in Financial Reporting Standards Training offered by KPMG.
Stéphan Crétier
Mr. Crétier earned an Masters of Business Administration from the University of California (Pacific). He is the Chairman, President and CEO of a multinational corporation, Garda World with over 20 years of experience in providing company-wide operational and financial oversight. Mr. Cretier also serves as director of a number of Garda World’s direct and indirect subsidiaries. He previously served as a director of three public companies, ORTHOsoft Inc. (formerly ORTHOsoft Holdings Inc.), BioEnvelop Technologies Corp. and Rafale Capital Corp.

 
36   
TransCanada Annual information form 2016
 


John E. Lowe
Mr. Lowe holds a Bachelor of Science degree in Finance and Accounting from Pittsburg State University and is a Certified Public Accountant (inactive). He has been the non-executive Chairman of Apache's board of directors since May 2015. He also currently serves on the board of directors for Phillips 66 Company and has been the Senior Executive Adviser at Tudor, Pickering, Holt & Co. LLC since September 2012. Mr. Lowe has previously served on the audit committees for Agrium Inc. and DCP Midstream LLC. He has also held various executive and management positions with ConocoPhillps for more than 25 years.
Indira Samarasekera
Dr. Samarasekera earned an MSc from the University of California and was granted a PhD in metallurgical engineering from the University of British Columbia. She also holds honorary degrees from the Universities of Alberta, British Columbia, Toronto, Waterloo, Montreal and Western in Canada and Queen’s University in Belfast, Ireland. Dr. Samaraskera is currently a senior advisor for Bennett Jones LLP and serves on the board of directors of the Bank of Nova Scotia, Magna International, Asia-Pacific Foundation, the Rideau Hall Foundation and the Perimeter Institute of Theoretical Physics. She is also a member of the TriLateral Commission, a federal member of the Independent Advisory Board for Senate Appointments and sits on the selection panel for Canada’s outstanding chief executive officer of the year.
D. Michael G. Stewart
Mr. Stewart earned a Bachelor of Science in Geological Sciences with First Class Honours from Queen’s University. He currently serves on the board of directors of Pengrowth Energy Corporation (governance committee Chair) and Canadian Energy Services and Technology Corp. (corporate governance and nominating committee Chair). He has also previously served on the board of directors of several other public companies and organizations and was on the audit committee of certain of those boards. Mr. Stewart held a number of senior executive positions with Westcoast Energy Inc. including Executive Vice-President, Business Development. He has been active in the Canadian energy industry for over 40 years.
PRE-APPROVAL POLICIES AND PROCEDURES
TransCanada'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 $250,000 or more, pre-approval of the Audit committee is required. In all cases, regardless of the dollar amount involved, where there is a potential for conflict of interest involving the external auditor to arise on an engagement, the Audit committee must pre-approve the assignment.
To date, all non-audit services have been pre-approved by the Audit committee in accordance with the pre-approval policy described above.
EXTERNAL AUDITOR SERVICE FEES
The table below shows the services KPMG provided during the last two fiscal years and the fees we paid them:
($ millions)
2016

2015

 
 
 
Audit fees
$8.2

$7.8

• 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
$0.1

$0.2

• services related to the audit of the financial statements of certain TransCanada post-retirement and post-employment plans, and pipeline abandonment trusts
 
 
Tax fees
$0.6

$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
$8.9

$8.5

Note: The tax fees principally related to fees incurred on account of compliance matters.


 
 
TransCanada Annual information form 2016
37


Legal proceedings and regulatory actions
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 or results of operations. Other than the Keystone XL legal proceedings described in this AIF under the heading General development of the business – Liquids Pipelines – Keystone XL, we are not aware of any potential legal proceeding or action that would have a material impact on our consolidated financial position or results of operations.
Transfer agent and registrar
TransCanada's transfer agent and registrar is Computershare Trust Company of Canada with its Canadian transfer facilities in the cities of Vancouver, Calgary, Toronto, Halifax and Montréal.
Material contracts
Except as described below, TransCanada did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2016, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2016 which are still in effect as at the date of this AIF.
In connection with the acquisition of Columbia, the Company filed the following material contract on its SEDAR profile at www.sedar.com: Agreement and Plan of Merger among TCPL, TransCanada Pipeline USA LTD., Taurus Merger Sub Inc., Columbia, and, solely for purposes of Section 3.02, Section 5.02, Section 5.09 and Article VIII, TransCanada Corporation dated as of March 17, 2016. Further information about the Columbia acquisition can be found under the General – Acquisition of Columbia Pipeline Group, Inc. and General development of the business – Natural Gas Pipelines – Developments in the U.S. Natural Gas Pipelines segment headings in this AIF.
Interest of experts
KPMG LLP are the auditors of TransCanada and have confirmed with respect to TransCanada, that they are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulations and also that they are independent accountants with respect to all relevant U.S. professional and regulatory standards.
The consolidated and combined financial statements of Columbia as of December 31, 2015 and 2014, and for each of the three years ended December 31, 2015, included in Schedule B to the business acquisition report dated July 22, 2016 were audited by Deloitte & Touche LLP (which report expresses an unqualified opinion and includes an explanatory paragraph relating to Columbia's initial public offering of limited partner interests of CPPL which was completed on February 11, 2015 and Columbia's spin-off from NiSource Inc. on July 1, 2015).
Additional information
1.
Additional information in relation to TransCanada may be found under TransCanada's profile on SEDAR (www.sedar.com).
2.
Additional information including directors' and officers' remuneration and indebtedness, principal holders of TransCanada's securities and securities authorized for issuance under equity compensation plans (all where applicable), is contained in TransCanada's Management information circular for its most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from the Corporate Secretary of TransCanada.
3.
Additional financial information is provided in TransCanada's audited consolidated financial statements and MD&A for its most recently completed financial year.

 
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TransCanada Annual information form 2016
 


Glossary
Units of measure
Bbl/d
 
Barrel(s) per day
Bcf
 
Billion cubic feet
Bcf/d
 
Billion cubic feet per day
GWh
 
Gigawatt hours
km
 
Kilometres
KW-M
 
Kilowatt month
MMcf/d
 
Million cubic feet per day
MW
 
Megawatt(s)
MWh
 
Megawatt hours
TJ/d
 
Terajoule per day
 
 
 
General terms and terms related to our operations
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
diluent
 
A thinning agent made up of organic compounds. Used to dilute bitumen so it can be transported through pipelines
FID
 
Final investment decision
force majeure
 
Unforeseeable circumstances that prevent a party to a contract from fulfilling it
GHG
 
Greenhouse gas
HSE
 
Health, safety and environment
investment base
 
Includes rate base as well as assets under construction
LNG
 
Liquefied natural gas
NEB 2014 Decision
 
In response to the RH-01-2014 Decision on the Canadian Mainline's 2015-2030 Tolls Application
OM&A
 
Operating, maintenance and administration
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
PPA
 
Power purchase arrangement
rate base
 
Our annual average investment used
TSA
 
Transportation Service Agreements
WCSB
 
Western Canada Sedimentary Basin
 

Accounting terms
AFUDC
 
Allowance for funds used during construction
DRP
 
Dividend reinvestment plan
GAAP
 
U.S. generally accepted accounting principles
ROE
 
Rate of return on common equity
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Government and regulatory bodies terms
CFE
 
Comisión Federal de Electricidad (Mexico)
CRE
 
Comisión Reguladora de Energia, or Energy Regulatory Commission (Mexico)
FERC
 
Federal Energy Regulatory Commission (U.S.)
IESO
 
Independent Electricity System Operator
ISO
 
Independent System Operator
NAFTA
 
North American Free Trade Agreement
NEB
 
National Energy Board (Canada)
OPEC
 
Organization of the Petroleum Exporting Countries
OPG
 
Ontario Power Generation
RGGI
 
Regional Greenhouse Gas Initiative (northeastern U.S.)
SEC
 
U.S. Securities and Exchange Commission
SGER
 
Specified Gas Emitters Regulations




 
 
TransCanada Annual information form 2016
39


Schedule A
Metric conversion table
The conversion factors set out below are approximate factors. To convert from Metric to Imperial multiply by the factor indicated. To convert from Imperial to Metric divide by the factor indicated.
Metric
Imperial
Factor
Kilometres (km)
Miles
0.62
Millimetres
Inches
0.04
Gigajoules
Million British thermal units
0.95
Cubic metres*
Cubic feet
35.3
Kilopascals
Pounds per square inch
0.15
Degrees Celsius
Degrees Fahrenheit
to convert to Fahrenheit multiply by 1.8, then add 32 degrees; to convert to Celsius subtract 32 degrees, then divide by 1.8
*
The conversion is based on natural gas at a base pressure of 101.325 kilopascals and at a base temperature of 15 degrees Celsius.

 
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TransCanada Annual information form 2016
 


Schedule B
CHARTER OF THE AUDIT COMMITTEE
1. PURPOSE
The Audit Committee shall assist the Board of Directors (the Board) in overseeing and monitoring, among other things, the:
Company’s financial accounting and reporting process;
integrity of the financial statements;
Company’s internal control over financial reporting;
external financial audit process;
compliance by the Company with legal and regulatory requirements; and
independence and performance of the Company’s internal and external auditor.
To fulfill its purpose, the Audit Committee has been delegated certain authorities by the Board that it may exercise on behalf of the Board.
2. ROLES AND RESPONSBILITIES
I. Appointment of the Company’s External Auditor
Subject to confirmation by the external auditor of their compliance with Canadian and U.S. regulatory registration requirements, the Audit Committee shall recommend to the Board the appointment of the external auditor, such appointment to be confirmed by the Company’s shareholders at each annual meeting. The Audit Committee shall also recommend to the Board the compensation to be paid to the external auditor for audit services. The Audit Committee shall also be directly responsible for the oversight of the work of the external auditor (including resolution of disagreements between management and the external auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or related work. The external auditor shall report directly to the Audit Committee.
The Audit Committee shall review and approve the audit plan of the external auditor. The Audit Committee shall also receive periodic reports from the external auditor regarding the auditor’s independence, discuss such reports with the auditor, consider whether the provision of non-audit services is compatible with maintaining the auditor’s independence and take appropriate action to satisfy itself of the independence of the external auditor.
II. Oversight in Respect of Financial Disclosure
The Audit Committee, to the extent it deems it necessary or appropriate, shall:
a)
review, discuss with management and the external auditor and recommend to the Board for approval, the Company’s audited annual consolidated financial statements, annual information form, management’s discussion and analysis (MD&A), all financial information in prospectuses and other offering memoranda, financial statements required by securities regulators, all prospectuses and all documents which may be incorporated by reference into a prospectus, including, without limitation, the annual management information circular, but excluding any pricing or prospectus supplement relating to the issuance of debt securities of the Company;
b)
review, discuss with management and the external auditor and recommend to the Board for approval, the release to the public of the Company’s interim reports, including the consolidated financial statements, MD&A and press releases on quarterly financial results;
c)
review and discuss with management and the external auditor the use of non-GAAP information and the applicable reconciliation;
d)
review and discuss with management any financial outlook or future-oriented financial information disclosure in advance of its public release; provided, however, that such discussion may be done generally (consisting of discussing the types of information to be disclosed and the types of presentations to be made). The Audit Committee need not discuss in advance each instance in which the Company may provide financial projections or presentations to credit rating agencies;
e)
review with management and the external auditor major issues regarding accounting policies and auditing practices, including any significant changes in the Company’s selection or application of accounting policies, as well as major issues as to the adequacy of the Company’s internal controls and any special audit steps adopted in light of material control deficiencies that could significantly affect the Company’s financial statements;
f)
review and discuss quarterly findings reports from the external auditor on:
(i)
all critical accounting policies and practices to be used;

 
 
TransCanada Annual information form 2016
41


(ii)
all alternative treatments of financial information within generally accepted accounting principles that have been discussed with management, ramifications of the use of such alternative disclosures and treatments, and the treatment preferred by the external auditor;
(iii)
other material written communications between the external auditor and management, such as any management letter or schedule of unadjusted differences;
g)
review with management and the external auditor the effect of regulatory and accounting developments on the Company's financial statements;
h)
review with management and the external auditor the effect of any off-balance sheet structures on the Company's financial statements;
i)
review with management, the external auditor and, if necessary, legal counsel, any litigation, claim or contingency, including arbitration and tax assessments, that could have a material effect upon the financial position of the Company, and the manner in which these matters have been disclosed in the financial statements;
j)
review disclosures made to the Audit Committee by the Company’s Chief Executive Officer (CEO) and Chief Financial Officer (CFO) during their certification process for the periodic reports filed with securities regulators about any significant deficiencies in the design or operation of internal controls or material weaknesses therein and any fraud involving management or other employees who have a significant role in the Company’s internal controls;
k)
discuss with management the Company’s material financial risk exposures and the steps management has taken to monitor and control such exposures, including the Company’s risk assessment and risk management policies;
III. Oversight in Respect of Legal and Regulatory Matters
(a)
review with the Company’s General Counsel legal matters that may have a material impact on the financial statements, the Company’s compliance policies and any material reports or inquiries received from regulators or governmental agencies;
IV. Oversight in Respect of Internal Audit
(a)
review and approve the audit plans of the internal auditor of the Company including the degree of coordination between such plans and those of the external auditor and the extent to which the planned audit scope can be relied upon to detect weaknesses in internal control, fraud or other illegal acts;
(b)
review the significant findings prepared by the internal audit department and recommendations issued by it or by any external party relating to internal audit issues, together with management’s response thereto;
(c)
review compliance with the Company’s policies and avoidance of conflicts of interest;
(d)
review the report prepared by the internal auditor on officers' expenses and aircraft usage;
(e)
review the adequacy of the resources of the internal auditor to ensure the objectivity and independence of the internal audit function, including reports from the internal audit department on its audit process with subsidiaries and affiliates;
(f)
ensure the internal auditor has access to the Chair of the Audit Committee, the Board and the CEO and meet separately with the internal auditor to review with him or her any problems or difficulties he or she may have encountered and specifically:
(i)
any difficulties which were encountered in the course of the audit work, including restrictions on the scope of activities or access to required information, and any disagreements with management;
(ii)
any changes required in the planned scope of the internal audit;
(iii)
the internal audit department responsibilities, budget and staffing; and to report to the Board on such meetings;
V. Oversight in Respect of the External Auditor
(a)
review any letter, report or other communication from the external auditor in respect of any identified weakness or unadjusted difference and management’s response and follow-up, inquire regularly of management and the external auditor of any significant issues between them and how they have been resolved, and intervene in the resolution if required;
(b)
receive and review annually the external auditor’s formal written statement of independence delineating all relationships between itself and the Company;

 
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TransCanada Annual information form 2016
 


(c)
meet separately with the external auditor to review any problems or difficulties the external auditor may have encountered and specifically:
(i)
any difficulties which were encountered in the course of the audit work, including any restrictions on the scope of activities or access to required information, and any disagreements with management;
(ii)
any changes required in the planned scope of the audit; and to report to the Board on such meetings;
(d)
meet with the external auditor prior to the audit to review the planning and staffing of the audit;
(e)
receive and review annually the external auditor's written report on their own internal quality control procedures; any material issues raised by the most recent internal quality control review, or peer review, of the external auditor, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, and any steps taken to deal with such issues;
(f)
review and evaluate the external auditor, including the lead partner of the external auditor team;
(g)
ensure the rotation of the lead (or coordinating) audit partner having primary responsibility for the audit and the audit partner responsible for reviewing the audit as required by law, but at least every five years;
VI. Oversight in Respect of Audit and Non-Audit Services