U.S. Securities and Exchange Commission Washington, D.C. 20549 Form 40-F
For the fiscal year ended December 31, 2014 Commission File Number 1-31690
Securities registered or to be registered pursuant to Section 12(b) of the Act:
Securities registered or to be registered pursuant to Section 12(g) of the Act: NoneSecurities 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:
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, 2014, 708,662,996 common shares;9,498,423 Cumulative Redeemable First Preferred Shares, Series 1;12,501,577 Cumulative Redeemable First Preferred Shares, Series 2;14,000,000 Cumulative Redeemable First Preferred Shares, Series 3;14,000,000 Cumulative Redeemable First Preferred Shares, Series 5;24,000,000 Cumulative Redeemable First Preferred Shares, Series 7; and18,000,000 Cumulative Redeemable First Preferred Shares, Series 9were 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 ý No o
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 ý No o
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:
S-8
F-3
F-10
AUDITED CONSOLIDATED ANNUAL FINANCIAL STATEMENTS AND MANAGEMENT'S DISCUSSION AND ANALYSIS
Except sections specifically referenced below which shall be deemed incorporated by reference herein and filed, no other portion of the TransCanada Corporation 2014 Annual report 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 121 through 182 of the TransCanada Corporation 2014 Annual report to shareholders included herein.
B. Management's Discussion and Analysis
For management's discussion and analysis, see pages 21 through 120 of the TransCanada Corporation 2014 Annual report 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 121 of the TransCanada Corporation 2014 Annual report to shareholders included herein.
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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
For information on disclosure controls and procedures, see "Other information — Controls and Procedures" in Management's discussion and analysis on pages 105 and 106 of the TransCanada Corporation 2014 Annual report 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. Kevin E. Benson and Mr. Siim A. Vanaselja 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. Benson and Mr. Vanaselja as audit committee financial experts does not make Mr. Benson or Mr. Vanaselja "experts" for any purpose, impose any duties, obligations or liability on Mr. Benson or Mr. Vanaselja that are greater than those imposed on members of the Audit committee and Board of Directors who do not carry this designation or affect the duties, obligations or liability of any other member of the Audit committee.
CODE OF ETHICS
The Registrant has adopted a code of business ethics for its directors, officers, employees and contractors. The Registrant's code is available on its website at www.transcanada.com. No waivers have been granted from any provision of the code during the 2014 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 pages 36 and 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 26 of the Notes to the 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 95 of the TransCanada Corporation 2014 Annual report to shareholders.
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IDENTIFICATION OF THE AUDIT COMMITTEE
The Registrant has a separately-designated standing Audit committee. The members of the Audit committee are:
FORWARD-LOOKING INFORMATION
We disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe, may, will, should, estimate or other similar words.
Forward-looking statements in this document may include information about the following, among other things:
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
4
Risks and uncertainties
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.
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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.
DOCUMENTS FILED AS PART OF THIS REPORT
13.1
TransCanada Corporation Annual information form for the year ended December 31, 2014.
13.2
Management's discussion and analysis (included on pages 21 through 120 of the TransCanada Corporation 2014 Annual report to shareholders).
13.3
2014 Audited consolidated financial statements (included on pages 121 through 182 of the TransCanada Corporation 2014 Annual report 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, 2014.
EXHIBITS
23.1
Consent of KPMG LLP, Independent Registered Public Accounting Firm.
31.1
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certification of Chief Executive Officer regarding Periodic Report containing Financial Statements.
32.2
Certification of Chief Financial Officer regarding Periodic Report containing Financial Statements.
101.INS
XBRL Instance Document.
101.SCH
XBRL Taxonomy Extension Schema Document.
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
XBRL Taxonomy Definition Linkbase Document.
101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
TransCanada Corporation
2014 Annual information form
February 12, 2015
Table of Contents
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, 2014 (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 12, 2015 (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 United States 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.
Forward-looking statements contained or incorporated by reference in this AIF may include information about the following, among other things:
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 AIF and other disclosure incorporated by reference herein.
2 TransCanada Annual information form 2014
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. 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.
TransCanada Annual information form 2014 3
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 or revenues that exceeded 10 per cent of the total consolidated revenues of TransCanada as at Year End. TransCanada beneficially owns, controls or directs, directly or indirectly, 100 per cent of the voting shares in each of these subsidiaries.
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.
General development of the business
We operate our business in three segments: Natural Gas Pipelines, Liquids Pipelines and Energy. 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 2015.
4 TransCanada Annual information form 2014
DEVELOPMENTS IN THE NATURAL GAS PIPELINES BUSINESS
Canadian Regulated Pipelines
TransCanada Annual information form 2014 5
6 TransCanada Annual information form 2014
TransCanada Annual information form 2014 7
8 TransCanada Annual information form 2014
Further information about developments in the Natural Gas Pipelines business can be found in the MD&A in the About our business – Our strategy, Natural Gas Pipelines – Results, Natural Gas Pipelines – Outlook, Natural Gas Pipelines – Understanding the Natural Gas Pipelines Business and Natural Gas Pipelines – Significant Events sections, which sections of the MD&A are incorporated by reference herein.
TransCanada Annual information form 2014 9
DEVELOPMENTS IN THE LIQUIDS PIPELINES BUSINESS
10 TransCanada Annual information form 2014
TransCanada Annual information form 2014 11
Further information about developments in the Liquids Pipelines business can be found in the MD&A in the About our business – Strategy, Liquids Pipelines – 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.
12 TransCanada Annual information form 2014
DEVELOPMENTS IN THE ENERGY BUSINESS
Canadian Power
TransCanada Annual information form 2014 13
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Further information about developments in the Energy business can be found in the MD&A in the About our business – Strategy, Energy – Results, Energy – Outlook, Energy – Understanding the Energy business and Energy – Significant Events sections, which sections of the MD&A are incorporated by reference herein.
TransCanada Annual information form 2014 15
Business of TransCanada
We are a leading North American energy infrastructure company focused on Natural Gas Pipelines, Liquids Pipelines and Energy. At Year End and for the year then ended, Natural Gas Pipelines accounted for approximately 48 per cent of revenues and 46 per cent of our total assets, Liquids Pipelines accounted for approximately 15 per cent of revenues and 27 per cent of our total assets' and Energy accounted for approximately 37 per cent of revenues and 24 per cent of our total assets. The following table shows our revenues from operations by segment, classified geographically, for the years ended December 31, 2014 and 2013.
The following is a description of each of TransCanada's three main areas of operations.
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NATURAL GAS PIPELINES BUSINESS Our natural gas pipeline network transports natural gas to local distribution companies, power generation facilities and other businesses across Canada, the U.S. and Mexico. We also have regulated natural gas storage facilities in Michigan.
We are the operator of all of the following natural gas pipelines and regulated natural gas storage assets except for Iroquois.
TransCanada Annual information form 2014 17
Further information about our pipeline holdings, developments and opportunities and significant regulatory developments which relate to Natural Gas Pipelines can be found in the MD&A in the Natural Gas Pipelines – Results, Natural Gas Pipelines – Understanding the Natural Gas Pipelines Business and Natural Gas Pipelines – Significant Events sections, which sections of the MD&A are incorporated by reference herein.
18 TransCanada Annual information form 2014
LIQUIDS PIPELINES BUSINESS Our existing liquids pipeline infrastructure connects Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas, as well as connecting U.S. crude oil supplies from the Cushing, Oklahoma hub to refining markets in the U.S. Gulf Coast. Our proposed future pipeline infrastructure would also connect Canadian and U.S. crude oil supplies to refining markets in eastern Canada and overseas export markets, expand Canadian and U.S. crude oil to U.S. markets and connect condensate supplies to U.S. and Canadian markets.
We are the operator of all of the following pipelines and properties.
Further information about our pipeline holdings, developments and opportunities and significant regulatory developments which relate to Liquids Pipelines can be found in the MD&A in the Liquids Pipelines – Results, 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 2014 19
REGULATION OF THE NATURAL GAS AND LIQUIDS PIPELINES BUSINESSES
Canada
Natural Gas Pipelines The Canadian Mainline, NGTL System and most of the other Canadian pipelines owned or operated by TransCanada (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 the Company's 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 – Developments in the Natural Gas Pipelines business – Canadian Mainline, Tolls and Tariff Applications (LDC Settlement) section above.
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.
Natural Gas Pipelines Projects The Coastal GasLink and PRGT 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, facilities and the physical operation of the Canadian portion of the Keystone Pipeline System.
Liquids Pipelines Projects TC Terminals, Northern Courier Pipeline, and Grand Rapids Pipeline were approved by the AER in February, July and October 2014 respectively. All three projects are currently under construction. The Heartland Pipeline application is currently under regulatory review 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 proposed and developed under the regulatory regime administered by the NEB.
United States
Natural Gas Pipelines TransCanada'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 and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation and interstate commerce. The ANR System's natural gas storage facilities in Michigan are also regulated by FERC.
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 Cushing Marketlink. The siting and construction of pipeline facilities are regulated by the specific state commissions where the pipeline crosses. 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 Keystone Pipeline System and the proposed Keystone XL project, are required to obtain a Presidential Permit from the DOS.
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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 BUSINESS Our Energy business includes a portfolio of power generation assets in Canada and the U.S., and unregulated natural gas storage assets in Alberta.
We own, control or are developing generation capacity powered by natural gas, nuclear, coal, hydro, wind and solar assets. Our power business in Canada is mainly located in Alberta, Ontario and Québec. Our power business in the U.S. is located in New York, New England, and Arizona. The assets are largely supported by long-term contracts and some represent low cost baseload generation, while others are critically located, essential capacity.
We conduct wholesale and retail electricity marketing and trading throughout North America from our offices in Alberta, Ontario and Massachusetts to actively manage our commodity exposure and provide higher returns.
We own or control unregulated natural gas storage capacity in Alberta and regulated natural gas storage in Michigan (part of the Natural Gas Pipelines segment).
We are the operator of all of our Energy assets, except for the Sheerness, Sundance A and Sundance B PPAs, Cartier Wind, Bruce A and B and Portlands Energy.
TransCanada Annual information form 2014 21
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We own or have the rights to power supply in Alberta and Arizona through three long-term PPAs, five natural gas-fired cogeneration facilities, and through Coolidge, a simple-cycle, natural gas peaking facility in Arizona.
Power purchased under long-term contracts is as follows:
Power sold under long-term contracts is as follows:
We own or are developing power generation capacity in eastern Canada. All of the power produced by these assets is sold under long-term contracts.
Assets currently operating under long-term contracts are as follows:
Assets currently under construction are as follows:
Further information about our Energy holdings and significant developments and opportunities in relation to Energy can be found in the MD&A in the Energy – Results, Energy – Understanding the Energy business and Energy – Significant Events sections, which sections of the MD&A are incorporated by reference herein.
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General
EMPLOYEES At Year End, TransCanada's principal operating subsidiary, TCPL, had 6,059 full time active employees, substantially all of whom were employed in Canada and the U.S., as set forth in the following table.
HEALTH, SAFETY AND ENVIRONMENTAL PROTECTION AND SOCIAL POLICIES The Health, Safety and Environment 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 health, safety and environment (HSE) corporate policy through regular reporting from management. We have an integrated HSE management system that establishes a framework for managing HSE issues that is used to capture, organize and document 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 requirements and various other internal management systems. It follows a continuous improvement cycle organized into four key areas:
The committee reviews HSE performance and operational risk management on a quarterly basis. It receives detailed reports on:
The committee also receives updates on any specific areas of operational and construction risk management review being conducted by management and the results and corrective action plans emanating from internal and third party audits.
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 inspection and audit programs designed to keep all of our facilities in compliance with environmental requirements.
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Safety and asset integrity As one of TransCanada's priorities, safety is an integral part of the way our employees work. Since 2008, we have sustained year over year improvement in our safety performance. Overall, TransCanada's incident frequency rates in 2014 continued to meet or exceed most 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.
Social Policies TransCanada has a number of policies, guiding principles and practices in place to help manage Aboriginal and other 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 every year. The Code is based on the Company's four core values of integrity, collaboration, responsibility and innovation, which guide the interaction between and among the Company's employees and contractors, and serve as a standard for us in our dealings with all stakeholders.
Our approach to stakeholder engagement is based on building relationships, mutual respect and trust while recognizing the unique values, needs and interests of each community. Our stakeholder relations framework 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.
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 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 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.
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 it 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. In the opinion of TransCanada's management, such provisions do not currently restrict or alter TransCanada's ability to declare or pay dividends.
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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 are set out in the following table:
We increased the quarterly dividend on our outstanding common shares by eight per cent to $0.52 per share for the quarter ending March 31, 2015.
Description of capital structure
SHARE CAPITAL TransCanada's authorized share capital consists of an unlimited number of common shares, of which 708,662,996 were issued and outstanding at Year End, and an unlimited number of first preferred shares and second preferred shares, issuable in series, of which the following were issued and outstanding as at Year End, or as otherwise indicated below.
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
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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) which permits eligible holders of TransCanada common or preferred shares and preferred shares of TCPL to elect to reinvest their dividends and make optional cash payments to buy TransCanada common shares acquired on the open market at 100 per cent of the weighted average purchase price. Participants may also make additional cash payments 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 stock based compensation plans that allow 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 plans 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 and 9 preferred shares will be entitled to receive quarterly five-year fixed rate cumulative preferential cash dividends, as and when declared by the Board, at 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 and have the right to convert their shares into cumulative redeemable Series 2, 4, 6, 8, and 10 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series 1, 3, 5, 7 and 9 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 and 10 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 and 9 preferred shares, respectively, subject to certain conditions, on such conversion dates as set forth in the table below. The Series 2, 4, 6, 8 and 10 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.
TransCanada Annual information form 2014 27
In the event of liquidation, dissolution or winding up of TransCanada, the holders of Series 1, 2, 3, 4, 5, 6, 7, 8, 9 and 10 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.
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.
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 Standard & Poor's (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 stable 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. The following table sets out the current credit ratings assigned to those outstanding classes of securities of the Company and TCPL which have been rated by DBRS, Moody's and S&P:
28 TransCanada Annual information form 2014
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 and TCPL paid fees to each of DBRS, Moody's and S&P for the credit ratings rendered their outstanding classes of securities noted above. Other than annual monitoring fees for the Company and TCPL and their rated securities, no additional payments were made to DBRS, Moody's and S&P in respect of any other services provided to us during the past two years.
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.
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 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 ten categories for long-term debt. Long-term debt rated A is good credit quality. The capacity for the payment of interest and principal 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 ten categories for long-term debt. Long- term debt rated BBB is of adequate credit quality. The capacity for the payment of interest and principal is considered acceptable, but long-term debt rated BBB may be vulnerable to future events. The Pfd-2 (low) rating assigned to TCPL's and 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 Baa1 and Baa2 ratings assigned to TCPL's junior subordinated debt and preferred shares, respectively, are in the fourth highest of nine rating categories for long-term obligations, with the junior subordinated debt ranking higher within the Baa rating category with a modifier of 1 as opposed to the modifier of 2 on the 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 ten 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. As guarantor of a U.S. subsidiary's commercial paper program, TCPL has been assigned a commercial paper rating of 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 is in the fourth highest of ten 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 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.
TransCanada Annual information form 2014 29
Market for securities
TransCanada's common shares are listed on the TSX and the New York Stock Exchange (NYSE) under the symbol TRP. Our Series 1, 2, 3, 5, 7 and 9 preferred shares have been listed for trading on the TSX since September 30, 2009, December 31, 2014, March 11, 2010, June 29, 2010, March 4, 2013 and January 20, 2014 under the symbols TRP.PR.A, TRP.PR.F, TRP.PR.B, TRP.PR.C, TRP.PR.D, and TRP.PR.E, respectively. 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, 5, 7 and 9 preferred shares on the TSX, for the period indicated:
COMMON SHARES
PREFERRED SHARES
30 TransCanada Annual information form 2014
TCPL's cumulative redeemable first preferred shares, series Y, were listed on the TSX under the symbol TCA.PR.Y until their redemption on March 5, 2014.
SERIES Y PREFERRED SHARES
TransCanada Annual information form 2014 31
Directors and officers
As of February 12, 2015, the directors and officers of TransCanada as a group beneficially owned, or exercised control or direction over, directly or indirectly, an aggregate of 441,744 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 12, 2015 (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.
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BOARD COMMITTEES TransCanada has four committees of the Board: the Audit committee, the Governance committee, the Health, Safety and Environment committee and the Human Resources committee. The voting members of each of these committees, as of February 12, 2015, are identified below. Ms. Reynolds was appointed as the Chair of the Human Resources committee effective May 2, 2014.
Information about the Audit committee can be found in this AIF under the heading Audit committee.
TransCanada Annual information form 2014 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
Corporate officers
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. Our 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.
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The Board considers whether directors serving on the boards of all 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 must receive the consent of the Governance committee. All other employees must receive the consent of their immediate supervisor.
Affiliates The Board closely oversees relationships between TransCanada and any affiliates to avoid any potential conflicts of interest. This includes our relationship with the 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:
We also comply with the governance listing standards of the NYSE and the governance rules of the SEC that, in each case, apply 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.
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 12, 2015 are Kevin E. Benson (Chair), Derek H. Burney, Mary Pat Salomone, D. Michael G. Stewart, and Siim A. Vanaselja. Richard E. Waugh attended the Audit committee meetings as an observer until he retired as Deputy Chairman of Scotiabank on January 31, 2014 and was a voting member of the committee from February 1 until May 2, 2014. Mr. Vanaselja was appointed as a member of the Audit committee effective May 2, 2014.
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. Benson and Mr. Vanaselja 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
TransCanada Annual information form 2014 35
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.
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. until October 2007. In prior years, he has held several executive positions including one 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 certain 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 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 until May 2007 and was the Chair of Canwest Global Communications Corp. until October 2010. He has served on one other organization's audit committee and has participated in Financial Reporting Standards Training offered by KPMG.
Mary Pat Salomone Ms. Salomone has a Bachelor of Engineering in Civil Engineering from Youngstown State University and a Master of Business Administration from Baldwin Wallace College. She completed the Advanced Management Program at Duke University's Fuqua School of Buiness in 2011. Ms. Salomone was the Senior Vice-President and Chief Operating Officer of B&W until June 2013. She previously held a number of senior roles with B&W Nuclear, including serving as the Manager of Business Development from 2009 to 2010 and Manager of Strategic Acquisitions from 2008 to 2009, and served as President and Chief Executive Officer of Marine Mechanical Corporation 2001 through 2007, which B&W acquired in 2007.
D. Michael G. Stewart Mr. Stewart earned a Bachelor of Science in Geological Sciences with First Class Honours from Queen's University. He has served and continues to serve on the boards of several public companies and other organizations and 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 also been active in the Canadian energy industry for over 40 years.
Siim A. Vanaselja Mr. Vanaselja is a member of the Institute of Chartered Accountants of Ontario and holds an Honours Bachelor of Business degree from the Schulich School of Business. Mr. Vanaselja has been the Executive Vice-President and Chief Financial Officer of BCE Inc. and Bell Canada since January 2001, having previously served as Executive Vice-President and Chief Financial Officer of Bell Canada International. Prior to that, he was a partner at the accounting firm KPMG Canada in Toronto. Mr. Vanaselja has served and continues to serve as a board director for several other companies including 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.
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.
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EXTERNAL AUDITOR SERVICE FEES The table below shows the services KPMG provided during the last two fiscal years and the fees we paid them:
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, results of operations or liquidity. We are not aware of any potential legal proceeding or action that would have a material impact on our consolidated financial position, results of operations or liquidity.
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
TransCanada did not enter into any material contracts outside the ordinary course of business during the year ended December 31, 2014, nor has it entered into any material contracts outside the ordinary course of business prior to the year ended December 31, 2014 which are still in effect as at the date of this AIF.
Interest of experts
KPMG LLP are the auditors of TransCanada and have confirmed that they are independent with respect to TransCanada 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.
Additional information
TransCanada Annual information form 2014 37
Glossary
Units of measure
General terms and terms related to our operations
Accounting terms
Government and regulatory bodies terms
38 TransCanada Annual information form 2014
Schedule AMetric 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.
TransCanada Annual information form 2014 39
Schedule BCharter 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:
To fulfill its purpose, the Audit Committee has been delegated certain authorities by the Board of Directors that it may exercise on behalf of the Board.
2. ROLES AND RESPONSIBILITIES
I. Appointment of the Company's External Auditors Subject to confirmation by the external auditors of their compliance with Canadian and U.S. regulatory registration requirements, the Audit Committee shall recommend to the Board the appointment of the external auditors, 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 auditors 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 also receive periodic reports from the external auditors regarding the auditors' independence, discuss such reports with the auditors, consider whether the provision of non-audit services is compatible with maintaining the auditors' independence and the Audit Committee shall take appropriate action to satisfy itself of the independence of the external auditors.
II. Oversight in Respect of Financial Disclosure The Audit Committee, to the extent it deems it necessary or appropriate, shall:
40 TransCanada Annual information form 2014
III. Oversight in Respect of Legal and Regulatory Matters
IV. Oversight in Respect of Internal Audit
and to report to the Board on such meetings;
V. Insight in Respect of the External Auditors
TransCanada Annual information form 2014 41
VI. Oversight in Respect of Audit and Non-Audit Services
VII. Oversight in Respect of Certain Policies
VIII. Oversight in Respect of Financial Aspects of the Company's Canadian Pension Plans (the "Company's pension plans"), specifically:
42 TransCanada Annual information form 2014
IX. U.S. Stock Plans
X. Oversight in Respect of Internal Administration
XI. Information Security
XII. Oversight Function While the Audit Committee has the responsibilities and powers set forth in this Charter, it is not the duty of the Audit Committee to plan or conduct audits or to determine that the Company's financial statements and disclosures are complete and accurate or are in accordance with generally accepted accounting principles and applicable rules and regulations. These are the responsibilities of management and the external auditors. The Audit Committee, its Chair and any of its members who have accounting or related financial management experience or expertise, are members of the Board, appointed to the Audit Committee to provide broad oversight of the financial disclosure, financial risk and control related activities of the Company, and are specifically not accountable nor responsible for the day to day operation of such activities. Although designation of a member or members as an "audit committee financial expert" is based on that individual's education and experience, which that individual will bring to bear in carrying out his or her duties on the Audit Committee, designation as an "audit committee financial expert" does not impose on such person any duties, obligations or liability that are greater than the duties, obligations and liability imposed on such person as a member of the Audit Committee and Board in the absence of such designation. Rather, the role of any audit committee financial expert, like the role of all Audit Committee members, is to oversee the process and not to certify or guarantee the internal or external audit of the Company's financial information or public disclosure.
3. COMPOSITION OF AUDIT COMMITTEE The Audit Committee shall consist of three or more Directors, a majority of whom are resident Canadians (as defined in the Canada Business Corporations Act), and all of whom are unrelated and/or independent for the purposes of applicable Canadian and United States securities law and applicable rules of any stock exchange on which the Company's securities are listed. Each member of the Audit Committee shall be financially literate and at least one member shall have accounting or related financial management expertise (as those terms are defined from time to time under the requirements or guidelines for audit committee service under securities laws and the applicable rules of any stock exchange on which the Company's securities are listed for trading or, if it is not so defined, as that term is interpreted by the Board in its business judgment).
TransCanada Annual information form 2014 43
4. APPOINTMENT OF AUDIT COMMITTEE MEMBERS The members of the Audit Committee shall be appointed by the Board from time to time, on the recommendation of the Governance Committee and shall hold office until the next annual meeting of shareholders or until their successors are earlier appointed or until they cease to be Directors of the Company.
5. VACANCIES Where a vacancy occurs at any time in the membership of the Audit Committee, it may be filled by the Board on the recommendation of the Governance Committee.
6. AUDIT COMMITTEE CHAIR The Board shall appoint a Chair of the Audit Committee who shall:
7. ABSENCE OF AUDIT COMMITTEE CHAIR If the Chair of the Audit Committee is not present at any meeting of the Audit Committee, one of the other members of the Audit Committee present at the meeting shall be chosen by the Audit Committee to preside at the meeting.
8. SECRETARY OF AUDIT COMMITTEE The Corporate Secretary shall act as Secretary to the Audit Committee.
9. MEETINGS The Chair, or any two members of the Audit Committee, or the internal auditor, or the external auditors, may call a meeting of the Audit Committee. The Audit Committee shall meet at least quarterly. The Audit Committee shall meet periodically with management, the internal auditors and the external auditors in separate executive sessions.
10. QUORUM A majority of the members of the Audit Committee, present in person or by telephone or other telecommunication device that permit all persons participating in the meeting to speak to each other, shall constitute a quorum.
11. NOTICE OF MEETINGS Notice of the time and place of every meeting shall be given in writing, facsimile communication or by other electronic means to each member of the Audit Committee at least 24 hours prior to the time fixed for such meeting; provided, however, that a member may in any manner waive a notice of a meeting. Attendance of a member at a meeting is a waiver of notice of the meeting, except where a member attends a meeting for the express purpose of objecting to the transaction of any business on the grounds that the meeting is not lawfully called.
12. ATTENDANCE OF COMPANY OFFICERS AND EMPLOYEES AT MEETING At the invitation of the Chair of the Audit Committee, one or more officers or employees of the Company may attend any meeting of the Audit Committee.
13. PROCEDURE, RECORDS AND REPORTING The Audit Committee shall fix its own procedure at meetings, keep records of its proceedings and report to the Board when the Audit Committee may deem appropriate but not later than the next meeting of the Board.
44 TransCanada Annual information form 2014
14. REVIEW OF CHARTER AND EVALUATION OF AUDIT COMMITTEE The Audit Committee shall review its Charter annually or otherwise, as it deems appropriate and, if necessary, propose changes to the Governance Committee and the Board. The Audit Committee shall annually review the Audit Committee's own performance.
15. OUTSIDE EXPERTS AND ADVISORS The Audit Committee is authorized, when deemed necessary or desirable, to retain and set and pay the compensation for independent counsel, outside experts and other advisors, at the Company's expense, to advise the Audit Committee or its members independently on any matter.
16. RELIANCE Absent actual knowledge to the contrary (which shall be promptly reported to the Board), each member of the Audit Committee shall be entitled to rely on (i) the integrity of those persons or organizations within and outside the Company from which it receives information, (ii) the accuracy of the financial and other information provided to the Audit Committee by such persons or organizations and (iii) representations made by management and the external auditors, as to any information technology, internal audit and other non-audit services provided by the external auditors to the Company and its subsidiaries.
TransCanada Annual information form 2014 45
2014 Annual Report Delivering Results Positioned for Growth
Our annual report is online, visit our site for more information. www.transcanada.com Forward-Looking Information and Non-GAAP Measures These pages contain certain forward-looking information and also contain references to certain non-GAAP measures that do not have any standardized meaning as prescribed by U.S. generally accepted accounting principles (GAAP) and therefore may not be comparable to similar measures presented by other entities. For more information on forward-looking information, the assumptions made, and the risks and uncertainties which could cause actual results to differ from the anticipated results, and reconciliations of non-GAAP measures to the most closely related GAAP measures, refer to TransCanada’s 2014 Annual Report filed with Canadian securities regulators and the U.S. Securities and Exchange Commission and available at TransCanada.com. Our Strategic Priorities Ensuring our $59-billion asset base operates safely, efficiently and generates maximum value for shareholders. Successful completion of $12 billion in small to medium-sized capital projects by the end of 2017 and $34 billion of commercially secured large-scale projects by the end of the decade. Capturing additional low-risk opportunities that contribute to earnings growth in the short, medium and long-term. Maintain our financial strength and flexibility to grow our dividend and continue to prudently fund our industry-leading capital program. Front Cover: Completion of the US$600-million extension of the Tamazunchale Pipeline in Mexico demonstrated TransCanada’s expertise in engineering, project management and commitment to responsible development. Our Vision To be the leading energy infrastructure company in North America, focusing on pipeline and power generation opportunities in regions where we have or can develop a significant competitive advantage.
TransCanada 2014 01 Net Income per Share – Basic (dollars) 2.5 2.0 1.5 1.0 0.5 2010 2011 2012 2013 2014 1.79 2.17 1.84 2.46 2.42 Comparable Earnings per Share (1) (dollars) 2.5 2.0 1.5 1.0 0.5 2010 2011 2012 2013 2014 1.96 2.22 1.89 2.42 2.24 Dividends Declared per Share (dollars) 2.0 1.6 1.2 0.8 0.4 2010 2011 2012 2013 2014 1.60 1.68 1.76 1.92 1.84 Net Income attributable to common shares: $1.7 billion or $2.46 per share Comparable earnings: $1.7 billion or $2.42 per share (1) Comparable earnings before interest, taxes, depreciation and amortization: $5.5 billion (1) Funds generated from operations: $4.3 billion (1) Capital expenditures, equity investments and acquisitions: $4.9 billion Common share dividends declared: $1.92 per share financial highlights 2014 We have invested over $40 billion in new assets since 2000 and our shareholders have been rewarded with an average annual return of 15 per cent. letter to shareholders A message from President and CEO Russ Girling and Board Chair Barry Jackson pg 03 map and listings A visual overview of our facilities and new projects across North America pg 08 strategy and competitive advantage We are delivering value to our shareholders and moving ahead with unprecedented growth pg 10 focus on safety Maximizing the value of our assets requires operational excellence pg 11 committed to responsible development We are raising the bar on our performance in order to meet society’s rising expectations pg 12 natural gas pipelines Reinforcing our position as one of North America’s leading natural gas transmission providers pg 14 liquids pipelines Earnings continue to grow as we develop a leading hydrocarbon liquids transportation system pg 16 energy A diverse portfolio of power generation assets pg 18 positioned for success The stage is set for significant growth in shareholder value over the long-term pg 20 financial information Management’s discussion and analysis pg 21 Financial statements and notes pg 121 Supplementary information pg 183 (1) Non-GAAP measures do not have any standardized meaning prescribed by U.S. generally accepted accounting principles (GAAP). For more information see Non-GAAP measures in the Management’s Discussion and Analysis of the 2014 Annual Report.
02 TransCanada 2014 Capital Spending, Equity Investments and Acquisitions (millions of dollars) 5,500 4,400 3,300 2,200 1,100 2010 2011 2012 2013 2014 5,131 4,854 3,464 3,162 4,973 Funds Generated from Operations (1) (millions of dollars) 4,500 3,600 2,700 1,800 900 2010 2011 2012 2013 2014 3,161 3,451 3,284 4,268 4,000 Common Shares Outstanding – Average (millions of shares) 750 600 450 300 150 2010 2011 2012 2013 2014 691 702 705 708 707 Market Price – Close Toronto Stock Exchange (dollars) 60 48 36 24 12 2010 2011 2012 2013 2014 37.99 44.53 47.02 57.10 48.54 Net Income Attributable to Common Shares (millions of dollars) 2,000 1,600 1,200 800 400 2010 2011 2012 2013 2014 1,712 1,743 1,299 1,526 1,233 Comparable Earnings (1) (millions of dollars) 2,000 1,600 1,200 800 400 2010 2011 2012 2013 2014 1,584 1,715 1,330 1,559 1,357 Comparable EBITDA (1) (millions of dollars) 6,000 4,800 3,600 2,400 1,200 2010 2011 2012 2013 2014 4,859 5,521 4,245 4,544 3,686 Liquids Pipelines 4,250km (2,600 miles) Natural Gas Pipelines 68,000km (42,100 miles) 368 billion cubic feet (bcf) gas storage capacity $59billion in Assets 10,900 megawatts (MW) generating capacity 19 Power Generation Facilities TransCanada at-a-glance United States 1,914 employees, in 35 states Mexico 135 employees, in 7 states Canada 4,010 employees, in 7 provinces People and Places: 6,059 employees
TransCanada 2014 03 letter to shareholders Energy – it is essential to our modern way of life. Whether it’s the refined oil used to move our vehicles and make the endless consumer products we use every day, the natural gas that heats our homes and fuels our industry, or the electricity that lights our cities and powers our telecommunications, the world’s appetite for affordable energy supplies continues to grow. At the same time, efforts to improve energy efficiency and reduce environmental impacts are presenting new opportunities and challenges for companies like TransCanada that are dedicated to delivering the energy the world needs, safely and reliably. A Solid Foundation Building on more than 60 years of experience, TransCanada is playing a central role in developing North America’s energy future, as new technology has unlocked oil and gas supplies that are paving the way toward energy self-sufficiency and the ability to export our energy products to meet the needs of overseas markets. Our diverse asset base of natural gas and liquids pipelines, gas storage and power generation facilities provides a solid foundation to realize our vision of becoming North America’s leading energy infrastructure company. 2014 was a year of many accomplishments for TransCanada, as we resolved a number of outstanding issues facing our existing business over the last few years, successfully advanced several of our new pipeline and power generation projects and captured more high-quality growth opportunities across the continent. We have created a platform that is expected to transform our company by the end of this decade and drive significant value for shareholders. Russ Girling has been president & CEO for the past four years, leading the development of an unprecedented capital growth plan. Russ Girling president and chief executive officer S. Barry Jackson chair of the board Barry Jackson has served as the chair of TransCanada’s Board of Directors since 2002 and has held senior management positions in the oil and gas industry since 1974.
04 TransCanada 2014 Positioned for Growth While 2015 may be challenging for North America’s energy industry as enterprises throughout the value chain adjust to lower oil and gas prices, TransCanada is well positioned for this environment thanks to our prudent approach and long-term perspective. This includes ensuring all our assets meet fundamental energy needs that transcend short-term price volatility, along with the additional stability of securing the majority of our existing assets and growth projects under long-term contracts with strong investment-grade counterparties or regulated business models. Our $46-billion capital program is largely comprised of a diversified mix of natural gas and liquids pipeline projects across Canada, the United States and Mexico backed by either long-term, take-or-pay contracts that average 20 years or more, or a traditional cost-of-service model. This stability buffers an energy infrastructure company like TransCanada from the current volatility of world oil prices, providing predictability and stability for our investors, customers and shareholders. Even more important is ensuring our existing $59-billion asset base operates safely and reliably, allowing it to deliver the energy people need and value for our shareholders for decades. Layer in a focus of continuing to capture future growth opportunities while maintaining the company’s financial strength and flexibility, and you have a strong sense of our overall plan. Delivering Results The Board of Directors and TransCanada’s executive leadership team firmly believe that our strategy is working and it best positions the company to deliver long-term value to investors by generating significant, sustainable growth in earnings, cash flow and dividends. The results bear that out: Since 2000, our shareholders have realized an average annual total return of 15 per cent including an annual dividend that has increased every year, from $0.80 to $1.92 in 2014. Over the last 15 years, we have grown our asset base from $26 billion to $59 billion and have developed an enviable footprint in Canada, the United States and Mexico. At the same time, we have maintained or improved our top-quartile standings when it comes to the safety and reliability of our assets. Our base business performed well in 2014 supplemented by new assets that came online and began contributing increased earnings and cash flow. Comparable earnings were $2.42 per share, an eight per cent increase over last year. Funds generated from operations were $4.3 billion, a seven per cent increase from 2013. Earnings and cash flow from our existing asset base, coupled with the $12 billion in short to medium-term growth projects we have underway, provide the confidence in predictable earnings and cash flow growth that supported the board’s decision to increase the quarterly dividend by eight per cent for the first quarter of 2015 to $0.52, which is equivalent to $2.08 on an annual basis. “It’s clear our strategy is working because it has produced results for our shareholders in the form of an average total annual return of 15 per cent since 2000.“ RUSS GIRLING President and CEO
TransCanada 2014 05 Maximizing Our Assets Our top priority continues to be an unwavering focus on maximizing the value of our $59 billion in assets, ensuring they operate safely, efficiently and are being used to their full potential. We moved forward by successfully repositioning some of our key long-haul natural gas pipeline systems that have been under pressure from changing market dynamics in recent years. The longevity of the ANR Pipeline in the United States was secured through long-term commitments that fully contract its Southeast Main Line to move natural gas from the Marcellus and Utica regions to key market destinations for an average term of 23 years. The restructuring of the Canadian Mainline’s tolling and service model has resulted in a significant increase in long-term contracts on the system and allowed us to collect our revenue requirement and incentive earnings for the system over the past two years. In November, the National Energy Board (NEB) approved the settlement reached with our largest Mainline shippers – local natural gas distribution companies in Ontario and Québec – that sets the stage for long-term stability and new expansions on the eastern end of the system. Over the course of the year, we placed $3.8 billion of new assets into service. In January, the Gulf Coast extension of the Keystone Pipeline System began commercial service, delivering crude oil from the market hub at Cushing, Oklahoma to refineries in Port Arthur, Texas. That was followed by $300 million of expansions on our NGTL System beginning operation and the completion of the US$600-million Tamazunchale Extension project in Mexico. We also took possession of another four solar generation facilities in Ontario as they began producing emission-free electricity under 20-year contracts with the Independent Electricity System Operator (IESO), bringing our total solar capacity to 76 MW, enough to power more than 12,000 homes. To support the funding of our capital program, we progressed our plans to sell our remaining U.S. natural gas pipelines to our master limited partnership, TC PipeLines, LP. In October, we sold our remaining 30 per cent interest in the Bison Pipeline and in November announced our intention to drop down our remaining 30 per cent interest in the GTN Pipeline. We believe our master limited partnership has the capacity to complete more than US$1 billion per year in asset purchases, and we are committed to vending in our remaining U.S. natural gas pipeline assets over the next several years in order to help fund our ambitious capital growth plan. letter to shareholders “TransCanada’s board and executive leadership team are firmly committed to delivering long-term value to investors through significant and sustainable growth in future cash flow, earnings and dividends.” BARRY JACKSON Chair of the Board
06 TransCanada 2014 Advancing New Projects Notable progress was made in 2014 on our portfolio of commercially secured growth projects, which now totals $46 billion including $12 billion in small to medium-sized projects that are expected to drive earnings and cash flow growth as they come on stream through 2017. Our business development teams captured approximately $7 billion in new pipeline opportunities throughout the year, while our project management groups advanced several key projects through the permitting phases and into construction. Our $34-billion portfolio of large-scale projects moved forward with important stakeholder engagement work and advancements in their respective regulatory processes. More than 18 months of field work and discussion with Aboriginal groups, landowners, communities and governments culminated in filing the application for the $12-billion Energy East Pipeline project with the NEB in October. In British Columbia, extensive environmental assessment and public consultation work resulted in both the Coastal GasLink and Prince Rupert Gas Transmission projects receiving environmental certifications. Despite our best efforts to obtain a Presidential Permit, the Keystone XL Pipeline project moved into its seventh year of regulatory review in 2014. This delay has increased the cost of the project to approximately US$8 billion but TransCanada and our shippers remain firmly committed to building the pipeline and appreciate the support of the majority of Americans who also believe it is in the nation’s best interest. The Right People Renewal and development of our people is critical to achieving our goals and is a continuing process. At the heart of TransCanada’s competitive advantage are our 6,000 employees and we owe our success to the fact that we have a highly talented and diverse workforce. The board and senior management are confident in our employees’ experience and expertise to deliver on our growth plans and commitment to being operationally excellent in everything they do. Our goal is to maintain the high quality of our work by instilling decades of valuable knowledge in our younger leaders and embedding our foundational values of Integrity, Responsibility, Collaboration and Innovation in all of our employees. Change is also underway on our Board of Directors, where we have had six retirements since early 2012. Most recently, Thomas Stephens retired in the spring of 2014 after many years of service to shareholders. Siim Vanaselja joined last year, bringing extensive financial, governance, management and risk experience, and has proven to be an invaluable addition to the board. We are pleased to report that two of our more experienced directors, Paule Gauthier and Derek Burney, have agreed to stand for nomination for one more year in spite of having reached the usual retirement age. Their continued guidance and contributions in their areas of personal expertise have been critical as we move our $46-billion capital program forward. Liquids Pipelines $25b Natural Gas Pipelines $20b Energy $1b $46b Capital Growth Plan Our $46 billion growth plan includes approximately $12 billion in small to medium-sized projects through 2017 and approximately $34 billion in commercially secured medium to large-scale projects for completion by the end of the decade.
TransCanada 2014 07 A Recognized Leader: TransCanada aims to be on the industry’s leading edge of corporate social responsibility and sustainable practices. In 2014, our dedication did not go unnoticed: • Received a score at the 88th percentile on the Dow Jones Sustainability Index, and earned rankings on the DJSI North America and World indices. • Awarded a top score for our actions to disclose carbon emissions and our strategy to mitigate the business risks of climate change with the CDP (formerly the Carbon Disclosure Project). • Landed a spot on Canada’s Top 100 Corporate R&D Spenders list by Research Infosource Inc., Canada’s source of R&D intelligence. • Shortlisted for best overall governance by the Canadian Society of Corporate Secretaries and consistently ranked in the top 10 per cent by other governance assessments. • Received the Governance, Risk Management and Compliance (GRC) 20/20 Value Award, an acknowledgment for excellence in adapting financial audit software to improving internal project processes. We would like to take this opportunity to thank all our employees and shareholders for continuing to support TransCanada. 2014 was a year of major progress for us and we have very ambitious plans to continue to grow your company. We have the assets, opportunity and people to make those plans a reality. As we grow, we will continue to provide the safe, reliable energy that millions of families across North America rely on every day – and for many decades to come. We are committed to continuing to generate significant shareholder returns for those who have placed their confidence in our ability to deliver results. Russ Girling Barry Jackson President & Chief Chair of Executive Officer the Board letter to shareholders
08 TransCanada 2014 TransCanada Today
TransCanada 2014 09 Natural Gas Pipelines Canadian Pipelines 1 NGTL System 2 Canadian Mainline 3 Foothills 4 Trans Quebec & Maritimes (TQM) U.S. Pipelines 5 ANR Pipeline 5a ANR Regulated Natural Gas Storage 6 Bison 7 Gas Transmission Northwest (GTN) 8 Great Lakes 9 Iroquois 10 North Baja 11 Northern Border 12 Portland 13 Tuscarora 14 TC Offshore Mexican Pipelines 15 Guadalajara 16 Tamazunchale Under Construction 17 Mazatlan Pipeline 18 Topolobampo Pipeline In Development 19 Alaska LNG Pipeline 20 Coastal GasLink 21 Prince Rupert Gas Transmission 22 North Montney Mainline 23 Merrick Mainline 24 Eastern Mainline Liquids Pipelines Canadian / U.S. Pipelines 25 Keystone Pipeline System 26 Cushing Marketlink Under Construction 27 Houston Lateral 28 Houston Terminal 29 Keystone Hardisty Terminal 30 Grand Rapids Pipeline 31 Northern Courier Pipeline In Development 32 Bakken Marketlink 33 Keystone XL 34 Heartland Pipeline 35 TC Terminals 36 Energy East Pipeline 37 Upland Pipeline Energy Canadian - Western Power 38 Bear Creek 39 Carseland 40 Coolidge 1 41 Mackay River 42 Redwater 43 Sheemess PPA 44 Sundance A PPA 44 Sundance B PPA Canadian - Eastern Power 45 Becancour 46 Cartier Wind 47 Grandview 48 Halton Hills 49 Portlands Energy 50 Ontario Solar (8 Facilities) Bruce Power 51 Bruce A 51 Bruce B U.S. Power 52 Kibby Wind 53 Ocean State Power 54 Ravenswood 55 TC Hydro Unregulated Natural Gas Storage 56 CrossAlta 57 Edson Under Construction 58 Napanee 1 Located in Arizona, results reported in Canadian - Western Power
10 TransCanada 2014 strategy and competitive advantage Over the past 15 years we have chosen to focus on three lines of business, giving us both investment diversity and important geographic overlap that has resulted in shared technical, stakeholder and operating expertise in each of our core markets. This has also allowed us to realize material efficiencies in terms of operating costs and financial synergies. With $46 billion in commercially secured capital projects planned from now until the end of the decade, we are aiming to transform the company by nearly doubling the asset base to more than $90 billion by 2020. Virtually all of the revenue streams from these facilities are secured by long-term contracts or regulated cost-of-service business models, a prudent approach that positions us to weather the uncertainties of market cycles over the long-term. Sticking to our strategy has paid off. Since 2000, our common shares have provided a 15 per cent average annual total shareholder return. A stable and growing dividend has contributed to this performance. The Board of Directors has raised the dividend every year, from $0.80 per share in 2000 to $2.08 in 2015. Looking forward, the stage has been set for unprecedented growth that will enable TransCanada to become North America’s pre-eminent energy infrastructure company and deliver superior total returns to our shareholders. Our existing operations provide a solid foundation to help fund our capital program and underpin dividend growth going forward. Incremental contributions from $3.8 billion of assets we placed into service helped increase earnings and cash flow in 2014. Over the next three years, we have $12 billion in small to medium-sized growth projects that are expected to generate predictable growth in earnings, cash flow and dividends. TransCanada invests more than $1 billion every year in proactive maintenance and integrity programs to ensure our assets operate safely and reliably. TransCanada’s pipelines are monitored around the clock in our Operation Control Centres by highlytrained operators using the most sophisticated equipment available. * Annualized based on first quarter declaration (1) Compound Annual Growth Rate TransCanada’s occupational and facility safety records continue to be among the best in the industry. 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015E $0.80 $0.90 $1.00 $1.08 $1.16 $1.22 $1.28 $1.36 $1.44 $1.52 $1.60 $1.68 $1.76 $1.84 $1.92 7% CAGR (1) $2.08* Track Record of Dividend Growth
TransCanada 2014 11 focus on safety large photo: Practice is important: We conducted more than 100 emergency response exercises across North America in 2014 to ensure our employees, contractors and community partners are prepared in the unlikely event of a safety incident at our facilities. Zerois real NO SAFETY INCIDENTS ARE ACCEPTABLE. OUR GOAL OF ZERO INCIDENTS IS REAL AND WE WILL NOT BE SATISFIED UNTIL WE ACHIEVE IT. reliability Maximizing the value of our pipelines and power facilities means ensuring they are designed, constructed and operated safely and reliably every day. Our company’s priority is to make sure that our employees and contractors make it home safe and that our neighbours see us as a responsible and trusted member of the community. Our goal is simple: Deliver world-class projects and operations by consistently achieving the right results, the right way. Realizing this goal as we grow requires us to consider the entire life cycle of our assets in a disciplined and organized way, embedding a culture of safety and quality in everything we do. It also requires us to set aggressive performance targets and hold ourselves accountable for achieving consistent and repeatable results for safety, quality, reliability and compliance. That’s why we have implemented a number of new programs and business processes that are designed not just to improve our own performance, but to improve our industry as a whole. Our occupational and facility safety records continue to be among the best in the industry, but we recognize that no safety-related incidents are acceptable. We will not be satisfied until we reach our ultimate goal of zero incidents. That is why we will invest more than $1.5 billion in 2015 on integrity programs and preventative maintenance for our assets and continue to play a leadership role in key initiatives to continually improve the quality of construction across our industry. We are also at the forefront in adopting new technologies to enhance the safety and efficiency of our construction and operations, dedicating more than $80 million over the last five years towards research and development work with industry and government partners.
12 TransCanada 2014 committed to responsible development TransCanada has become a partner of choice for the large-scale energy infrastructure North America requires because of our strength and expertise in stakeholder relations, engineering, project management and operational excellence. 13years FOR THE 13TH YEAR IN A ROW, WE WERE INCLUDED IN THE DOW JONES SUSTAINABILITY WORLD INDEX. trust Stakeholder engagement on the Energy East Pipeline project has included more than 100 public open houses and extensive consultation with more than 7,000 community members, 5,500 landowners and 155 First Nations and Métis communities across six provinces.
TransCanada 2014 13 We know that completing $46 billion in capital projects will not be easy, as new energy projects are faced with rising stakeholder expectations and greater public scrutiny than ever before. The standards for developing pipelines, power generation facilities and other critical energy infrastructure have never been higher. But we are up for the challenge of raising the bar on our performance and setting the highest standards for our industry as we bring our plans to life on time and on budget. Significant Milestones Achieved We achieved significant milestones on many of these projects in 2014, including filing the application for the Energy East Pipeline project with the NEB. The Energy East application is the most comprehensive regulatory application in our company’s history and was the result of more than 18 months of planning, fieldwork and stakeholder engagement that involved extensive consultation with more than 7,000 community members, 5,500 landowners and 155 First Nations and Métis communities across six provinces. Our natural gas pipeline projects in British Columbia made tremendous progress with environmental assessment work, stakeholder engagement and Aboriginal consultation that led to both projects receiving Environmental Assessment Certificates in late 2014. And we began construction on several of our new Alberta crude oil pipeline and terminal facilities after receiving approval from the Alberta Energy Regulator. World-class operations, a deep commitment to safety and doing the right thing when it comes to dealing with the thousands of landowners, Aboriginal groups, community leaders, local businesses and stakeholders we interact with are critical to our success. We demonstrate these qualities every day as we safely deliver 20 per cent of the continent’s natural gas supply, move one-fifth of Canada’s crude oil exports to U.S. markets and generate enough electricity for 11 million homes. Focus on Corporate Social Responsibility Relying on our track record is not enough, however. We have devoted significant resources to identifying the most important issues facing our company and developing more rigorous programs to track our performance and minimize risk. This has led to greater consistency and transparency in our Corporate Social Responsibility (CSR) reporting, which has been recognized by external CSR rating agencies. For the 13th year in a row, we were included in the Dow Jones Sustainability World Index and in 2014 we regained a place on their North America Index. We were also recognized as a leader for disclosing our carbon emissions and our strategy for mitigating the business risks of climate change by the London-based CDP (formerly the Carbon Disclosure Project). We have operated our assets across North America for decades. Our employees and their families are an active part of the communities where they live and work. That’s why we view the important work of building and maintaining long-term relationships as a cornerstone of our business. We work from the ground up by engaging directly with the people who are involved in our projects, listening closely to their needs and concerns and responding with positive solutions. These relationships support public confidence in our business, allowing us to continue providing the energy our society needs while meeting the needs of our customers into the future. At TransCanada, we are committed to protecting the environment, not just because we have to, but because we want to. It’s about doing what’s right. TransCanada is committed to treating landowners with integrity and respect. We work to develop fair, honest relationships and maintain open communication throughout the lifecycle of all our projects. We collaborate with national and local organizations to conserve important habitat, protect species at risk and educate the public about the importance of the environment. large photo: This land near David City, Nebraska returned to producing healthy crops in 2010, one year after construction of the Keystone Pipeline.
14 TransCanada 2014 As one of the continent’s largest natural gas transporters, we will be an essential player in meeting the need for new and improved infrastructure, beginning with $20 billion in commercially secured projects already in development. natural gas pipelines 20% WE SAFELY DELIVER 20 PER CENT OF ALL THE NATURAL GAS CONSUMED IN NORTH AMERICA EVERY DAY. In 2014, we placed $900 million of new facilities into service on our NGTL System and in Mexico – the two regions that make up the bulk of our short-term growth plan for natural gas pipelines. connect
TransCanada 2014 15 Natural gas pipelines continue to be TransCanada’s largest business. The enormous shifts that have occurred in North America’s natural gas market in recent years have presented opportunities and challenges for our systems, but the transformational changes we’ve made to our asset base in response to changing supply and demand patterns will ensure our existing pipelines will prosper over the long haul. At the same time, we have also secured significant growth opportunities to connect the abundant natural gas supplies from the continent’s shale basins to new and existing markets at home and abroad. Renewed Stability and Growth The restructuring of the Canadian Mainline’s tolling framework has resulted in greater stability and competitiveness for the Mainline system through a settlement we reached with the three major local distribution companies in Ontario and Québec that the NEB approved in late 2014. The settlement will enhance access of northeastern U.S. natural gas production to markets served by TransCanada facilities and provides long-term stability for the Mainline system over the next 15 years. It also facilitates $500 million in new capital projects to add needed capacity in the Eastern Triangle region while ensuring we can recover our system-wide costs. We also moved forward with significant expansion to the southern arm of the Eastern Triangle, filing an NEB application for the $1.5-billion Eastern Mainline project that will add capacity in the Toronto-to-Ottawa corridor to ensure the markets in southern Ontario and Québec continue to have abundant supplies of natural gas into the future. The addition of 245 kilometres (km) of new pipe under the Eastern Mainline project will allow us to convert approximately 3,000 km of Mainline facilities that are not fully contracted to crude oil service for the Energy East Pipeline project. Doing so will help to reduce costs and increase stability for gas shippers, while continuing to ensure that eastern Canadians have the gas supply they need to heat their homes, schools and hospitals. Long-Term Commitments Similarly, the future of our ANR Pipeline in the United States was enhanced through long-term commitments to move almost two billion cubic feet per day of natural gas from the Marcellus and Utica regions to key market destinations for an average term of 23 years. This included support for a program to reverse the flow on ANR’s Southeast Main Line to enable more natural gas to move south to the Gulf Coast, where markets are experiencing a resurgence of demand for industrial use and planned liquefied natural gas (LNG) export terminals. This successful recontracting ensures the ANR Pipeline will be used to its full potential and provides a solid base to explore further expansions to transport growing gas supplies to key North American markets. In 2014, we placed $900 million of new facilities into service on our NGTL System and in Mexico, the two regions that make up the bulk of our short-term growth plan for natural gas pipelines. The NGTL System saw $300 million in new assets begin operation, and another $4.8 billion of new investment is expected by the end of 2017. NGTL continues to be the primary gathering system for Alberta and northeastern British Columbia, moving growing production from the Duvernay, Montney and Horn River plays. In Mexico, the US$600-million extension of the Tamazunchale Pipeline over extremely rugged terrain demonstrated our expertise in engineering and project management. Looking forward, the Topolobampo and Mazatlan projects will double our Mexican assets to US$2.6 billion by 2016 and we are competing for more projects as the country shifts towards using more natural gas for electricity generation and industrial growth. Further on the horizon, TransCanada is helping to bring British Columbia’s plans to develop a West Coast LNG export industry to life. We have been successful in reaching agreements with several First Nations in northern British Columbia and our teams will continue to build relationships and have meaningful discussions with those living along our pipeline routes to ensure they realize long-term benefits from the historic opportunity that LNG development represents for these communities. The Prince Rupert Gas Transmission and Coastal GasLink projects are underpinned by leading international energy companies that have yet to make final investment decisions on their respective LNG developments. Both projects are expected to be in service by the end of the decade. TransCanada operates a network of 68,000 km (42,100 miles) of natural gas pipeline; enough to circle the earth 1.7 times. The future of the ANR Pipeline has been secured through long-term commitments to move natural gas from the Marcellus and Utica regions to key market destinations. TransCanada operates $27 billion of natural gas pipeline assets in Canada, the United States and Mexico. A 235-km (146-mile) extension to the Tamazunchale Pipeline began service in November 2014. large photo: TransCanada is North America’s third-largest gas storage provider with 368 billion cubic feet capacity.
16 TransCanada 2014 1/5 THE KEYSTONE PIPELINE SYSTEM TRANSPORTS ONE-FIFTH OF CANADA’S CRUDE OIL EXPORTS TO THE UNITED STATES. liquids pipelines Liquids pipelines are the largest pillar of TransCanada’s growth plan, with $25 billion in new projects underpinned by long-term contracts in development for completion by the end of the decade. deliver Our history of operating natural gas and liquids pipelines in Alberta has been instrumental in capturing $3.6 billion in new investments to move growing crude oil production in the province.
TransCanada 2014 17 We are developing an enviable position in the liquid hydrocarbon transportation business as we move forward with our strategy of connecting key producing areas in Canada and the United States to domestic and international refinery markets. Our Keystone Pipeline System is proving to be a valuable platform for growth, while our experience in repurposing underutilized natural gas pipeline facilities is helping to meet the growing need for crude oil transportation across the continent. EBITDA Surpasses $1 Billion Keystone has safely transported more than 830 million barrels of crude oil from Canada to U.S. markets since it began operation in July 2010. With the completion of the Gulf Coast extension in January 2014, the system now provides a direct route for our shippers from Hardisty, Alberta to Gulf Coast refineries at Port Arthur, Texas. This resulted in the EBITDA contribution from Keystone surpassing $1 billion in 2014. Our Keystone Pipeline System will extend its market reach even further in 2015 with the completion of the Houston Lateral and Terminal project. Our history of operating natural gas and liquids pipelines in Alberta has been instrumental in capturing $3.6 billion in new investments to move growing crude oil production within the province. These projects will serve as an excellent base for our shippers to access various crude oil markets via Keystone and our proposed Keystone XL and Energy East projects. Construction commenced in the second half of 2014 on both the $1.5-billion Grand Rapids Pipeline and on the $900-million Northern Courier Pipeline following approval of both projects by the Alberta Energy Regulator. Committed to Keystone XL TransCanada and our shippers remain committed to Keystone XL despite the unprecedented delays we have faced on this much-needed project. We are pleased that the Final Supplemental Environmental Impact Statement issued by the Department of State at the end of January 2014 reinforced previous conclusions that Keystone XL will be built and operated with minimal impact on the environment. The report also reiterated the benefits of the project, noting that Keystone XL will enhance American energy security, create more than 40,000 jobs and generate billions of dollars in economic activity for the U.S. The Nebraska Supreme Court’s decision in early 2015 validated the pipeline’s route in the state, allowing the Department of State to complete its National Interest Determination process. We expect Keystone XL to begin service approximately two years after receiving a Presidential Permit that will allow the pipeline to cross the Canada-U.S. border. Energy East Moves Forward Our $12-billion Energy East Pipeline project has secured long-term take-or-pay contracts to ship approximately one million barrels per day of crude oil from western Canada to refineries and proposed marine terminals in eastern Canada. This innovative project that will repurpose more than 3,000 km of underutilized capacity on the Canadian Mainline continues to gain public support as Canadians recognize the benefits of enhancing market access for our valuable energy resources and eliminating eastern Canada’s reliance on imported crude oil. We filed an extensive application for the Energy East Pipeline project with the NEB at the end of October. Subject to regulatory approvals, we anticipate crude oil deliveries to begin by the end of 2018. Altogether, our list of commercially secured projects will transform the company. In addition to smaller-scale projects, bringing Keystone XL and Energy East to fruition will provide us with approximately 2.5 million barrels per day of long-haul capacity underpinned by approximately two million barrels per day of long-term contracts, establishing us as leaders in the transportation of liquid hydrocarbons. Construction is underway on the US$600 million Houston Lateral and Terminal project in Texas, employing members of local tribes to monitor for unanticipated sites of cultural significance. Listening to communities: The application for the Energy East Pipeline project reflected the input of thousands of landowners, Aboriginal groups and community members across six provinces. The Gulf Coast extension of the Keystone System provides a direct route for our shippers from Hardisty, Alberta to U.S. Gulf Coast refineries at Port Arthur, Texas. large photo: The hub of TransCanada’s liquids network is the Hardisty terminal in Alberta.
18 TransCanada 2014 11MMhomes TRANSCANADA OWNS OR HAS INTEREST IN 10,900 MEGAWATTS OF ELECTRICITY GENERATION ACROSS NORTH AMERICA, ENOUGH TO POWER APPROXIMATELY 11 MILLION HOMES. Our Energy business performed well in 2014, generating more than $1.3 billion in EBITDA thanks to the strong performance of the Bruce Nuclear facility in Ontario and our U.S.-based fleet of power generation facilities. energy We have critical mass in our core North American power markets and are well positioned to capture opportunities in the future. diversity
TransCanada 2014 19 We are Canada’s largest private sector power company, with interests in 10,900 MW of generating capacity, one-third of which comes from emission-less sources including nuclear, hydro, wind and solar. Our diverse portfolio of assets is comprised of 19 power generation facilities that are either underpinned by long-term contracts, are on the low end of the cost curve, or are otherwise supported by stable revenue streams. With facilities located in Alberta, eastern Canada, New England, Arizona and New York, our focus on maximizing earnings from this critical infrastructure is relentless. Our experience in these regions positions us well for the future, as new opportunities arise to keep pace with demand growth in these markets through the replacement of older facilities with new, less carbon-intense forms of electricity generation. Strong Performance Our Energy business performed well in 2014, generating more than $1.3 billion in EBITDA. Strong performance of the Bruce Nuclear facility in Ontario, where all eight reactors are in operation and providing approximately one-third of the province’s power supply, was coupled with similarly strong performance from our U.S.-based fleet. We also expanded our portfolio of renewable energy sources with four additional solar generation facilities in Ontario. The $1-billion Napanee Generating Station under development in Ontario obtained necessary permits for construction to commence in January 2015. This highly efficient, combined-cycle natural-gas-fired power plant will be located in the town of Greater Napanee and will be capable of generating 900 MW under a 20-year clean energy supply contract with the IESO. Growth Opportunities Alberta continues to be an attractive area for long-term investment with growing demand for power and more than 800 MW of coal-fired generation expected to come offline around the end of the decade as a portion of the coal fleet reaches the end of its useful life. We believe this will present opportunities to add new and replacement capacity in the latter half of the decade. We will continue to explore further opportunities for growth in markets where we have an established presence and a competitive advantage, either through development or acquisition. This includes consideration of further nuclear refurbishments in Ontario, capacity additions or replacements in the northeastern U.S. markets and consideration of new power generation facilities in Mexico where we have an established and growing corporate presence as this market continues to mature and evolve. The Bruce Nuclear facility in Ontario produces approximately one-third of the province’s power supply. Located in Queens, NY, the Ravenswood Generating Station is capable of providing more than 20 per cent of New York City’s electricity. TransCanada operates eight solar generating facilities in Ontario, supplying renewable power under a longterm contract. Fuel Sources One-third of the power we generate comes from emission-less sources. large photo: TransCanada has invested more than $5 billion in emissionless energy assets, including the Kibby wind facility in Maine. Natural Gas 51% Coal 15% Nuclear 23% Hydro 5% Wind 5% Solar 1% 10,900 MW
20 TransCanada 2014 Kristine Delkus Executive Vice-President and General Counsel Karl Johannson Executive Vice-President and President, Natural Gas Pipelines Russ Girling President and Chief Executive Officer Wendy Hanrahan Executive Vice-President, Corporate Services Bill Taylor Executive Vice-President and President, Energy Alex Pourbaix Executive Vice-President and President, Development Jim Baggs Executive Vice-President, Operations and Engineering Paul Miller Executive Vice-President and President, Liquids Pipelines Don Marchand Executive Vice-President and Chief Financial Officer positioned for success All the conditions are in place for TransCanada to generate significant value and shareholder returns in the years ahead. We have an enduring business strategy that has a proven track record over the past 15 years. We will remain focused on maximizing the value of our existing assets and executing on our $46-billion portfolio of commercially secured growth projects. And we will continue to pursue the low-risk organic growth opportunities generated from our expanding asset base across North America. Our strong balance sheet and credit ratings provide the financial flexibility to execute our ambitious growth plan, take advantage of new opportunities when and where they make sense and allow us to access significant capital on compelling terms at all points of the economic cycle. We will continue to evaluate funding alternatives and portfolio management to enhance shareholder returns, including following through on our commitment to sell our remaining U.S. natural gas pipeline assets to our master limited partnership, TC PipeLines, LP. Our goal is to maximize long-term shareholder value, with an unwavering focus on per-share performance. As we advance our portfolio of commercially secured capital growth projects through the end of the decade we expect to generate significant sustainable growth in earnings, cash flow and dividends. A strong balance sheet provides the financial strength and flexibility to execute our ambitious growth plan. executive leadership team
Management's discussion and analysis
This management's discussion and analysis (MD&A) contains information to help the reader make investment decisions about TransCanada Corporation. It discusses our business, operations, financial position, risks and other factors for the year ended December 31, 2014.
This MD&A should be read with our accompanying December 31, 2014 audited comparative consolidated financial statements and notes for the same period, which have been prepared in accordance with U.S. generally accepted accounting principles (GAAP).
Contents
TransCanada Management's discussion and analysis 2014 21
About this document
Throughout this MD&A, the terms, we, us, our and TransCanada mean TransCanada Corporation and its subsidiaries.
Abbreviations and acronyms that are not defined in the document are defined in the glossary on page 120.
All information is as of February 12, 2015 and all amounts are in Canadian dollars, unless noted otherwise.
FORWARD-LOOKING INFORMATIONWe disclose forward-looking information to help current and potential investors understand management's assessment of our future plans and financial outlook, and our future prospects overall.
Statements that are forward-looking are based on certain assumptions and on what we know and expect today and generally include words like anticipate, expect, believe,may, will, should, estimate or other similar words.
Forward-looking statements in this MD&A may include information about the following, among other things:
Forward-looking statements do not guarantee future performance. Actual events and results could be significantly different because of assumptions, risks or uncertainties related to our business or events that happen after the date of this MD&A.
22 TransCanada Management's discussion and analysis 2014
FOR MORE INFORMATIONSee Supplementary information beginning on page 183 for other consolidated financial information on TransCanada for the last five years.
You can also find more information about TransCanada in our annual information form and other disclosure documents, which are available on SEDAR (www.sedar.com).
TransCanada Management's discussion and analysis 2014 23
NON-GAAP MEASURESWe use the following non-GAAP measures:
These measures do not have any standardized meaning as prescribed by U.S. GAAP and therefore may not be similar to measures presented by other entities.
EBITDA and EBITWe use EBITDA as an approximate measure of our pre-tax operating cash flow. It measures our earnings before deducting financial charges, income tax, depreciation and amortization, net income attributable to non-controlling interests and preferred share dividends, and includes income from equity investments. EBIT measures our earnings from ongoing operations and is a useful measure of our performance and an effective tool for evaluating trends in each segment as it is equivalent to our segmented earnings.
Funds generated from operationsFunds generated from operations includes net cash provided by operations before changes in operating working capital. We believe it is a useful measure of our consolidated operating cash flow because it does not include fluctuations from working capital balances, which do not necessarily reflect underlying operations in the same period and is used to provide a consistent measure of the cash generating performance of our assets. See the Financial condition section for a reconciliation to net cash provided by operations.
24 TransCanada Management's discussion and analysis 2014
Comparable measuresWe calculate the comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period. These comparable measures are calculated on a consistent basis from period to period and are adjusted for specific items in each period, as applicable.
Our decision not to include a specific item is subjective and made after careful consideration. Specific items may include:
We calculate comparable earnings by excluding the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these unrealized changes in fair value do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.
TransCanada Management's discussion and analysis 2014 25
About our business
With over 60 years of experience, TransCanada is a leader in the responsible development and reliable operation of North American energy infrastructure including natural gas and liquids pipelines, power generation and natural gas storage facilities.
THREE CORE BUSINESSESWe operate our business in three segments – Natural Gas Pipelines, Liquids Pipelines and Energy. We also have a non-operational corporate segment consisting of corporate and administrative functions that provide support and governance to our operational business segments.
Our $59 billion portfolio of energy infrastructure assets meets the needs of people who rely on us to deliver their energy safely and reliably every day. We operate in seven Canadian provinces, 35 U.S. states and Mexico.
26 TransCanada Management's discussion and analysis 2014
TransCanada Management's discussion and analysis 2014 27
Common share priceat December 31
Common shares outstanding – average
28 TransCanada Management's discussion and analysis 2014
OUR STRATEGYOur energy infrastructure business is made up of pipeline and power generation assets that gather, transport, produce, store or deliver natural gas, crude oil and other petroleum products and electricity to support businesses and communities in North America.
Our vision is to be the leading energy infrastructure company in North America, focusing on pipeline and power generation opportunities in regions where we have or can develop a significant competitive advantage.
Key components of our strategy
A competitive advantageYears of experience in the energy infrastructure business and a disciplined approach to project and operational management and capital investment give us our competitive edge.
• Strong leadership: scale, presence, operating capabilities and strategy development; expertise in regulatory, legal, commercial and financing support.
• High quality portfolio: a low-risk business model that maximizes the full-life value of our long-life assets and commercial positions.
• Disciplined operations: highly skilled in designing, building and operating energy infrastructure; focus on operational excellence; and a commitment to health, safety and the environment are paramount parts of our core values.
• Financial positioning: excellent reputation for consistent financial performance and long-term financial stability and profitability; disciplined approach to capital investment; ability to access sizable amounts of competitively priced capital to support our growth; stable and growing master limited partnership that complements our funding program; ability to balance an increasing dividend on our common shares while preserving financial flexibility to fund industry-leading capital program in all market conditions.
• Long-term relationships: long-term, transparent relationships with key customers and stakeholders; clear communication of our value to equity and debt investors – both the upside and the risks – to build trust and support.
TransCanada Management's discussion and analysis 2014 29
CAPITAL PROGRAMWe are developing quality projects under our long-term capital program. These long-life infrastructure assets are supported by long-term commercial arrangements with creditworthy counterparties or regulated business models and are expected to generate significant growth in earnings and cash flow.
Our capital program consists of $12 billion of small to medium-sized, shorter-term projects and $34 billion of commercially secured large-scale, medium and longer-term projects. Amounts presented exclude the impact of foreign exchange and capitalized interest.
All projects are subject to cost adjustments due to market conditions, route refinement, permitting conditions, scheduling and timing of regulatory permits.
30 TransCanada Management's discussion and analysis 2014
2014 FINANCIAL HIGHLIGHTSWe use certain financial measures that do not have a standardized meaning under GAAP because we believe they improve our ability to compare results between reporting periods and enhance understanding of our operating performance. Known as non-GAAP measures, they may not be similar to measures provided by other companies.
HighlightsComparable EBITDA (comparable earnings before interest, taxes, depreciation and amortization), comparable EBIT (comparable earnings before interest and taxes), comparable earnings, comparable earnings per common share and funds generated from operations are all non-GAAP measures. See page 24 for more information about the non-GAAP measures we use and page 112 for a reconciliation to their GAAP equivalents.
TransCanada Management's discussion and analysis 2014 31
Consolidated results
Net income attributable to common shares
Net income attributable to common shares in 2014 was $1,743 million (2013 – $1,712 million; 2012 – $1,299 million). The following specific items were recognized in net income in 2012 to 2014:
2014
2013
32 TransCanada Management's discussion and analysis 2014
2012
The items discussed above were excluded from comparable earnings for the relevant periods. Certain unrealized fair value adjustments relating to risk management activities are also excluded from comparable earnings. The remainder of net income is equivalent to comparable earnings. A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.
Reconciliation of net income to comparable earnings
TransCanada Management's discussion and analysis 2014 33
Comparable earnings
Comparable earnings in 2014 were $131 million higher than in 2013, an increase of $0.18 per share.
The increase in comparable earnings was primarily the net result of:
Comparable earnings in 2013 were $254 million higher than 2012, an increase of $0.35 per share.
The increase in comparable earnings was the net result of:
34 TransCanada Management's discussion and analysis 2014
Cash flows
Funds generated from operations Funds generated from operations were 7 per cent higher this year compared to 2013 primarily for the same reasons comparable earnings were higher, as described above.
Funds used in investing activities
Capital spending1
We invested $4.4 billion in capital projects in 2014 as part of our ongoing capital program which was consistent with our revised outlook in our third quarter 2014 report to shareholders. Our capital program is a key part of our strategy to optimize the value of our existing assets and develop new, complementary assets in high demand areas that are expected to generate stable, predictable earnings and cash flows and to maximize returns to shareholders for years to come.
Equity investments and acquisitions In 2014, we invested $256 million in our equity investments primarily related to the construction of Grand Rapids. We also spent $241 million on the acquisition of four additional solar facilities from Canadian Solar Solutions Inc.
TransCanada Management's discussion and analysis 2014 35
Balance sheetWe continue to maintain a strong balance sheet while growing our total assets by $10.6 billion since 2012. At December 31, 2014, common equity represented 38 per cent (40 per cent in 2013) of our capital structure. See page 91 for more information about our capital structure.
DividendsWe increased the quarterly dividend on our outstanding common shares by eight per cent to $0.52 per share for the quarter ending March 31, 2015 which equates to an annual dividend of $2.08 per share. This is the 15th consecutive year we have increased the dividend on our common shares.
Dividend reinvestment plan Under our dividend reinvestment plan (DRP), eligible holders of TransCanada common or preferred shares can reinvest their dividends and make optional cash payments to buy additional TransCanada common shares.
Quarterly dividend on our common shares $0.52 per share (for the quarter ending March 31, 2015)
Annual dividends on our preferred shares
Series 1 $0.821
Series 2 $0.692
Series 3 $1.00
Series 5 $1.10
Series 7 $1.00
Series 9 $1.06
Cash dividends
Refer to the Results section in each business segment and the Financial condition section of this MD&A for further discussion of these highlights.
36 TransCanada Management's discussion and analysis 2014
OUTLOOK
EarningsWe anticipate earnings in 2015 to be higher than 2014, mainly due to the net effect of the following:
Earnings will also be impacted by additional Corporate segment items including increased AFUDC reflecting continued growth and capital spending primarily on Topolobampo, Mazatlan, the NGTL System and Energy East.
Results from our U.S. businesses are subject to fluctuations in foreign exchange rates. These fluctuations are largely offset by interest on our U.S. dollar denominated debt as well as our hedging activities which are included in our Corporate segment.
Natural Gas Pipelines Earnings from the Natural Gas Pipelines segment are affected by regulatory decisions and the timing of these decisions. Earnings are also impacted by market conditions, which drive the level of demand and the rate, we secure for our services.
Canadian Mainline earnings are anticipated to be lower in 2015 primarily as the result of the 2015 – 2030 Tolls and Tariff Application approved by the NEB in November 2014. These lower earnings are expected to be largely offset by growth in the NGTL System investment base as we connect new natural gas supply in northeastern B.C. and western Alberta and respond to growing demand in the oil sands market in northeast Alberta.
U.S. and International Gas Pipelines earnings are expected to be higher in 2015 primarily due to new long-term contracts for ANR originating from the Utica/Marcellus shale plays.
Earnings from our existing Mexican pipeline operations are expected to be consistent with 2014.
Liquids Pipelines Earnings in 2015 from the Liquids Pipelines segment are not expected to be significantly different than 2014. We continue to seek further operational efficiencies which would, depending on market demand, improve capacity and flows on the Keystone Pipeline System.
Over time, Liquids Pipelines' earnings will increase as projects currently in development are placed in service.
Energy Earnings in the Energy segment are generally maximized by maintaining and optimizing the operations of our power plants and through various marketing activities. Although a significant portion of Energy's output is sold under long-term contracts, output that is sold under shorter-term arrangements or at spot prices will continue to be affected by fluctuations in commodity prices.
Western Power earnings are anticipated to be lower in 2015 as a result of changing market conditions. Despite continued robust power demand in Alberta, exclusive of any market supply challenges, new supply additions in 2015 are expected to result in downward pressure on spot prices.
Eastern Power earnings in 2015 are expected to be higher as a result of a full year of operations from the additional solar assets acquired in 2014 as well as higher contractual earnings at Bécancour.
Bruce Power equity income is expected to be lower primarily due to the increased planned maintenance activity and higher operating costs.
TransCanada Management's discussion and analysis 2014 37
U.S. Power earnings are anticipated to increase as a result of higher net energy margins and production partially offset by lower capacity prices for Ravenswood as a result of new supply entering the market in 2015.
Natural Gas Storage earnings are expected to be slightly lower in 2015 with fewer opportunities to realize shorter-term gas cycling gains such as those realized during periods of extreme volatility in 2014.
Consolidated capital spending and equity investmentsWe expect to spend approximately $6 billion in 2015 on new and existing capital projects. The 2015 capital spending relates to Natural Gas Pipeline projects including NGTL System expansion, the Canadian Mainline, Topolobampo, and Mazatlan; Liquids Pipeline projects including Grand Rapids, Northern Courier, Energy East and Heartland; and Energy projects including Napanee.
38 TransCanada Management's discussion and analysis 2014
Natural Gas Pipelines
Our natural gas pipeline network transports natural gas to local distribution companies, power generation facilities and other businesses across Canada, the U.S. and Mexico. We serve more than 80 per cent of the Canadian demand and approximately 15 per cent of the U.S. demand on a daily basis by connecting major natural gas supply basins and markets through:
We also have regulated natural gas storage facilities in Michigan with a total capacity of 250 Bcf, making us one of the largest providers of natural gas storage and related services in North America.
TransCanada Management's discussion and analysis 2014 39
40 TransCanada Management's discussion and analysis 2014
TransCanada Management's discussion and analysis 2014 41
42 TransCanada Management's discussion and analysis 2014
RESULTSThe following is a reconciliation of comparable EBITDA and comparable EBIT (our non-GAAP measures) to segmented earnings (the equivalent GAAP measure).
Natural Gas Pipelines segmented earnings in 2014 increased by $306 million compared to 2013 and included $9 million related to the gain on sale of Gas Pacifico/INNERGY in November 2014 whereas the year ended December 31, 2013 included $42 million related to the 2012 impact of the NEB 2013 Decision. These amounts have been excluded in our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT which, along with comparable EBITDA, are discussed below.
TransCanada Management's discussion and analysis 2014 43
Canadian Pipelines
Net income and comparable EBITDA for our rate-regulated Canadian Pipelines are primarily affected by our approved ROE, our investment base, the level of deemed common equity, carrying charges owed to shippers on the Canadian Mainline Tolls Stabilization Account (TSA), and incentive earnings. Changes in depreciation, financial charges and income taxes also impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenue on a flow-through basis.
Canadian Mainline's comparable earnings this year increased by $23 million compared to 2013 because of higher incentive earnings, partially offset by higher carrying charges owed to shippers on the positive TSA balance and a lower average investment base. Among other things, the NEB 2013 Decision set out an ROE of 11.50 per cent on deemed common equity of 40 per cent for the years 2012 through 2017. Net income of $361 million recorded in 2013 included $84 million related to the 2012 impact of the NEB 2013 Decision, which was excluded from comparable earnings. Comparable earnings in 2013 were $90 million higher than 2012 because of the impact of the NEB 2013 Decision which approved incentive earnings and a higher ROE. The ROE used to record earnings in 2012 was 8.08 per cent on 40 per cent deemed common equity.
Net income for the NGTL System was $2 million lower in 2014 compared to 2013. The decrease in net income was due to increased OM&A costs at risk under the terms of the 2013-2014 NGTL Settlement approved by the NEB in November 2013, partially offset by a higher average investment base. The settlement included an ROE of 10.10 per cent on deemed common equity of 40 per cent and included annual fixed amounts for certain OM&A costs. Net income in 2013 was $35 million higher than 2012 because of a higher average investment base and a higher ROE. In 2012, the NGTL System was operating under the 2010-2012 Settlement which had
44 TransCanada Management's discussion and analysis 2014
an ROE of 9.70 per cent on deemed common equity of 40 per cent and included an annual fixed amount for certain OM&A costs.
Comparable EBITDA and EBIT for the Canadian pipelines reflect the variances discussed above as well as variances in depreciation, financial charges and income tax which are substantially recovered in revenue on a flow-through basis and, therefore, do not have a significant impact on net income.
U.S. and International PipelinesEBITDA for our U.S. operations is affected by contracted volume levels, actual volumes delivered and the rates charged, as well as by the cost of providing services, including OM&A and other costs as well as property taxes.
ANR is also affected by the level of contracting and the determination of rates driven by the market value of its storage capacity, storage related transportation services, and incidental commodity sales. ANR's pipeline and storage volumes and revenues are generally higher in the winter months because of the seasonal nature of its business.
Comparable EBITDA for the U.S. and International Pipelines was US$90 million higher in 2014 than 2013. This was due to the net effect of:
Comparable EBITDA for the U.S. and International Pipelines was US$119 million lower in 2013 than 2012. This was due to the net effect of:
Comparable depreciation and amortizationComparable depreciation and amortization was $50 million higher in 2014 than in 2013 mainly because of a higher rate base for the NGTL System. Depreciation and amortization was $80 million higher in 2013 than in 2012 mainly because of a higher rate base for the NGTL System, as well as the impact of the Mainline NEB 2013 Decision discussed above.
Business developmentIn 2014, business development expenses were $18 million lower than 2013 due to a change in scope on the Alaska project and lower administrative costs, partially offset by higher spending on Mexican projects. Business development expenses were $6 million higher in 2013 compared to 2012 mainly due to a change in scope on the Alaska project. See page 54 for further discussion on Alaska.
TransCanada Management's discussion and analysis 2014 45
Earnings Earnings for Canadian Pipelines are affected most significantly by changes in investment base, ROE and regulated capital structure, and also by the terms of toll settlements or other toll proposals approved by the NEB.
For 2015, the Canadian Mainline will operate under the terms of the 2015 – 2030 Tolls and Tariff Application, the fundamentals of which were approved by the NEB in November 2014. The terms of the application decision include a lower ROE of 10.10 per cent on deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax contribution through tolls from us. As a result, we expect Canadian Mainline 2015 earnings to be lower than 2014.
We expect the NGTL System investment base to continue to grow as we connect new natural gas supply in northeastern B.C. and western Alberta and respond to rising demand in the oil sands market in northeastern Alberta. We expect the growing investment base to have a positive impact on NGTL System earnings in 2015.
We also anticipate a modest level of investment in our other Canadian rate-regulated natural gas pipelines, but expect the average investment bases of these pipelines to continue to decline as annual depreciation outpaces capital investment, reducing their year-over-year earnings.
Under the current regulatory model, earnings from Canadian rate-regulated natural gas pipelines are not materially affected by short-term fluctuations in the commodity price of natural gas, changes in throughput volumes or changes in contracted capacity levels.
U.S. Pipelines
Earnings U.S. Pipeline earnings are affected by the level of contracted capacity and the rates charged to customers. Our ability to recontract or sell capacity at favourable rates is influenced by prevailing market conditions and competitive factors, including alternatives available to end use customers in the form of competing natural gas pipelines and supply sources, in addition to broader macroeconomic conditions that might impact demand from certain customers or market segments. Earnings are also affected by the level of OM&A and other costs, which includes the impact of safety, environmental and other regulator's decisions.
Many of our U.S. natural gas pipelines are backed by long-term take-or-pay contracts that are expected to deliver stable and consistent financial performance. ANR and Great Lakes have had more commercial exposure from transportation and storage contract renewals in recent years, which resulted in reduced earnings in 2013 and 2014 as transportation and storage values were depressed to historically low levels.
ANR has secured new long term contracts and extended terms at maximum recourse rates for significant volumes originating from the Utica/Marcellus shale plays with contract start dates from late 2014 through late 2015. We continue to seek opportunities to expand upon this success along with those opportunities associated with continued growth in end use markets for natural gas. In addition, ANR and Great Lakes are examining commercial, regulatory and operational changes to continue to optimize their position in response to positive developments in supply fundamentals. As a result, we expect 2015 earnings from our U.S. Pipelines to increase slightly from 2014.
Mexican PipelinesThe 2015 earnings for our current operating assets in Mexico are expected to be consistent with 2014 due to the nature of the long-term contracts applicable to our Mexican pipeline systems.
Capital spendingWe spent a total of $2.1 billion in 2014 for our natural gas pipelines in Canada, the U.S. and Mexico, and expect to spend $3.4 billion in 2015 primarily on the NGTL System expansion projects, the Topolobampo and
46 TransCanada Management's discussion and analysis 2014
Mazatlan pipelines in Mexico and Canadian Mainline capacity projects. See page 105 for further discussion on liquidity risk.
UNDERSTANDING THE NATURAL GAS PIPELINES BUSINESSNatural gas pipelines move natural gas from major sources of supply to locations or markets that use natural gas to meet their energy needs.
Our natural gas pipeline business builds, owns and operates a network of natural gas pipelines in North America that connects locations where gas is produced or interconnects with other pipelines to end customers such as local distribution companies, power generation facilities, industrial operations and other pipeline interconnects or end-users. The network includes pipelines that are buried underground and transport natural gas under high pressure, compressor stations that act like pumps to move the large volumes of natural gas along the pipeline and meter stations that record the amount of natural gas coming on the network at receipt locations and leaving the network at delivery locations.
Regulation of tolls and cost recoveryOur natural gas pipelines are generally regulated in Canada by the NEB, in the U.S. by the FERC and in Mexico by the CRE. The regulators approve construction of new pipeline facilities and ongoing operations of the infrastructure.
Regulators in Canada, the U.S. and Mexico allow us to recover costs to operate the network by collecting tolls, or payments, for services. Costs of operating the systems include a return on our capital invested in the assets or rate base, as well as the recovery of the rate base over time through depreciation. Other costs recovered include OM&A costs, income and property taxes, and interest on debt. The regulator reviews our costs to ensure they are prudent and approves tolls that provide us a reasonable opportunity to recover them.
Within their respective jurisdictions, the FERC and CRE approve maximum transportation rates. These rates are cost based and are designed to recover the pipeline's investment, operating expenses and a reasonable return for our investors. As the pipeline operator within these jurisdictions, we may negotiate lower rates with shippers.
Sometimes we enter into agreements or settlements with our shippers for tolls and cost recovery, which may include mutually beneficial performance incentives. The regulator must approve a settlement, including performance incentives, for it to be put into effect.
Generally, Canadian natural gas pipelines request the NEB to approve the pipeline's cost of service and tolls once a year, and recover or refund the variance between actual and expected revenues and costs in future years. The Canadian Mainline, however, operates under a fixed toll arrangement for its longer-term firm transportation services and has the flexibility to price its shorter-term and interruptible services in order to maximize its revenue.
The FERC does not require U.S. interstate pipelines to calculate rates annually, nor do they allow for the collection or refund of the variance between actual and expected revenue and costs into future years. This difference in U.S. regulation puts our U.S. pipelines at risk for the difference in expected and actual costs and revenues between rate cases. If revenues no longer provide a reasonable opportunity to recover costs, we can file with the FERC for a new determination of rates, subject to any moratorium in effect. Similarly, the FERC may institute proceedings to lower tolls if they consider the return on the capital invested to be too high.
Our Mexican pipelines have approved tariffs, services and related rates. However, most of the contracts underpinning the construction and operation of the facilities in Mexico are long-term 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.
TransCanada Management's discussion and analysis 2014 47
Business environment and strategic prioritiesThe North American natural gas pipeline network has developed to connect supply to market. Use and growth of this infrastructure is affected by changes in the location and relative cost of natural gas supplies as well as changes in the location of markets and level of demand.
We have a significant pipeline footprint in the WCSB and transport approximately 75 per cent of total WCSB production to markets within and outside of the basin. Our pipelines also source natural gas, to a lesser degree, from the other major basins including the Appalachian (Utica and Marcellus), Rockies, Williston, Haynesville, Fayetteville and Anadarko as well as the Gulf of Mexico.
Increasing supply The WCSB spans almost all of Alberta and extends into B.C., Saskatchewan, Yukon and Northwest Territories and is Canada's primary source of natural gas supply. The WCSB is currently estimated to have 150 trillion cubic feet of remaining conventional resources and a technically accessible unconventional resource base of over 700 trillion cubic feet. The total recoverable WCSB resource base has recently more than quadrupled with the advent of technology that can economically access unconventional gas areas in the basin. Production from the WCSB increased slightly in 2014 after decreasing every year since 2007 and is expected to continue to increase over the next several years. The Montney and Horn River shale play formations and the Liard basin in northeastern B.C. are also part of the WCSB and have recently become a significant source of natural gas. We expect production from the Montney play that is currently just under 3 Bcf/d, to grow to approximately 6 Bcf/d by 2020, depending on the economics of exploration and production compared to other, mainly U.S., sources and the progress of proposed B.C. west coast LNG exports.
48 TransCanada Management's discussion and analysis 2014
The primary sources of natural gas in the U.S. are the U.S. shale areas, Gulf of Mexico and the Rockies. The U.S. shales are the biggest area of growth which we estimate will meet almost 50 per cent of the overall North American gas demand by 2020. The largest shale developments for natural gas are the Utica/Marcellus basins in the northeast U.S. These basins have grown from essentially no production prior to 2008 up to 16 Bcf/d at the end of 2014. They are forecast to grow to 25 Bcf/d by 2020. Other natural gas supply from shale in the U.S. includes the Haynesville, Barnett, Eagle Ford and Fayetteville plays.
The overall supply of natural gas in North America is forecast to increase significantly over the next decade (by almost 20 Bcf/d or 22 per cent by 2020), and is expected to continue to increase over the long term for several reasons:
The development of shale gas basins that are located close to existing markets, particularly in the northeast U.S., has led to an increase in the number of supply choices and is expected to change historical gas pipeline flow patterns, generally from long-haul, long-term firm contracted capacity to shorter-distance, shorter-term contracts. Along with our competitors, we are restructuring our tolls and service offerings to capture this growing northeast supply and North American demand.
The Canadian Mainline is well positioned to offer optionality of supply to eastern Canadian and northeast U.S. markets, while still ensuring the opportunity to recover our costs including a return on the investment for both existing and new infrastructure as required.
Growing northeast supply has had a positive impact for both the Mainline, with new proposed facilities in eastern Canada, and our ANR U.S. pipeline assets, with significant new long-term contracts for service. The increase in supply in northeastern B.C. has created opportunities for us to plan and build, subject to regulatory approval and a positive final investment decisions (FID), new large pipeline infrastructure on the NGTL System to move the natural gas to markets, including proposed LNG exports and growing Alberta market demand.
Changing demand The growing supply of natural gas has resulted in relatively low natural gas prices in North America, which have supported increased demand for natural gas particularly in the following areas:
Natural gas producers continue to progress opportunities to sell natural gas to global markets, which involves connecting natural gas supplies to new LNG export terminals which are proposed primarily along the west coast of B.C. and the U.S. Gulf of Mexico. Assuming the receipt of all necessary regulatory and other approvals, the proposed facilities along the west coast of B.C. are expected to become operational later in this decade. The U.S Gulf Coast also has several LNG export facilities in various stages of development or construction. LNG exports are expected to ramp up from this area, with initial deliveries beginning as early as late 2015. The demand created by the addition of these new markets creates opportunities for us to build new pipeline infrastructure and to increase throughput on our existing pipelines.
TransCanada Management's discussion and analysis 2014 49
Commodity Prices In general, the profitability of our gas pipelines business is not directly tied to commodity prices given we are a transporter of the commodity and the transportation costs are not tied to the price of natural gas. However, the cyclical supply and demand nature of commodities and its price impact can have an indirect impact on our business where our shippers may choose to accelerate or delay certain projects. This can impact the timing for the demand of transportation services and/or new gas pipeline infrastructure.
More competition Changes in supply and demand levels and locations have resulted in increased competition for transportation services throughout North America. Development of technology for shale gas supply basins that are closer to markets historically served by long-haul pipelines has resulted in changes to flow patterns of existing natural gas pipeline infrastructure that includes reversing direction of flow and different distances of haul, particularly with the large development of U.S. northeast supply. Along with other pipelines, we are restructuring our tolls and service offerings to capture this growing northeast supply and North American demand.
Strategic priorities We are focused on capturing opportunities resulting from growing natural gas supply, and connecting new markets, while satisfying increasing demand for natural gas within existing markets.We are also focused on adapting our existing assets to the changing gas flow dynamics.
The Canadian Mainline continued to be a focal point of our strategy in 2014. The cold 2013/14 winter coupled with the ability to price our discretionary services at market prices, resulted in a significant increase in long-haul firm transportation originating at Empress as well as increased revenue collection from the utilization of Mainline transportation services. The regulatory framework in place at the time did not allow us the opportunity to meet growing demand for new gas supplies to eastern Canada and recover the costs for those investments. As a result, an application for approval of 2015 to 2030 tolls was filed with the NEB based on the components reached in a settlement with the three major LDCs in Ontario and Québec. In November 2014, the NEB approved the application as filed (2015 – 2030 Tolls and Tariff Application). This approval sets the stage to advance capital projects in eastern Canada to meet the needs of our eastern Canada and northeast U.S. shippers seeking alternative supply sources. It also ensures a reasonable opportunity to recover the costs associated with our existing assets as well as those related to new pipeline investments.
In 2015, we will continue to advance the planned conversion of portions of the Canadian Mainline from natural gas service to crude oil service. The Energy East Pipeline is a planned project, subject to regulatory approval, to convert approximately 3,000 km (1,864 miles) of the Canadian Mainline from the Alberta border to a point in eastern Ontario, southeast of Ottawa, to crude oil service. We are committed to ensuring that our gas shipper community continues to receive transportation service to meet their firm service requirements.
The NGTL System is the major natural gas gathering and transportation system for the WCSB, connecting most of the natural gas production in western Canada to domestic and export markets. It faces competition for connection to supply, particularly in northeastern B.C., where the largest new source of natural gas has access to two other existing competing pipelines. Connections to new supply and new or growing demand continues to support new capital expansions of the NGTL System. We expect supply in the WCSB to grow from its current level of approximately 14 Bcf/d to approximately 16 Bcf/d by 2020. The NGTL System is well positioned to connect WCSB supply to meet expected demand for proposed LNG exports on the B.C. coastline. Obtaining the necessary regulatory approvals to extend and expand the NGTL System in northeastern B.C. to connect the Montney shale area was a key focus in 2014. A hearing process that examined the merits of our North Montney Pipeline project concluded in December 2014 and the NEB decision is expected by the end of April 2015.
50 TransCanada Management's discussion and analysis 2014
Our U.S. pipeline assets are positioned for further connections to growth in supply and markets for the following reasons:
Management expects to drop down our remaining U.S. natural gas pipeline assets into TC PipeLines, LP as a means of funding a portion of our capital growth program, subject to the approvals of TC PipeLines, LP's board and our board as well as market conditions.
Our focus in Mexico in 2015 is to advance the construction phase for the Mazatlan and Topolobampo pipelines and to continue operating our existing facilities safely and reliably. We continue to be very interested in the further development of natural gas infrastructure in Mexico and will work to advance future projects, that align with our strategic priorities.
SIGNIFICANT EVENTS
NGTL System We continue to experience significant growth on the NGTL System as a result of growing natural gas supply in northwestern Alberta and northeastern B.C. from unconventional gas plays and substantive growth in intra-basin delivery markets. This demand growth is driven primarily by oil sands development, gas-fired electric power generation and expectations of B.C. west coast LNG projects. This demand for NGTL System services is expected to result in approximately 4.0 Bcf/d of incremental firm services with approximately 3.1 Bcf/d related to firm receipt services and 0.9 Bcf/d related to firm delivery services. We will be seeking regulatory approvals in 2015 to construct new facilities to meet service requests of approximately 540 km (336 miles) of pipeline, seven compressor stations, and 40 meter stations that will be required in 2016 and 2017 (2016/17 Facilities). The estimated total capital cost for the facilities is approximately $2.7 billion.
Including the new 2016/17 Facilities, the North Montney Mainline, the Merrick Mainline, and other new supply and demand facilities, the NGTL System has approximately $6.7 billion of commercially secured projects in various stages of development.
North Montney Mainline The $1.7 billion North Montney Pipeline is a proposed extension and expansion of the NGTL System to receive and transport natural gas from the North Montney area of B.C. The hearing for the application before the NEB to build and operate this project concluded in December 2014. We expect the NEB to issue its report and recommendations for the project by the end of April 2015.
Merrick Mainline In 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 proposed Merrick Mainline will transport natural gas sourced through the NGTL System to the inlet of the proposed Pacific Trail Pipeline that will terminate at the Kitimat LNG Terminal at Bish Cove near Kitimat, B.C. The proposed project will be an extension from the existing Groundbirch Mainline section of the NGTL System beginning near Dawson Creek, B.C. to its end point near the community of Summit Lake, B.C. The $1.9 billion project will consist of approximately 260 km (161 miles) of 48-inch diameter pipe.
TransCanada Management's discussion and analysis 2014 51
Subject to the necessary approvals, which includes the regulatory approval from the NEB for us to build and operate the pipeline, and a positive final investment decision for the Kitimat LNG project, we expect the Merrick Mainline to be in service in first quarter 2020.
2015 Revenue Requirement Settlement We received NEB approval on February 2, 2015 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 10.10 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 administrative expense amount that is based on an escalation of 2014 actual costs.
Canadian Mainline
2015 – 2030 Tolls and Tariff Application On November 28, 2014, the NEB approved the Canadian Mainline's 2015 – 2030 Tolls and Tariff Application. The application reflected components of a settlement between the Canadian Mainline and the three major LDCs in Ontario and Québec. The approval of this application provides a long term commercial platform for both the Canadian Mainline and its shippers with a known toll design for 2015 to 2020 and certain parameters for a toll-setting methodology up to 2030. The platform balances the needs of our shippers while at the same time ensuring a reasonable opportunity to recover the capital from our existing facilities and any new facilities required to serve existing and new markets.
Highlights of the approved application include:
Eastern Mainline Project In October 2014, we filed an application seeking NEB approval to build, own and operate new facilities for our existing Canadian Mainline natural gas transmission system in southeastern Ontario (Eastern Mainline Project). The new facilities are a result of the proposed transfer of a portion of the Canadian Mainline capacity from natural gas service to crude oil service as part of our Energy East Pipeline and an open season that closed in January 2014. The $1.5 billion capital project will add 0.6 Bcf/d of new capacity in the Eastern Triangle segment of the Canadian Mainline and will ensure appropriate levels of capacity are available to meet the requirements of existing shippers as well as new firm service commitments. The project is contingent upon the Energy East Pipeline and is subject to regulatory approvals expected to be issued simultaneously with regulatory approvals for the Energy East Pipeline. The project is expected to be in service by second quarter 2017.
Other Canadian Mainline Expansions In addition to the Eastern Mainline Project, we have executed new short haul arrangements in the Eastern Triangle portion of the Canadian Mainline that require new facilities, or modifications to existing facilities with a total capital cost of approximately $475 million with expected in-service dates between November 1, 2015 and November 1, 2016. These projects are subject to regulatory approval and, once constructed, will provide capacity needed to meet customer requirements in eastern Canada.
52 TransCanada Management's discussion and analysis 2014
Sale of Bison Pipeline to TC PipeLines, LP In October 2014, we closed the sale of our remaining 30 per cent interest in Bison Pipeline LLC to our master limited partnership, TC PipeLines, LP, for cash proceeds of US$215 million.
Sale of GTN Pipeline to TC PipeLines, LP In November 2014, we announced an offer to sell the remaining 30 per cent interest in Gas Transmission Northwest LLC (GTN) to TC PipeLines, LP. Subject to the satisfactory negotiation of terms and TC PipeLines, LP's board approval, the transaction is expected to close in late first quarter 2015.
At December 31, 2014, we held a 28.3 per cent interest in TC PipeLines, LP for which we are the General Partner.
ANR Pipeline We have secured nearly 2.0 Bcf/d of firm natural gas transportation commitments for existing and expanded capacity on ANR Pipeline's Southeast Main Line (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 the SEML. Capital costs associated with the ANR System expansions required to bring the additional capacity to market are currently 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 is also assessing further demand from our customers to transport natural gas from the Utica/Marcellus formation, which is expected to result in incremental opportunities to enhance and expand the system.
Mexican Pipelines
Tamazunchale Pipeline Extension Construction of the US$600 million extension was completed November 6, 2014. Delays from the original service commencement date of March 9, 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.
Topolobampo and Mazatlan Pipelines Permitting, engineering, and construction activities are advancing as planned for these two northwest Mexico pipelines. The Topolobampo project is a 530 km (329 miles), 30-inch pipeline with a capacity of 670 MMcf/d and a cost of US$1 billion that will deliver gas to Topolobampo, Sinaloa from interconnects with third party pipelines in El Oro, Sinaloa and El Encino, Chihuahua in Mexico. The Mazatlan project is a 413 km (257 miles), 24-inch pipeline running from El Oro to Mazatlan within the state of Sinaloa with a capacity of 200 MMcf/d and an estimated cost of US$400 million. Both projects are supported by 25-year contracts with the CFE and are expected to be in service mid to late 2016.
International Gas Pipelines
Gas Pacifico/INNERGY sale In November 2014, we closed the sale of our 30 per cent equity interests in Gas Pacifico/INNERGY at a price of $9 million. This sale marks our exit from the Southern Cone region of South America.
TransCanada Management's discussion and analysis 2014 53
LNG Pipeline Projects
Coastal GasLink In October 2014, the B.C. Environmental Assessment Office issued an Environmental Assessment Certificate (EAC) for Coastal GasLink. In 2014, we also submitted applications to the B.C. Oil and Gas Commission (BC OGC) for the permits required under the Oil and Gas Activities Act to build and operate Coastal GasLink. Regulatory review of those applications is progressing on schedule, with permit decisions anticipated in first quarter 2015. We are currently continuing our engagement with Aboriginal groups and stakeholders along the pipeline route and are progressing detailed engineering and construction planning work to support the regulatory applications and refine the capital cost estimates. Pending the receipt of all required regulatory approvals and a positive FID from our customer, construction is anticipated in 2016, with an in-service date by the end of the decade. Should the project not proceed, our project costs (including AFUDC) are fully recoverable.
Prince Rupert Gas Transmission On November 25, 2014, we received an EAC from the B.C. Environmental Assessment Office. We have submitted our pipeline permit applications to the BC OGC for construction of the pipeline and anticipate receiving these permits in first quarter 2015.
We have 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 continue to work closely with First Nations and stakeholders along the proposed route to create and deliver appropriate benefits to all impacted groups. In October 2014, 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.
On December 3, 2014, our customer announced the deferral of an FID. We continue to work with our contractors to refine capital cost estimates for the project. Once the permitting process with the BC OGC is complete and Pacific NorthWest LNG secures the necessary regulatory approvals and proceeds with a positive FID, we will be in a position to begin construction. All costs would be fully recoverable should the project not proceed. The deferral of an FID past the end of 2014 has resulted in a deferral of the expected in-service date for the pipeline. The in-service date will depend on when our customer receives the necessary regulatory approvals and is in a position to make an FID.
Alaska In April 2014, the State of Alaska passed new legislation to provide a framework for us, the three major Alaska North Slope producers (ANS Producers), and the Alaska Gasline Development Corp. (AGDC) to advance the development of an LNG export project, which is believed to be the best opportunity to commercialize Alaska North Slope gas resources in current market conditions. In June 2014, we executed an agreement with the State of Alaska to abandon the previous 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 is anticipated to take two years to complete with our share of the cost to be approximately US$100 million. The precedent agreement also provides us with full recovery of development costs in the event the project does not proceed.
In July 2014, the ANS Producers filed an export permit application with the U.S. Department of Energy for the right to export 20 million tonnes per annum of liquefied natural gas for 30 years. In September 2014, the FERC approved the National Environmental Policy Act (NEPA) pre-file request jointly made by us, the three major ANS Producers and AGDC. This approval triggers the NEPA environmental review process, which includes a series of community consultations.
54 TransCanada Management's discussion and analysis 2014
BUSINESS RISKSThe following are risks specific to our natural gas pipelines business. See page 99 for information about general risks that affect the company as a whole, including other operational risks, health, safety and environment (HSE) risks, and financial risks.
WCSB supply for downstream connecting pipelinesAlthough we have diversified our sources of natural gas supply, many of our North American natural gas pipelines and transmission infrastructure assets depend largely on supply from the WCSB. We continue to monitor changes in the capital programs of our customers and how these changes may impact our project schedules.There is competition for this supply from several pipelines, demand within the basin and, in the future, demand for pipelines proposed for LNG exports from the west coast of B.C. An overall decrease in production and/or competing demand for supply, could impact throughput on WCSB connected pipelines that in turn could impact overall revenues generated. The WCSB has considerable reserves, but the amount actually produced depends on many variables, including the price of natural gas, basin-on-basin competition, downstream pipeline tolls, demand within the basin and the overall value of the reserves, including liquids content.
Market accessWe compete for market share with other natural gas pipelines. New supply basins being developed closer to markets we have historically served may reduce the throughput and/or distance of haul on our existing pipelines that may impact revenue. The long-term competitiveness of our pipeline systems and the avoidance of bypass pipelines will depend on our ability to adapt to changing flow patterns by offering alternative transportation services at prices that are acceptable to the market.
Competition for greenfield expansionWe face competition from other pipeline companies seeking opportunities to invest in greenfield natural gas pipeline development opportunities. This competition could result in fewer projects being available that meet our investment hurdles or projects that proceed with lower overall financial returns.
Demand for pipeline capacityDemand for pipeline capacity is ultimately the key driver that enables pipeline transportation services to be sold. Demand for pipeline capacity is created by supply and market competition, variations in economic activity, weather variability, natural gas pipeline and storage competition and pricing of alternative fuels. Renewal of expiring contracts, and the opportunity to charge and collect a toll that the market requires depends on the overall demand for transportation service. A change in the level of demand for our pipeline transportation services could impact revenues.
Commodity PricesThe cyclical supply and demand nature of commodities and related pricing can have a secondary impact on our business where our shippers may choose to accelerate or delay certain projects. This can impact the timing for the demand of transportation services and/or new gas pipeline infrastructure. As well, sustained low gas prices could impact our shippers' financial situation and their ability to meet their transportation service cost obligations.
Regulatory riskDecisions by regulators can have an impact on the approval, timing, construction, operation and financial performance of our natural gas pipelines. There is a risk that decisions are delayed or are not favourable and therefore could impact revenues and the opportunity to further invest capital in our systems. There is also risk of a regulator disallowing a portion of our prudently incurred costs, now or at some point in the future.
TransCanada Management's discussion and analysis 2014 55
The regulatory approval process for larger infrastructure projects, including the time it takes to receive a decision could be slowed or unfavorable due to the influence from the evolving role of activists and their impact on public opinion and government policy related to natural gas pipeline infrastructure development.
Increased scrutiny of operating processes by the regulator or other enforcing agencies has the potential to increase operating costs. There is a risk of an impact to income if these costs are not fully recoverable.
We continuously monitor regulatory developments and decisions to determine the possible impact on our gas pipelines business. We also work closely with our stakeholders in the development of rate, facility and tariff applications and negotiated settlements, where possible.
OperationalKeeping our pipelines operating safely and reliably is essential to the success of our business. Interruptions in our pipeline operations impact our throughput capacity and may result in reduced revenue and can affect corporate reputation as well as customer and public confidence in our operations. We manage this by investing in a highly skilled workforce, operating prudently, using risk-based preventive maintenance programs and making effective capital investments. We use internal inspection equipment to check our pipelines regularly, and repair or replace them whenever necessary. We also calibrate the meters regularly to ensure accuracy, and continuously maintain compression equipment to ensure safe and reliable operation.
56 TransCanada Management's discussion and analysis 2014
Liquids Pipelines
Our existing liquids pipeline infrastructure connects Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas, as well as connecting U.S. crude oil supplies from the Cushing, Oklahoma hub to refining markets in the U.S Gulf Coast. Our proposed future pipeline infrastructure would also connect Canadian and U.S. crude oil supplies to refining markets in eastern Canada and overseas export markets, expand Canadian and U.S. crude oil to U.S. markets and connect condensate supplies to U.S. and Canadian markets.
TransCanada Management's discussion and analysis 2014 57
58 TransCanada Management's discussion and analysis 2014
TransCanada Management's discussion and analysis 2014 59
Liquids Pipelines segmented earnings were $240 million higher in 2014 than in 2013 and $50 million higher in 2013 than in 2012. Liquids Pipelines segmented earnings are equivalent to comparable EBIT, which along with comparable EBITDA, are discussed below.
Comparable EBITDAComparable EBITDA for the Keystone Pipeline System was $307 million higher this year than in 2013. This increase was primarily due to:
Comparable EBITDA for the Keystone Pipeline System was $54 million higher in 2013 than in 2012. This increase reflected higher revenues primarily resulting from:
Comparable depreciation and amortizationComparable depreciation and amortization was $67 million higher in 2014 than in 2013 due to the Keystone Gulf Coast extension being placed in service.
60 TransCanada Management's discussion and analysis 2014
EarningsOur 2015 earnings are not expected to be significantly different than our 2014 earnings. We continue to seek further operational efficiencies which would, depending on market demand, improve capacity and flows on the Keystone Pipeline System.
Capital spendingWe spent a total of $2.0 billion in 2014 on capital spending in Liquids Pipelines. We expect to spend approximately $2.3 billion on capital spending and equity investments in 2015, primarily on Grand Rapids, Northern Courier, Energy East and Heartland. See page 105 for further discussion on liquidity risk.
UNDERSTANDING THE LIQUIDS PIPELINES BUSINESSIn general, pipelines move crude oil from major supply sources to refinery markets so the crude oil can be refined into various petroleum products.
We generate earnings from our liquids pipelines mainly by providing pipeline capacity to shippers in exchange for fixed monthly payments that are not linked to actual throughput volumes. Uncontracted capacity is offered to the market on a spot basis which provides opportunities to generate incremental earnings.
The terms of service and fixed monthly payments are determined by transportation service arrangements negotiated with shippers. These arrangements are typically long term, and provide for the recovery of costs we incur to construct and operate the system.
Business environment and strategic priorities
TransCanada Management's discussion and analysis 2014 61
Over the past decade, North American crude oil production has increased significantly in response to growth in global energy consumption and increased demand for crude oil. This growth in crude oil supply has increased the demand for new liquids pipeline infrastructure to connect these supplies to key North American and overseas markets. We have successfully secured a $25 billion portfolio of commercially secured projects to develop this infrastructure and we continue to pursue additional opportunities to expand our transportation service offerings to other areas of the value chain such as the long-term storage of liquids.
Recently, crude oil prices have declined sharply as continued growth in U.S. light oil supply, which has displaced North American imports, and growth in other global supplies has outpaced incremental demand. Although supplies from high cost production may be reduced if lower prices persist, our business is not expected to be significantly impacted by commodity price changes or supply reductions. Our existing operations and development projects are supported by long-term contracts where we have agreed to provide pipeline capacity to our customers in exchange for fixed monthly payments. The cyclical supply and demand nature of commodities and its price movements can have a secondary impact on our business where our shippers may choose to accelerate or delay certain new projects. This can impact the timing for the demand of transportation services and/or new liquids pipeline infrastructure.
Commodity price fluctuations are a normal part of the business cycle. Longer-term, we expect global demand for crude oil will continue to grow resulting in continued growth in North American crude oil supply production and demand for new pipeline infrastructure. Our growing position in the crude oil transportation business is creating a significant platform to capture these future growth opportunities.
Supply outlook
Canada Alberta produces the majority of the crude oil in the WCSB which is the primary source of crude oil supply for the Keystone Pipeline System. In its 2014 Crude Oil Forecast, Markets and Transportation report, the Canadian Association of Petroleum Producers (CAPP) estimated 2015 WCSB crude oil production of 1.4 million Bbl/d of conventional crude oil and condensate and 2.2 million Bbl/d of oil sands crude oil, a total of approximately 3.6 million Bbl/d. The report forecasted WCSB crude oil production will increase to 4.6 million Bbl/d by 2020 and to 6.4 million Bbl/d by 2030.
In a January 2015 press release, CAPP announced estimated 2015 industry capital spending in western Canada, including oil sands development, would decline to $46 billion, $23 billion lower than forecasted in 2014. CAPP forecasts a slowing in the growth of crude oil production from the 2014 Crude Oil Forecast, Markets and Transportation report by 65,000 Bbl/d in 2015 and 120,000 Bbl/d in 2016. Although CAPP anticipates a decrease in capital spending, the revised forecast for total western Canadian crude oil production is approximately 150,000 higher in 2015 than in 2014.
According to the May 2014 Alberta's Energy Reserves 2013 and Supply/Demand Outlook 2014-2023, the Alberta Energy Regulator (AER) estimated there is approximately 167 billion barrels of economically and technically recoverable conventional and oil sands reserves in Alberta. Oil sands projects have a long reserve life. It is estimated that a typical oil sands mine has a 25 to 50 year lifespan, while an in-situ operation will run 10 to 15 years on average. This longevity aligns with the producer's desire to secure long-term connectivity of their reserves to market. The Keystone Pipeline System, including Keystone XL, and the proposed Energy East Pipeline are underpinned by long term contracts.
U.S. According to the International Energy Agency World Energy Outlook 2014 Report, by 2020 the U.S. is set to surpass Saudi Arabia as the world's largest crude oil producer. The U.S. Energy Information Administration (EIA) projects over 1.0 million Bbl/d of U.S. production growth from 2014 to 2019, peaking at 9.6 million Bbl/d by 2019. Higher production volumes are mainly a result of recent advancements in shale oil production. EIA forecasts shale oil production peaking at approximately 4.8 million Bbl/d by 2020 and declining after 2022.
62 TransCanada Management's discussion and analysis 2014
U.S. shale oil supply growth is mainly originating from the Bakken formation of the Williston basin in North Dakota and Montana, the Permian basin in south Texas and Woodford shale area of the Arkoma basin in Oklahoma. These shale production areas also represent some of the sources of crude oil supply for our Bakken Marketlink and Cushing Marketlink projects.
Growing U.S. production has contributed to increased crude oil supply at the Cushing, Oklahoma market hub and resulted in increased demand for additional pipeline capacity between Cushing, Oklahoma and the U.S. Gulf Coast refining market. Cushing Marketlink, which use facilities that form part of the Keystone Pipeline System, provides pipeline capacity to transport growing crude oil supply at Cushing, Oklahoma to the U.S. Gulf Coast.
Even with growth in U.S. crude oil production, the EIA report predicts the U.S. will remain a net importer of crude oil, importing 7.7 million Bbl/d into 2040. Growing production in the west Texas Permian, south Texas Eagle Ford and Williston basins is primarily light crude oil and is expected to compete with light imports from countries such as Nigeria and Saudi Arabia. Gulf Coast refiners are expected to continue to prefer Canadian heavy crude oil because these refineries are mainly configured to process heavy and medium crude oil and cannot easily switch to processing the new light shale oil in large quantities without significant capital investments. Gulf Coast refineries currently require approximately 3.5 million Bbl/d of heavy and medium crude oil, and the level of demand is not expected to change significantly in the future. The Keystone Pipeline System is well positioned to deliver Canadian crude oil to this significant market.
Strategic prioritiesWe are focused on advancing our current portfolio of commercially secured projects to connect growing Canadian and U.S. crude oil supply to key markets.
Securing regulatory approval for our $12 billion Energy East Pipeline is a key priority. In 2014, we filed necessary regulatory applications for approval to construct and operate this project and we are actively engaged with stakeholders as we work towards securing regulatory approval. Refineries in eastern Canada currently process primarily light crude oil imported from west Africa and the Middle East, and therefore could process North American light crude oil. According to the 2014 Crude Oil Forecast, Markets and Transportationreport, total refining capacity in eastern Canada is approximately 1.2 million Bbl/d, and western Canada supplied only 354,000 Bbl/d to these eastern refineries. Due to insufficient pipeline capacity, many of these refineries have begun receiving domestic light crude oil in small quantities by rail at a cost significantly higher than the cost to ship by pipeline. This has created a significant demand for pipelines to connect eastern Canada with growing Bakken and WCSB light crude oil production. We anticipate that our Energy East Pipeline, once approved and constructed, will meet this demand.
We also remain fully committed to Keystone XL despite the unprecedented regulatory delays we have faced on this project. Keystone XL would expand the Keystone Pipeline System to provide more than 800,000 Bbl/d of additional capacity. This project is supported by long-term contracts and will transport crude oil from Canada as well as growing U.S. crude oil supplies to the large refining markets found in the American Midwest and along the U.S. Gulf Coast.
Within Alberta, we are leveraging our extensive natural gas pipeline footprint and experience to develop a regional liquids pipeline business. Growth in oil sands production is driving the need for new intra-Alberta pipelines, like our Grand Rapids Pipeline, that can move crude oil production from the source to market hubs at Edmonton/Heartland and Hardisty, Alberta as well as diluent from Edmonton/Heartland region to the production area in northern Alberta. The Heartland Pipeline and TC Terminals projects are intended to support these market hubs which will allow shippers the ability to connect with the Keystone Pipeline System, Energy East Pipeline and other pipelines that transport crude oil outside of Alberta to ultimately provide our customers with a contiguous seamless path from production to market.
As our liquids pipeline footprint continues to grow throughout North America, we are also pursuing other opportunities to expand our service offerings.These opportunities also include the development of rail transportation solutions, transportation of other liquids such as condensate, and the addition of terminal and liquids storage services to complement our existing infrastructure.
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Keystone Pipeline SystemThe completion of the Gulf Coast extension in January 2014 expanded the Keystone Pipeline System to a 4,247 km (2,639 miles) pipeline system that transports crude oil from Hardisty, Alberta, to markets in the U.S. Midwest and the U.S. Gulf Coast.
To date, the Keystone Pipeline System has delivered more than 830 million barrels of crude oil from Canada to the U.S.
Cushing MarketlinkConstruction was completed on the Cushing Marketlink facilities at Cushing, Oklahoma in September 2014. Cushing Marketlink transports crude oil from the market hub at Cushing, Oklahoma to the U.S. Gulf Coast refining market on facilities that form part of the Keystone Pipeline System.
Houston Lateral and TerminalConstruction continues on the 77 km (48 miles) Houston Lateral pipeline and tank terminal which will extend the Keystone Pipeline System to Houston, Texas refineries. The terminal is expected to have initial storage capacity for 700,000 barrels of crude oil. The pipeline and terminal are expected to be completed in the second half of 2015.
Keystone XLIn January 2014, the DOS released its Final Supplemental Environmental Impact Statement (FSEIS) for the Keystone XL project. The results included in the report were consistent with previous environmental reviews of Keystone XL. The FSEIS concluded Keystone XL is "unlikely to significantly impact the rate of extraction in the oil sands" and that all other alternatives to Keystone XL are less efficient methods of transporting crude oil, and would result in significantly more greenhouse gas emissions, oil spills and risks to public safety. The report initiated the National Interest Determination period of up to 90 days which involves consultation with other governmental agencies and provides an opportunity for public comment. In April 2014, the DOS announced that the national interest determination period has been extended indefinitely to allow them to consider the potential impact of the case discussed below on the Nebraska portion of the pipeline route.
In February 2014, a Nebraska district court ruled that the state Public Service Commission, rather than Governor Dave Heineman, has the authority to approve an alternative route through Nebraska for Keystone XL. Nebraska's Attorney General filed an appeal which was heard by the Nebraska State Supreme Court on September 5, 2014. On January 9, 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.
In September 2014, we filed a certification petition for Keystone XL with the South Dakota Public Utilities Commission (PUC). This certification confirms that the conditions under which Keystone XL's original June 2010 PUC construction permit was granted continue to be satisfied. The formal hearing for the certification is scheduled for May 2015.
On January 16, 2015, the DOS reinitiated the national interest review and requested the eight federal agencies, with a role in the review, to complete their consideration of whether Keystone XL serves the national interest and to provide their views to the DOS by February 2, 2015.
On February 2, 2015, the U.S. Environmental Protection Agency (EPA) posted a comment letter to its website suggesting that, among other things, the FSEIS issued by the DOS has not fully and completely assessed the environmental impacts of Keystone XL and that, at lower oil prices, Keystone XL may increase the rates of oil sands production and greenhouse gas emissions. On February 10, 2015, we sent a letter to the DOS refuting
64 TransCanada Management's discussion and analysis 2014
these and other comments in the EPA letter but also offering to work with the DOS to ensure it has all the relevant information to allow it to reach a decision to approve Keystone XL.
The timing and ultimate approval of Keystone XL remain uncertain. In the event the project does not proceed as planned, we would reassess and reduce its carrying value to its recoverable amount if necessary and appropriate.
The estimated capital costs for Keystone XL are expected to be approximately US$8.0 billion. As of December 31, 2014, we have invested US$2.4 billion in the project and have also capitalized interest in the amount of US$0.4 billion.
Keystone Hardisty TerminalThe Keystone Hardisty Terminal will be constructed in conjunction with Keystone XL and is expected to be completed approximately two years from the date the Keystone XL permit is received.
Energy East PipelineIn March 2014, we filed the project description for the Energy East Pipeline with the NEB. This was the first formal step in the regulatory process to receive the necessary approvals to build and operate the pipeline.
On October 30, 2014, we filed the necessary regulatory applications for approvals to construct and operate the Energy East Pipeline and terminal facilities with the NEB. The project is estimated to cost approximately $12 billion, excluding the transfer value of Canadian Mainline natural gas assets. Subject to regulatory approvals, the pipeline is anticipated to commence deliveries by the end of 2018.
The Energy East Pipeline includes a proposed marine terminal near Cacouna, Québec which would be adjacent to a beluga whale habitat. On December 8, 2014, the Committee on the Status of Endangered Wildlife in Canada recommended that beluga whales be placed on the endangered species list. As a result, we have made the decision to halt any further work at Cacouna and will be analyzing the recommendation, assessing any impacts to the project and reviewing all viable options. We intend to make a decision on how to proceed by the end of first quarter 2015.
The 1.1 million Bbl/d Energy East Pipeline received approximately one million Bbl/d of firm, long-term contracts to transport crude oil from western Canada that were secured during binding open seasons.
Northern Courier PipelineIn July 2014, the AER issued a permit approving our application to construct and operate the Northern Courier Pipeline. Construction has started on the $900 million, 90 km (56 miles) pipeline to transport bitumen and diluent between the Fort Hills mine site and Suncor Energy's terminal located north of Fort McMurray, Alberta. We currently expect the pipeline to be ready for service in 2017.
Heartland Pipeline and TC TerminalsThe Heartland Pipeline is a 200 km (125 miles) crude oil pipeline connecting the Edmonton/Heartland, Alberta market region to facilities in Hardisty, Alberta. TC Terminals is a terminal facility in the Heartland industrial area north of Edmonton, Alberta.
The pipeline could transport up to 900,000 Bbl/d, while the terminal is expected to have initial storage capacity for up to 1.9 million barrels of crude oil. In February 2014, the application for the terminal facility was approved and construction commenced in October 2014.
These projects together have a combined estimated cost of $900 million and are expected to be placed in service in late 2017.
Grand Rapids PipelineOn October 9, 2014, the AER issued a permit approving our application to construct and operate the Grand Rapids Pipeline. We have a partner through a joint venture, to develop Grand Rapids, a 460 km (287 miles) crude oil and diluent pipeline system connecting the producing area northwest of Fort McMurray, Alberta to
TransCanada Management's discussion and analysis 2014 65
terminals in the Edmonton/Heartland, Alberta region. Each partner will own 50 per cent of the $3 billion pipeline project, and we will be the operator. Our partner has also entered into a long-term transportation service contract in support of Grand Rapids. Construction has commenced with initial crude oil transportation planned in 2016.
Upland PipelineIn November 2014, we completed a successful binding open season for the Upland Pipeline. The $600 million pipeline would 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 2018. The commercial contracts we have executed for Upland Pipeline are conditioned on Energy East proceeding.
BUSINESS RISKSThe following are risks specific to our liquids pipelines business. See page 99 for information about general risks that affect the company as a whole, including other operational risks, health, safety and environment (HSE) risks, and financial risks.
OperationalOptimizing and maintaining availability of our liquids pipelines is essential to the success of our liquids pipelines business. Interruptions in our pipeline operations impact our throughput capacity and may result in reduced fixed payment revenues and spot volume opportunities. We manage this by investing in a highly skilled workforce, operating prudently, using risk-based preventive maintenance programs and making effective capital investments. We use internal inspection equipment to check our pipelines regularly and repair them whenever necessary.
RegulatoryDecisions by Canadian and U.S. regulators can have a significant impact on the approval, construction, operation and financial performance of our liquids pipelines. Public opinion about crude oil development and production may also have an adverse impact on the regulatory process. There are some individuals and interest groups that are expressing their opposition to crude oil production by lobbying against the construction of liquids pipelines. We manage this risk by continuously monitoring regulatory developments and decisions to determine their possible impact on our liquids pipelines business and by working closely with our stakeholders in the development and operation of the assets.
Execution, capital costs and permittingWe make substantial capital commitments in large infrastructure projects based on the assumption that the new assets will offer an attractive return on investment in the future. Under some contracts, we share the cost of these risks with customers. While we carefully consider the expected cost of our capital projects, under some contracts we bear capital cost risk which may impact our return on these projects. Our capital projects are also subject to permitting risk which may result in construction delays, increased capital cost and, potentially, reduced investment returns.
Crude oil supply and demand for pipeline capacityA decrease in demand for refined crude oil products could adversely impact the price that crude oil producers receive for their product. Lower prices for crude oil could mean producers may curtail their investment in the further development of crude oil supplies. Depending on their severity, these factors would negatively impact the opportunities we have to expand our crude oil pipeline infrastructure and, in the longer term, to re-contract with shippers as current agreements expire.
CompetitionAs we continue to develop a competitive position in the North American liquids transportation market to transport growing WCSB, Williston, Permian and Arkoma basins crude oil supplies to key North American refining markets and export markets, we face competition from other pipeline companies, and to a lesser extent, rail companies which also seek to transport these crude oil supplies to the same markets. Our success is dependent on our ability to offer and contract transportation services on terms that are market competitive.
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Energy
Our Energy business includes a portfolio of power generation assets in Canada and the U.S., and unregulated natural gas storage assets in Alberta.
We own, control or are developing approximately 11,800 MW of generation capacity powered by natural gas, nuclear, coal, hydro, wind and solar assets. Our power business in Canada is mainly located in Alberta, Ontario and Québec. Our power business in the U.S. is located in New York, New England, and Arizona. The assets are largely supported by long-term contracts and some represent low-cost baseload generation, while others are critically located, essential capacity.
We own and operate approximately 118 Bcf of unregulated natural gas storage capacity in Alberta and hold a contract with a third party for additional storage, in total accounting for approximately one-third of all storage capacity in the province. When combined with the regulated natural gas storage in Michigan (part of the Natural Gas Pipelines segment), we provide over 350 Bcf of natural gas storage and related services.
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68 TransCanada Management's discussion and analysis 2014
TransCanada Management's discussion and analysis 2014 69
70 TransCanada Management's discussion and analysis 2014
Energy segmented earnings were $62 million lower in 2014 than in 2013 and $534 million higher in 2013 than in 2012.
Energy segmented earnings included the following specific items:
The year over year variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our position for these particular derivatives over a certain period of time; however, they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impact of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them part of our underlying operations.
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The specific items noted above have been excluded in our calculation of comparable EBIT. The remainder of the Energy segmented earnings are equivalent to comparable EBIT, which along with comparable EBITDA, are discussed below.
Comparable EBITDA for Energy was $15 million lower in 2014 than in 2013. The decrease was the effect of:
72 TransCanada Management's discussion and analysis 2014
Comparable EBITDA for Energy was $460 million higher in 2013 compared to 2012. This increase was the effect of:
EarningsWe expect 2015 earnings from the Energy segment to be slightly lower than 2014, assuming the net effect of the following expectations:
Although a significant portion of Energy's output is sold under long-term contracts, revenue from power that is sold under shorter-term forward arrangements or at spot prices will continue to be impacted by fluctuations in commodity prices and changes in seasonal natural gas storage price spreads will impact Natural Gas Storage earnings.
Weather, unplanned outages and unforeseen regulatory changes can play a role in spot markets and can drive fluctuations in our Energy results.
Western Power2015 average spot power prices are expected to be slightly lower than 2014. The Alberta power market was relatively well supplied in 2014 and that trend is expected to be further entrenched in 2015 with the addition of a large gas-fired power plant in the Calgary area which is expected to be placed in service in first half 2015. Average spot market power prices in 2014 ($50/MWh) were much lower than 2013 ($80/MWh) primarily due to strong coal fleet availability and new wind generation capacity despite strong annual power demand growth of just over three per cent.
The Alberta Electric System Operator is forecasting healthy supply growth over the next 10 years in order to meet continued demand growth of over three per cent per year over the next 10 years. While some of this robust growth outlook in Alberta is underpinned by oil and gas activity and demand, it is also driven by the anticipated coal fleet turnover and need to replace other aging generation capacity being retired over time. We remain cautiously optimistic that the Alberta market will continue to outpace growth in other regions of North America.
Natural Gas StorageNatural gas price spreads are expected to modestly improve from cyclical lows, however, extreme gas price volatility experienced in first quarter 2014 is not expected to repeat in first quarter 2015. As a result, the 2015 segment contribution is expected to be slightly lower compared to 2014 results.
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Eastern PowerIn January 2015, the OPA and the Independent Electricity System Operator (IESO) merged and now operate as one organization which is continuing under the name IESO. This merger does not impact the terms of any of our contracts with the OPA.
All of our energy assets in eastern Canada are fully contracted. The Ontario assets are contracted with the IESO and are largely sheltered from spot market pricing. Eastern Power earnings in 2015 are expected to be higher as a result of a full year of operations from the additional solar assets acquired in 2014 as well as higher contractual earnings at Bécancour.
The Ontario power market is currently well supplied despite the fact that the coal-fired fleet is now fully retired. The combination of flat system demand growth, partly due to conservation programs and increased nuclear and renewable output, is enabling Ontario to be a net exporter of electricity.
Bruce PowerWe expect 2015 equity income from Bruce Power to be lower than 2014 primarily due to increased planned maintenance activity and higher costs at each of Bruce A and Bruce B. During second quarter 2015, all Bruce B units are expected to be removed from service for approximately one month to allow for inspection of the Bruce B vacuum building. The vacuum building is a key component of the site's safety systems and is required to be inspected approximately once every decade. Additional planned maintenance at Bruce B is scheduled to occur during second quarter 2015.
Planned maintenance at Bruce A is scheduled for first and third quarters of 2015.
Overall plant availability percentages in 2015 are expected to be in the mid 80s for Bruce A and Bruce B.
The Ontario government's 2013 Long-Term Energy Plan outlined their intentions on nuclear power's role in the fuel mix going forward. The potential refurbishment of six Bruce Power units was included within the plan and Bruce Power is actively considering the site's refurbishment options within this context.
U.S. PowerU.S. northeast markets experienced a colder than normal winter in 2014 with multiple polar vortex events and natural gas pipeline constraints causing high price volatility in the winter months. However, the summer months experienced below normal temperatures that reduced air conditioning power demand. In 2015, we expect to continue to experience price volatility in the winter months due to pipeline constraints; however, recent reductions in fuel oil prices are anticipated to keep peak price excursions limited compared to previous years. The New York and New England ISO forecasts growth in the demand for power of about one per cent per year in the coming years.
Our northeastern U.S. power facilities also earn significant revenues through participation in regional capacity markets. Capacity markets compensate power suppliers for being available to provide power, and as a result are intended to promote investment in new and existing power resources needed to meet customer demand and maintain a reliable power system. New York Spot capacity prices are on average expected to be lower in 2015 than 2014.
The timing of recognizing earnings from our U.S. power marketing business is impacted by different pricing profiles between the prices we charge our customers and the prices we pay for volumes purchased to fulfill our sales obligations over the term of the contracts. The costs on volumes purchased to fulfill power sales commitments to wholesale, commercial and industrial customers includes the impact of certain contracts to purchase power over multiple periods at a flat price. Because the price we charge our customers is typically shaped to the market, the impact of these two contract pricing profiles has generally resulted in higher earnings in January to March, offset by lower earnings between April and December with overall positive margins over the term of the contracts. Due to increased volatility of forward natural gas and power prices in the New England market, these timing differences will be more significant in 2015.
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Capital spendingWe spent a total of $0.2 billion in 2014, and expect to spend approximately $0.3 billion on capital spending in Energy in 2015. See page 105 for further discussion on liquidity risk.
Equity investments and acquisitionsIn 2014, we also invested $0.2 billion on the acquisition of four Ontario solar facilities and $0.1 billion in Bruce Power for capital projects. We expect to spend approximately $0.2 billion on Bruce Power investments in 2015.
UNDERSTANDING THE ENERGY BUSINESSOur Energy business is made up of three groups:
Energy comparable EBIT – contribution by group, excluding business development expenses year ended December 31, 2014
Power generation capacity – contribution by group year ended December 31, 2014 (includes facilities in development)
Western Power We own or have the rights to approximately 2,600 MW of power supply in Alberta and Arizona through three long-term PPAs, five natural gas-fired cogeneration facilities, and through Coolidge, a simple-cycle, natural gas peaking facility in Arizona.
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Earnings in the Western Power business are maximized by maintaining and optimizing the operations of our power plants, and through various marketing activities.
A disciplined operational strategy is critical to maximizing output and revenue at our cogeneration facilities and maximizing Coolidge earnings, where revenue is based on plant availability, and is not a function of market price.
The marketing function is critical for optimizing returns and managing risk through direct sales to medium and large industrial and commercial companies and other market participants. Our marketing group sells power sourced through the PPAs, markets uncommitted volumes from the cogeneration plants, and buys and sells power and natural gas to maximize earnings from our assets. To reduce exposure associated with uncontracted volumes, we sell a portion of our power in forward sales markets when acceptable contract terms are available.
A portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements. This ensures we have adequate power supply to fulfill our sales obligations if we have unexpected plant outages and provides the opportunity to increase earnings in periods of high spot prices.
The amount sold forward will vary depending on market conditions and market liquidity and has historically ranged between 25 to 75 per cent of expected future production with a higher proportion being hedged in the near term periods. Such forward sales may be completed with medium to large industrial and commercial companies as well as other market participants and will affect our average realized price (versus spot price) in future periods.
Eastern Power We own or are developing approximately 3,000 MW of power generation capacity in eastern Canada. All of the power produced by these assets is sold under long-term contracts.
Disciplined maintenance of plant operations is critical to the results of our Eastern Power assets, where earnings are based on plant availability and performance.
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Western and Eastern Power resultsComparable EBITDA and comparable EBIT are non-GAAP measures. See page 24 for more information.
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Sales volumes and plant availabilityIncludes our share of volumes from our equity investments.
Western Power Western Power's comparable EBITDA in 2014 was $103 million lower than in 2013, due to the net effect of:
Average spot market power prices in Alberta decreased by 38% from approximately $80/MWh in 2013 to approximately $50/MWh in 2014. Despite strong power demand growth of just over three per cent, ten of the twelve months of 2014 saw relatively soft price levels as the Alberta power market was well supplied during the year. Weather events in February 2014 and July 2014 tightened the supply demand balance resulting in strong prices during those months. Realized power prices on power sales can be higher or lower than spot market power prices in any given period as a result of contracting activities.
In 2013, Western Power's comparable EBITDA was $44 million higher than 2012. The increase was mainly due to higher purchased volumes under the PPAs following the return to service of Sundance A Units 1 and 2.
Approximately 75 per cent of Western Power sales volumes were sold under contract in 2014 compared to 72 per cent in 2013 and 85 per cent in 2012.
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Eastern Power Eastern Power's comparable EBITDA in 2014 was $28 million higher than 2013 due to the net effect of incremental earnings from the four solar facilities acquired in 2013, the additional four facilities acquired in late 2014 and higher contractual earnings at Bécancour.
In 2013, Eastern Power's comparable EBITDA was similar to 2012 due to the net effect of incremental earnings from Cartier Wind and from the four solar facilities acquired in 2013 and lower contractual earnings at Bécancour.
Bruce PowerBruce Power is a nuclear power generation facility located near Tiverton, Ontario and is comprised of Bruce A and Bruce B. Bruce A Units 1 to 4 have a combined capacity of approximately 3,000 MW and Bruce B Units 5 to 8 have a combined capacity of approximately 3,300 MW. Bruce B leases the eight nuclear reactors from Ontario Power Generation and subleases Units 1 to 4 to Bruce A.
Results from Bruce Power fluctuate primarily due to the frequency, scope and duration of planned and unplanned outages.
Under a contract with the IESO, all of the output from Bruce A is sold at a fixed price/MWh which is adjusted annually on April 1 for inflation and other provisions under the contract. Bruce A also recovers fuel costs from the IESO.
Under the same contract, all output from Bruce B Units 5 to 8 is subject to a floor price adjusted annually for inflation on April 1.
Amounts received under the Bruce B floor price mechanism within a calendar year are subject to repayment if the average spot price in a month exceeds the floor price. The first quarter 2014 average spot price exceeded the floor price; however, spot prices fell below the floor price for the remainder of 2014. As a result, Bruce B recognized annual revenues at the floor price throughout 2014 and amounts received above the floor price in first quarter 2014 were repaid to the IESO in January 2015.
Bruce B also enters into fixed-price contracts under which it receives or pays the difference between the contract price and the spot price.
The contract also provides for payment if the IESO reduces Bruce Power's generation to balance the supply of and demand for electricity and/or manage other operating conditions of the Ontario power grid. The amount of the reduction is considered "deemed generation", for which Bruce Power is paid the fixed price, floor price or spot price as applicable under the contract.
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Bruce Power resultsOur proportionate share
Equity income from Bruce A in 2014 was $7 million higher than 2013. The increase was mainly due to lower depreciation and operating expenses and higher volumes partially offset by recognition of an insurance recovery of approximately $40 million in the first quarter 2013. The negative impact of increased outage days in 2014 is offset by higher generation levels while operating.
Equity income from Bruce B in 2014 was $3 million lower than 2013. The decrease was mainly due to higher lease expense recognized based on the terms of the lease agreement with Ontario Power Generation, partially offset by higher volumes and lower operating costs resulting from lower outage days.
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In 2013, equity income from Bruce A was $351 million higher than 2012. The increase was mainly due to:
In 2013, equity income from Bruce B was $55 million lower than 2012. The decrease was mainly due to lower volumes and higher operating costs resulting from higher planned outage days.
U.S. PowerWe own approximately 3,800 MW of power generation capacity in New York and New England, including plants powered by natural gas, oil, hydro and wind.
We earn revenues in both New York and New England in two ways – by providing capacity and by selling energy. Capacity markets compensate power suppliers for being available to provide power, and are intended to promote investment in new and existing power resources needed to meet customer demand and maintain a reliable power system. The energy markets compensate power providers for the actual energy they supply.
Providing capacity Capacity revenues in New York and New England are a function of two factors – capacity prices and plant availability. It is important for us to keep our plant availability high to maximize the amount of capacity for which we get paid.
Capacity prices paid to capacity suppliers in New York are determined by a series of voluntary forward auctions and a mandatory spot auction. The forward auctions are bid based while the mandatory spot auction is affected by a demand curve price setting process that is driven by a number of established parameters that are subject to periodic review by the New York ISO and FERC. The parameters are determined for each zone and include the forecasted cost of a new unit entering the market, available existing operable supply and fluctuations in the forecasted demand.
The price paid for capacity in the New England Power Pool is determined by annual competitive auctions which are held three years in advance of the applicable capacity year. Auction results are impacted by actual and projected power demand, power supply, and other factors.
Selling energy We focus on selling power under short and long-term contracts to wholesale, commercial and industrial customers in the following power markets:
We also earn additional revenues by bundling power sales with other energy services.
We meet our power sales commitments using power we generate ourselves or with power we buy at fixed prices, reducing our exposure to changes in commodity prices.
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U.S. Power resultsComparable EBITDA and comparable EBIT are non-GAAP measures. See page 24 for more information.
Sales volumes and plant availability
U.S. Power – other information
U.S. Power's comparable EBITDA in 2014 was US$53 million higher than 2013. This reflected the net effect of:
In 2013, U.S. Power's comparable EBITDA was US$114 million higher than 2012. This reflected the net effect of:
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Average New York Zone J spot capacity prices were approximately 27 per cent higher in 2014 than in 2013. The increase in spot prices and the impact of hedging activities resulted in higher realized capacity prices in New York in 2014.
Wholesale electricity prices in New York and New England were higher in 2014 compared to 2013 primarily due to colder winter temperatures and gas transmission constraints. This resulted in higher natural gas prices in the predominantly gas-fired New England and New York power markets in first quarter 2014 compared to the same period in 2013. Average spot power prices in 2014 in New England increased approximately 14 per cent and in New York spot power prices increased approximately 11 per cent compared to 2013.
Physical sales volumes in 2014 rose compared to 2013. Generation volumes increased primarily due to higher generation at the Ravenswood facility throughout 2014 compared to 2013. Purchased volumes were also higher in 2014 compared to 2013 due to increased sales to commercial and industrial customers in both the New England and PJM markets.
As at December 31, 2014, approximately 3,700 GWh or 30 per cent of U.S. Power's planned generation is contracted for 2015, and 1,600 GWh or 14 per cent for 2016. Planned generation fluctuates depending on hydrology, wind conditions, commodity prices and the resulting dispatch of the assets. Power sales fluctuate based on customer usage.
Natural Gas StorageWe own and operate 118 Bcf of non-regulated natural gas storage capacity in Alberta. This business operates independently from our regulated natural gas transmission business and from ANR's regulated storage business, which are included in our Natural Gas Pipelines segment.
Storage capacity
We also hold a contract for Alberta-based storage capacity with a third party.
Our natural gas storage business helps balance seasonal and short-term supply and demand, and adds flexibility to the delivery of natural gas to markets in Alberta and the rest of North America. Market volatility creates arbitrage opportunities and our natural gas storage facilities also give customers the ability to capture value from short-term price movements. The natural gas storage business is affected by the change in seasonal natural gas price spreads which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons.
Our gas storage business contracts with third parties, typically participants in the Alberta and interconnected gas markets, for a fixed fee to provide gas storage services on a short, medium, and/or long term basis.
We also enter into proprietary natural gas storage transactions, which include a forward purchase of our own natural gas to be injected into storage and a simultaneous forward sale of natural gas for withdrawal at a later period, typically during the winter withdrawal season. By matching purchase and sales volumes on a back-to-back basis, we lock in future positive margins, effectively eliminating our exposure to changes in gas prices.
These forward natural gas contracts provide highly effective economic hedges but do not meet the specific criteria for hedge accounting and, therefore, are recorded at their fair value through net income based on the forward market prices for the contracted month of delivery. We record changes in the fair value of these contracts in revenues. We do not include changes in the fair value of natural gas forward purchase and sales
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contracts when we calculate comparable earnings because they do not represent the amounts that will be realized on settlement.
Natural Gas Storage and other resultsComparable EBITDA in 2014 was $19 million lower than 2013, mainly due to decreased third party storage revenue as a result of lower realized natural gas storage price spreads.
In 2013, comparable EBITDA was $4 million lower than 2012, mainly due to lower realized natural gas storage price spreads, partially offset by incremental earnings from CrossAlta resulting from the acquisition of the remaining 40 per cent interest in December 2012.
Ontario Solar As part of a purchase agreement with Canadian Solar Solutions Inc. signed in 2011, we completed the acquisition of three Ontario solar facilities for $181 million in September 2014 and acquired a fourth facility for $60 million in December 2014. In 2013, we completed the acquisition of four solar facilities for $216 million. Our total investment in the eight solar facilities is $457 million. All power produced by the solar facilities is sold under 20-year FIT contracts with the IESO.
Napanee In January 2015, we began construction activities of a 900 MW natural gas-fired power plant at Ontario Power Generation's Lennox site in eastern Ontario in the town of Greater Napanee. We expect to invest approximately $1.0 billion in the Napanee facility during construction and commercial operations are expected to begin in late 2017 or early 2018. Production from the facility is fully contracted with the IESO.
Bécancour In May 2014, Hydro-Québec 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. Under the December 2013 amended suspension agreement, Hydro-Québec has the option each year to further extend the suspension by an additional year (subject to certain conditions). We continue to receive capacity payments while generation is suspended.
Cancarb Limited and Cancarb Waste Heat Facility The sale of Cancarb Limited, a thermal carbon black facility, and its related power generation facility closed in April 2014 for gross proceeds of $190 million. We recognized a gain of $99 million, net of tax, in second quarter 2014.
Bruce Power In March 2014, Cameco Corporation sold its 31.6 per cent limited partnership interest in Bruce B to BPC Generation Infrastructure Trust (BPC). We are considering our option to increase our Bruce B ownership percentage.
New Canadian federal legislation is expected to come into force in 2015 respecting the determination of liability and compensation for a nuclear incident in Canada resulting in personal injuries and damages. This proposed 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 proposed 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 one-third of the shares of Bruce Power Inc., the licensed operator of Bruce Power, and as such Bruce Power is subject to this liability in the event of an incident and the legislation's other requirements.
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U.S. Power
Ravenswood In late September 2014, the 972 MW Unit 30 at the Ravenswood Generating Station experienced an unplanned outage as a result of a problem with the generator associated with the high pressure turbine. Insurance is expected to cover the repair costs and lost revenues associated with the unplanned outage, which are yet to be finalized. As a result of the expected insurance recoveries, net of deductibles, the Unit 30 unplanned outage is not expected to have a significant impact on our earnings although the recording of earnings may not coincide with lost revenues due to timing of the anticipated insurance proceeds. The unit is expected to be back in service in first half 2015.
Natural Gas StorageEffective April 30, 2014, we terminated a 38 Bcf long-term natural gas storage contract in Alberta with Niska Gas Storage. The contract contained provisions allowing for possible early termination. As a result, we recorded an after tax charge of $32 million in 2014. We have re-contracted for new natural gas storage services in Alberta with Niska Gas Storage starting May 1, 2014 for a six-year period and a reduced average volume.
BUSINESS RISKSThe following are risks specific to our energy business. See page 99 for information about general risks that affect the company as a whole,including other operational risks, health, safety and environment (HSE) risks, and financial risks.
Fluctuating power and natural gas market pricesPower and natural gas prices are affected by fluctuations in supply and demand, weather, and by general economic conditions. The power generation facilities in our Western Power operations in Alberta, and in our U.S. Power operations in New England and New York, are exposed to commodity price volatility.
Earnings from these businesses are generally correlated to the prevailing power supply and demand conditions. In New England and New York, the price of natural gas also has a significant impact on power prices, as energy prices in these markets are usually set by gas-fired power supplies. Extended periods of low gas prices will generally exert downward pressure on power prices and therefore on earnings from our New England and New York facilities.
Our Coolidge Generating Station and our portfolio of assets in eastern Canada are fully contracted, and are therefore not subject to fluctuating commodity prices. As these contracts expire in the long term, it is uncertain if we will be able to re-contract on similar terms. Bruce Power's exposure to fluctuating power prices is discussed further below.
To mitigate the impact of power price volatility in Alberta and the U.S. northeast, we sell a portion of our supply under medium to long-term sales contracts where contract terms are acceptable. A portion of our power is retained to be sold in the spot market or under shorter-term forward arrangements to ensure we have adequate power supply to fulfill sales obligations if unexpected plant outages occur. This unsold supply is exposed to fluctuating power and natural gas market prices. As power sales contracts expire, new forward contracts are entered into at prevailing market prices.
Under an agreement with the IESO, Bruce B volumes are subject to a floor price mechanism. When the spot market price is above the floor price, Bruce B's volumes are subject to spot price volatility. When spot prices are below the floor price, Bruce B receives the floor price for all of its output. Bruce B also enters into third party fixed-price contracts where it receives the difference between the contract price and spot price. All Bruce A output is sold into the Ontario wholesale power spot market under a fixed-price contract with the IESO.
Our natural gas storage business is subject to fluctuating seasonal natural gas price spreads which are generally determined by the differential in natural gas prices between the traditional summer injection and winter withdrawal seasons.
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U.S. Power capacity paymentsA significant portion of revenues earned by Ravenswood and a portion of revenues earned by our power facilities in New England are driven by capacity payments. Fluctuations in capacity prices can have a material impact on these businesses, particularly in New York. New York capacity prices are determined by a series of voluntary forward auctions and a mandatory spot auction. The forward auctions are bid based while the mandatory spot auction is affected by a demand curve price setting process that is driven by a number of established parameters that are subject to periodic review by the New York ISO and FERC. These parameters are determined for each capacity zone and include the forecasted cost of a new unit entering the market, available existing operable supply and fluctuations in forecasted demand. Capacity payments are also a function of plant availability which is discussed below.
Plant availabilityOptimizing and maintaining plant availability is essential to the continued success of our Energy business. Unexpected outages or extended planned outages at our power plants can increase maintenance costs, lower plant output and sales revenue and lower capacity payments and margins. We may also have to buy power or natural gas on the spot market to meet our delivery obligations.
We manage this risk by investing in a highly skilled workforce, operating prudently, running comprehensive, risk-based preventive maintenance programs and making effective capital investments.
For facilities we do not operate, our purchase agreements include a financial remedy if a plant owner does not deliver as agreed. The Sundance and Sheerness PPAs, for example, require the producers to pay us market-based penalties if they cannot supply the amount of power we have agreed to purchase.
RegulatoryWe operate in both regulated and deregulated power markets in both the United States and Canada. These markets are subject to various federal, state and provincial regulations in both countries. As power markets evolve across North America, there is the potential for regulatory bodies to implement new rules that could negatively affect us as a generator and marketer of electricity. These may be in the form of market rule changes, changes in the interpretation and application of market rules by regulators, price caps, emission controls, cost allocations to generators and out-of-market actions taken by others to build excess generation, all of which negatively affect the price of power or capacity, or both. In addition, our development projects rely on an orderly permitting process and any disruption to that process can have negative effects on project schedules and costs. We are an active participant in formal and informal regulatory proceedings and take legal action where required.
WeatherSignificant changes in temperature and other weather events have many effects on our business, ranging from the impact on demand, availability and commodity prices, to efficiency and output capability. Extreme temperature and weather can affect market demand for power and natural gas and can lead to significant price volatility. Extreme weather can also restrict the availability of natural gas and power if demand is higher than supply. Seasonal changes in temperature can reduce the efficiency of our natural gas-fired power plants, and the amount of power they produce. Variable wind speeds affect earnings from our wind assets, and sun-light hours and intensity affects earnings from our solar assets.
HydrologyOur hydroelectric power generation facilities in the northeastern U.S. are subject to hydrology risks that can impact the volume of water available for generation at these facilities including weather changes and events, local river management and potential dam failures at these plants or upstream facilities.
CompetitionWe face various competitive forces that impact our existing assets and prospects for growth. For instance, our existing power plants in deregulated markets will compete over time with new power capacity. New supply could come in several forms including supply that employs more efficient power generation technologies, additional supply from regional power transmission interconnections and new supply in the form of distributed generation. We also face competition from other power companies in the greenfield power plant development arena.
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Corporate
OTHER INCOME STATEMENT ITEMSThe following are reconciliations and related analyses of our non-GAAP measures to the equivalent GAAP measures.
Interest expense
Comparable interest expense in 2014 was $214 million higher than in 2013 due to the net effect of:
Comparable interest expense in 2013 was $8 million higher than 2012 due to the net effect of:
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Interest income and other
Comparable interest income and other in 2014 was $70 million higher than 2013. This was the net result of:
In 2013, comparable interest income and other was $44 million lower than 2012. This decrease was mainly due to higher realized losses in 2013 compared to 2012 on derivatives used to manage our net exposure to foreign exchange rate fluctuations on U.S. dollar-denominated income and on translation of foreign denominated working capital.
Income tax expense
Comparable income tax expense increased $197 million in 2014 compared to 2013 mainly because of higher pre-tax earnings in 2014, changes in the proportion of income earned between Canadian and foreign jurisdictions as well as higher flow-through taxes in 2014 on Canadian regulated pipelines.
Comparable income tax expense increased $185 million in 2013 compared to 2012 because of higher pre-tax earnings in 2013 combined with changes in the proportion of income earned between Canadian and foreign jurisdictions.
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Other
Net income attributable to non-controlling interests increased by $28 million in 2014 compared to 2013 primarily due to the sale of a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP in July 2013 and the remaining 30 per cent of Bison in October 2014. This was partially offset by the redemption of Series U preferred shares in October 2013 and Series Y preferred shares in March 2014.
Net income attributable to non-controlling interest increased $7 million in 2013 compared to 2012 primarily due to the sale of a 45 per cent interest in each of GTN and Bison to TC PipeLines, LP in July 2013.
Preferred share dividends increased by $23 million in 2014 compared to 2013 due to the issuances of Series 7 preferred shares in March 2013 and Series 9 preferred shares in January 2014.
Preferred share dividends increased $19 million in 2013 compared to 2012 due to the issuance of Series 7 preferred shares in March 2013.
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Financial condition
We strive to maintain strong financial capacity and flexibility in all parts of the economic cycle. We rely on our operating cash flow to sustain our business, pay dividends and fund a portion of our growth. In addition, we access capital markets to meet our financing needs, manage our capital structure and to preserve our credit ratings.
We believe we have the financial capacity to fund our existing capital program through our predictable cash flow from our operations, access to capital markets, proceeds from the sale of natural gas pipeline assets to TC PipeLines, LP, cash on hand and substantial committed credit facilities.
Balance sheet analysisAs of December 31, 2014, assets increased by $5.0 billion, liabilities increased by $4.5 billion and equity rose by $0.5 billion compared to December 31, 2013.
The increase in assets was primarily due to increases in property, plant and equipment and intangible and other assets. Property, plant and equipment increased by $4.2 billion primarily due to the completion of the Gulf Coast Extension of the Keystone Pipeline System, further investment in the NGTL System, investment in our Mexican pipelines projects, construction of the Houston Lateral and Tank Terminal and the expansion of our ANR pipeline. Intangible and other assets rose by $0.7 billion primarily due to spending on our capital projects under development.
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The increase in liabilities was primarily due to an increase in long-term debt and notes payable used to fund our growth. In 2014, we issued $1.4 billion and repaid $1.1 billion of long term debt. The strengthening of the U.S. dollar also contributed a $1.6 billion increase on translation of our U.S. dollar-denominated debt. In 2014, notes payable increased by $0.6 billion.
Total equity increased $0.5 billion in 2014 mainly due to a $450 million preferred share issuance in January 2014.
Consolidated capital structureat December 31, 2014
As at December 31, 2014, we had unused capacity of $1.55 billion, $2.0 billion and US$2.75 billion under our equity, Canadian debt and U.S. debt shelf prospectuses, respectively, to facilitate future access to the North American debt and equity markets.
As at December 31, 2014, we were in compliance with all of our financial covenants. Provisions of various trust indentures and credit arrangements with certain of our subsidiaries can restrict those subsidiaries' ability to declare and pay dividends or make distributions under certain circumstances. If such restrictions apply, they may, in turn, have an impact on our ability to declare and pay dividends on our common and preferred shares. In the opinion of management, these provisions do not currently restrict or alter our ability to declare or pay dividends. These trust indentures and credit arrangements also require us to comply with various affirmative and negative covenants and maintain certain financial ratios.
Cash flowsThe following tables summarize the cash flows of our business.
We continue to fund our extensive capital program through cash flow from operations supplemented by capital market financing activities and the sale of our U.S. natural gas pipeline assets to TC PipeLines, LP.
Liquidity will continue to be comprised of predictable cash flow generated from operations, committed credit facilities, our ability to access debt and equity markets in both Canada and the U.S., additional drop downs of our U.S. natural gas pipeline assets into TC PipeLines, LP and cash on hand.
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Net cash provided by operations
Funds generated from operations, a non-GAAP measure, helps us assess the cash generating ability of our operations excluding the timing effects of working capital changes. See page 24 for more information about non-GAAP measures. The increase in 2014 compared to 2013 was driven by the increase in comparable earnings adjusted for the following non-cash items: increased deferred income tax expense and depreciation, higher equity AFUDC income and lower equity earnings. Funds generated from operations also reflected lower distributed earnings from equity investments.
At December 31, 2014, our current liabilities were higher than our current assets, leaving us with a working capital deficit of $4.0 billion. This short-term deficiency was mainly due to the use of accounts payable, notes payable and the current portion of our long-term debt to fund our capital program.
This short-term deficiency is considered to be in the normal course of a growing business and is managed through:
Net cash used in investing activities
Our 2014 capital spending was incurred primarily for expanding our NGTL System, construction of our Mexican pipelines, construction of the Houston Lateral and Tank Terminal, development of our Energy East Pipeline and expansion of the ANR pipeline. Also included in investing activities in 2014 was the acquisition of an additional four solar facilities in Ontario, proceeds from the sale of Cancarb and its related power generation facilities and our contribution for the construction of Grand Rapids Pipeline.
Net cash (used in)/provided by financing activities
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Long-term debt issued
Long-term debt retired
Preferred share issuance, redemption and conversionIn January 2014, we completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at $25 per share resulting in gross proceeds of $450 million. Investors are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly. The dividend rate will reset on October 30, 2019 and every five years thereafter to a yield per annum equal to the sum of the then five-year Government of Canada bond yield and 2.35 per cent. The preferred shares are redeemable by us on or after October 30, 2019 and on October 30 of every fifth year thereafter at a price of $25 per share plus accrued and unpaid dividends. Investors will have the right to convert their shares into Series 10 cumulative redeemable first preferred shares on October 30, 2019 and on October 30 of every fifth year thereafter. The holders of Series 10 preferred shares will be entitled to receive quarterly floating rate cumulative dividends at an annualized rate equal to the sum of the then 90-day Government of Canada treasury bill rate and 2.35 per cent.
In March 2014, we redeemed all four million Series Y preferred shares of TCPL at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends. The total face value of the outstanding Series Y shares was $200 million and they carried an aggregate of $11 million in annualized dividends.
In December 2014, Series 1 shareholders elected to convert 12.5 million of our 22 million outstanding Series 1 cumulative redeemable first preferred shares, on a one-for-one basis into Series 2 floating-rate cumulative redeemable first preferred shares. The Series 1 shares will yield an annual fixed dividend rate of 3.266 per cent, paid on a quarterly basis, for the five-year period which began on December 31, 2014. The Series 2 shares will pay a floating quarterly dividend at an annualized rate equal to the sum of the 90-day Government of Canada treasury bill rate and 1.92 per cent for the five-year period which began on December 31, 2014. The floating quarterly dividend rate for the Series 2 shares for the first quarterly floating
TransCanada Management's discussion and analysis 2014 93
rate period, commencing December 31, 2014, is 2.815 per cent per annum and will be reset each quarter going forward.
The net proceeds of the above debt and preferred share offerings were used for general corporate purposes and to reduce short-term indebtedness.
TC PipeLines, LP at-the-market (ATM) equity issuance programIn August 2014, TC PipeLines, LP initiated its at-the-market equity issuance program (ATM program) under which it is authorized to offer and sell common units having an aggregate offering price of up to US$200 million.
From August until December 31, 2014, 1.3 million common units were issued under the ATM program generating net proceeds of approximately US$73 million. Our ownership interest in TC PipeLines, LP will decrease as a result of equity issuances under the ATM program.
Credit facilitiesWe have committed, revolving credit facilities to primarily support our commercial paper programs. The commercial paper programs, along with additional demand credit facilities, are used for general corporate purposes, including issuing letters of credit and providing additional liquidity.
At December 31, 2014, we had $6.7 billion (2013 – $6.2 billion) in unsecured credit facilities, including:
At December 31, 2014, our operated affiliates had $0.4 billion of undrawn capacity on committed credit facilities.
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Contractual obligationsPayments due (by period)
Our contractual obligations include our long-term debt, operating leases, purchase obligations and other liabilities incurred in our business such as environmental liability funds and employee retirement and post-retirement benefit plans.
Long-term debtAt the end of 2014, we had $25 billion of long-term debt and $1.2 billion of junior subordinated notes, compared to $22.9 billion of long-term debt and $1.1 billion of junior subordinated notes at December 31, 2013.
Total notes payable were $2.5 billion at the end of 2014 compared to $1.8 billion at the end of 2013.
We attempt to spread out the maturity profile of our debt. The majority of our debt obligations mature beyond five years with an average term of 12 years.
At December 31, 2014, scheduled principal repayments and interest payments related to our long-term debt were as follows:
Principal repaymentsPayments due (by period)
Interest paymentsPayments due (by period)
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Operating leasesOur operating leases for premises, services and equipment expire at different times between now and 2052. Some of our operating leases include the option to renew the agreement for one to five years.
Our commitments under the Alberta PPAs are considered operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Fixed payments under these PPAs have been included in our summary of future obligations. Variable payments have been excluded as these payments are dependent upon plant availability and other factors. Our share of power purchased under the PPAs in 2014 was $391 million (2013 – $242 million; 2012 – $238 million).
Purchase obligationsWe have purchase obligations that are transacted at market prices and in the normal course of business, including long-term natural gas transportation and purchase arrangements.
Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts.
Payments due (by period)1
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OutlookWe are developing quality projects under our long-term $46 billion capital program. These long-life infrastructure assets are supported by long-term commercial arrangements, and once completed, are expected to generate significant growth in earnings and cash flow.
Our $46 billion capital program is comprised of $12 billion of small to medium-sized, shorter-term projects and $34 billion of commercially secured large-scale, medium – and longer-term projects each of which are subject to key commercial or regulatory approvals. The portfolio is expected to be financed through our growing internally generated cash flow and a combination of funding options including:
Additional financing alternatives available include common equity through DRP or, lastly, discrete equity issuances.
GUARANTEES
Bruce PowerWe and our partner, BPC, have each severally guaranteed some of Bruce B's contingent financial obligations related to power sales agreements, a lease agreement and contractor services. The Bruce B guarantees have terms to 2018 except for one guarantee with no termination date that has no exposure associated with it.
We and BPC have each severally guaranteed half of certain contingent financial obligations of Bruce A related to a sublease agreement, an agreement with the IESO to restart the Bruce A power generation units, and certain other financial obligations. The Bruce A guarantees have terms to 2019.
At December 31, 2014, our share of the potential exposure under the Bruce A and B guarantees was estimated to be $634 million. The carrying amount of these guarantees was estimated to be $6 million. Our exposure under certain of these guarantees is unlimited.
Other jointly owned entitiesWe and our partners in certain other jointly owned entities have also guaranteed (jointly, severally, or jointly and severally) the financial performance of these entities relating mainly to redelivery of natural gas, PPA payments and the payment of liabilities. The guarantees have terms ranging to 2040.
Our share of the potential exposure under these assurances was estimated at December 31, 2014 to be a maximum of $104 million. The carrying amount of these guarantees was $14 million, and is included in other long-term liabilities. In some cases, if we make a payment that exceeds our ownership interest, the additional amount must be reimbursed by our partners.
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OBLIGATIONS – PENSION AND OTHER POST-RETIREMENT PLANSIn 2015, we expect to make funding contributions of approximately $70 million for the defined benefit pension plans, approximately $7 million for the other post-retirement benefit plans and approximately $36 million for the savings plan and defined contribution pension plans. In addition, the Company expects to provide a $35 million letter of credit to the Canadian DB Plan for the funding of solvency requirements.
In 2014, we made funding contributions of $73 million to our defined benefit pension plans, $6 million for the other post-retirement benefit plans and $37 million for the savings plan and defined contribution pension plans. We also provided a $47 million letter of credit to a defined benefit plan in lieu of cash funding.
OutlookThe next actuarial valuation for our pension and other post-retirement benefit plans will be carried out as at January 1, 2015. Based on current market conditions, we expect funding requirements for these plans to approximate 2014 levels for several years. This will allow us to amortize solvency deficiencies in the plans, in addition to normal funding costs.
Our net benefit cost for our defined benefit and other post-retirement plans decreased to $115 million in 2014 from $134 million, mainly due to a higher discount rate used to measure the benefit obligation.
Future net benefit costs and the amount we will need to contribute to fund our plans will depend on a range of factors, including:
We do not expect future increases in the level of funding needed to maintain our plans to have a material impact on our liquidity.
98 TransCanada Management's discussion and analysis 2014
Other information
RISKS AND RISK MANAGEMENTThe following is a summary of general risks that affect our company. You can find risks specific to each operating business segment in the business segment discussions.
Risk management is integral to the successful operation of our business. Our strategy is to ensure that our risks and related exposures are in line with our business objectives and risk tolerance.
We build risk assessment into our decision-making processes at all levels.
The Board's Governance Committee oversees our risk management activities, which includes ensuring that there are appropriate management systems in place to manage our risks, and adequate Board oversight of our risk management policies, programs and practices. Other Board committees oversee specific types of risk: the Audit Committee oversees management's role in monitoring financial risk, the Human Resources Committee oversees executive resourcing and compensation, organizational capabilities and compensation risk, and the Health, Safety and Environment Committee oversees operational, safety and environmental risk through regular reporting from management.
Our executive leadership team is accountable for developing and implementing risk management plans and actions, and effective risk management is reflected in their compensation.
Operational risks
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Pipeline abandonment costs The NEB's Land Matters Consultation Initiative (LMCI) is an initiative that requires all Canadian pipeline companies regulated by the NEB to set aside funds to cover future pipeline abandonment costs.
The NEB provided several key guiding principles under this initiative, including the position that abandonment costs are a legitimate cost of providing pipeline service and are recoverable, upon NEB approval, from users of the individual pipeline systems. Pipeline companies are responsible for managing the collection and investment of funds to cover future abandonment costs.
All hearings have been completed and Board decisions have been received, with the final decision in December 2014, providing approval to begin collection through an abandonment surcharge in January 2015. Collection of funds will be held in trusts which will serve to hold and invest funds collected to cover future abandonment costs.
Health, safety and environment The Health, Safety and Environment committee of TransCanada's Board of Directors (the Board) monitors compliance with our HSE corporate commitment statement through regular reporting from management. We have an integrated HSE Management System that is used to capture, organize and document our related policies, programs and procedures.
The HSE Management System is modeled after international standards, conforms to external industry consensus standards and voluntary programs, and complies with applicable legislative requirements and various other internal management systems. It follows a continuous improvement cycle.
The safety and integrity of our existing and newly-developed infrastructure is a top priority. All assets are designed, constructed and commissioned with full consideration given to safety and integrity, and are brought in service only after all necessary requirements have been satisfied. In 2014, we spent $550 million for pipeline integrity on the natural gas and liquids pipelines we operate, an increase of $174 million over 2013 primarily
100 TransCanada Management's discussion and analysis 2014
due to increased levels of in-line pipeline inspections and related maintenance projects on all systems as well an increased amount of pipe replacement required due to population encroachment on the pipelines. Under the approved regulatory models in Canada, non-capital pipeline integrity expenditures on NEB-regulated pipelines are generally treated on a flow-through basis and, as a result, these expenditures have minimal impact on our earnings. Under the Keystone contracts, pipeline integrity expenditures are recovered through the tolling mechanism and, as a result, these expenditures generally have no impact on our earnings. Our safety record in 2014 continued to meet or exceed industry benchmarks.
Our Energy operations spending associated with process safety and our various integrity programs is used to minimize risk to employees and the public, process equipment, the surrounding environment, and to prevent disruptions to serving the electrical needs of our customers, within the footprint of each facility.
Spending associated with public safety on Energy assets is focused primarily on our hydro dams and associated equipment.
Our main environmental risks are:
As described in the Business interruption section, above, we have a set of procedures in place to manage our response to natural disasters which include catastrophic events such as forest fires, tornadoes, earthquakes, floods, volcanic eruptions and hurricanes. The procedures, which are included in our Incident Management Program, are designed to help protect the health and safety of our employees, minimize risk to the public and limit any operational impacts caused by a natural disaster on the environment.
Environmental compliance and liabilities Our facilities are subject to federal, state, provincial and local environmental statutes and regulations governing environmental protection, including air and GHG emissions, water quality, wastewater discharges and waste management. Our facilities are required to obtain and comply with a wide variety of environmental registrations, licenses, permits and other approvals and requirements. Failure to comply could result in administrative, civil or criminal penalties, remedial requirements or orders affecting future operations.
We continually monitor our facilities to ensure compliance with all environmental requirements. We routinely monitor proposed changes in environmental policy, legislation and regulation, and where the risks are potentially large or uncertain, we comment on proposals independently or through industry associations.
We are not aware of any material outstanding orders, claims or lawsuits against us related to releasing or discharging any material into the environment or in connection with environmental protection.
Compliance obligations can result in significant costs associated with installing and maintaining pollution controls, fines and penalties resulting from any failure to comply, and potential limitations on operations.
Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties, and with damage claims arising from the contamination of properties.
It is not possible to estimate the amount and timing of all our future expenditures related to environmental matters because:
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At December 31, 2014, we had accrued approximately $30 million related to these obligations ($32 million at the end of 2013). This represents the amount that we have estimated that we will need to manage our currently known environmental liabilities. We believe that we have considered all necessary contingencies and established appropriate reserves for environmental liabilities; however, there is the risk that unforeseen matters may arise requiring us to set aside additional amounts. We adjust this reserve quarterly to account for changes in liabilities.
Greenhouse gas emissions regulation risk We own assets and have business interests in a number of regions where there are regulations to address industrial GHG emissions. We have procedures in place to comply with these regulations, including:
There are federal, regional, state and provincial initiatives currently in development. While economic events may continue to affect the scope and timing of new regulations, we anticipate that most of our facilities will be subject to future regulations to manage industrial GHG emissions.
Financial risksWe are exposed to market risk, counterparty credit risk and liquidity risk, and have strategies, policies and limits in place to mitigate their impact on our earnings, cash flow and, ultimately, shareholder value.
These strategies, policies and limits are designed to ensure our risks and related exposures are in line with our business objectives and risk tolerance. We manage market risk and counterparty credit risk within limits that are ultimately established by the Board, implemented by senior management and monitored by our risk management and internal audit groups. Management monitors compliance with market and counterparty risk management policies and procedures, and reviews the adequacy of the risk management framework, overseen by the Audit Committee. Our internal audit group assists the Audit Committee by carrying out regular and ad-hoc reviews of risk management controls and procedures, and reporting up to the Audit Committee.
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Market risk We build and invest in energy infrastructure projects, buy and sell energy commodities, issue short-term and long-term debt (including amounts in foreign currencies) and invest in foreign operations. Certain of these activities expose us to market risk from changes in commodity prices and foreign exchange and interest rates which may affect our earnings and the value of the financial instruments we hold.
We use derivative contracts to assist in managing our exposure to market risk, including:
We assess contracts we use to manage market risk to determine whether all, or a portion of it, meets the definition of a derivative.
Commodity price risk We are exposed to changes in commodity prices, especially electricity and natural gas, which may affect our earnings. We use several strategies to reduce this exposure, including:
Foreign exchange and interest rate risk Certain of our businesses generate income in U.S. dollars, but since we report in Canadian dollars, changes in the value of the U.S. dollar against the Canadian dollar can affect our net income. As our U.S. dollar-denominated operations continue to grow, this exposure increases. The majority of this risk is offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.
We have floating interest rate debt which subjects us to interest rate cash flow risk. We manage this using a combination of interest rate swaps and options.
Average exchange rate – U.S. to Canadian dollars
The impact of changes in the value of the U.S. dollar on our U.S. operations is significantly offset by other U.S. dollar-denominated items, as set out in the table below. Comparable EBIT is a non-GAAP measure. See page 24 for more information.
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Significant U.S. dollar-denominated amounts
We hedge our net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options.
Derivatives designated as a net investment hedgeThe fair values and notional or principal amounts for the derivatives designated as a net investment hedge were as follows:
U.S. dollar-denominated debt designated as a net investment hedge
The balance sheet classification of the fair value of derivatives used to hedge our U.S. dollar net investment in foreign operations is as follows:
Counterparty credit risk We have exposure to counterparty credit risk in the following areas:
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If a counterparty fails to meet its financial obligations to us according to the terms and conditions of the financial instrument, we could experience a financial loss. We manage our exposure to this potential loss using recognized credit management techniques, including:
There is no guarantee that these techniques will protect us from material losses.
We review our accounts receivable regularly and record allowances for doubtful accounts using the specific identification method. We had no significant credit losses in 2014 and no significant amounts past due or impaired at year end. We had a credit risk concentration of $258 million (US$222 million) at December 31, 2014 with one counterparty (2013 – $240 million (US$225 million)). This amount is secured by a guarantee from the counterparty's parent company and we anticipate collecting the full amount.
We have significant credit and performance exposure to financial institutions because they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
Liquidity risk Liquidity risk is the risk that we will not be able to meet our financial obligations as they come due. We manage our liquidity by continuously forecasting our cash flow for a 12 month period and making sure we have adequate cash balances, cash flow from operations, committed and demand credit facilities and access to capital markets to meet our operating, financing and capital expenditure obligations under both normal and stressed economic conditions.
See page 90 Financial condition for more information about our liquidity.
Dealing with legal proceedings Legal proceedings, arbitrations and actions are part of doing business. While we cannot predict the final outcomes of proceedings and actions with certainty, management does not expect any current proceeding or action to have a material impact on our consolidated financial position, results of operations or liquidity. We are not aware of any potential legal proceeding or action that would have a material impact on our consolidated financial position, results of operations or liquidity.
CONTROLS AND PROCEDURESWe meet Canadian and U.S. regulatory requirements for disclosure controls and procedures, internal control over financial reporting and related CEO and CFO certifications.
Disclosure controls and proceduresWe carried out an evaluation under the supervision and with the participation of management, including our President and CEO and our CFO, of the effectiveness of our disclosure controls and procedures as at December 31, 2014 as required by the Canadian securities regulatory authorities and by the SEC. Based on this evaluation, our President and CEO and our CFO have concluded that the disclosure controls and procedures are effective in that they are designed to ensure that the information we are required to disclose in
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reports we file with or send to securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and U.S. securities laws.
Management's annual report on internal control over financial reportingWe are responsible for establishing and maintaining adequate internal control over financial reporting, which is a process designed by, or under the supervision of, our President and CEO and our CFO, and effected by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP.
Under the supervision and with the participation of management, including our President and CEO and our CFO, an evaluation of the effectiveness of the internal control over financial reporting was conducted as of December 31, 2014 based on the criteria described in "Internal Control – Integrated Framework" issued in 2013 by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management determined that, as of December 31, 2014, the internal control over financial reporting was effective.
Our internal control over financial reporting as of December 31, 2014 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their attestation report which is included herein.
Changes in internal control over financial reportingEffective January 1, 2014, management successfully implemented an Enterprise Resource Planning (ERP) system, and made changes to certain related processes. As a result of the ERP system, certain processes supporting our internal control over financial reporting changed in 2014.
Other than this ERP system implementation there has been no change in our internal control over financial reporting that occurred during the year covered by this annual report that has materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Although this implementation changed certain specific activities within the accounting function, it did not significantly affect the overall controls and procedures we follow in establishing internal controls over financial reporting.
CEO AND CFO CERTIFICATIONSOur President and CEO and our CFO have attested to the quality of the public disclosure in our fiscal 2014 reports filed with Canadian securities regulators and the SEC, and have filed certifications with them.
CRITICAL ACCOUNTING ESTIMATESWhen we prepare financial statements that conform with GAAP, we are required to make certain estimates and assumptions that affect the timing and amount we record for our assets, liabilities, revenues and expenses because these items may be affected by future events. We base the estimates and assumptions on the most current information available, using our best judgment. We also regularly assess the assets and liabilities themselves.
The following accounting estimates require us to make the most significant assumptions when preparing our financial statements and changes in these assumptions could have a material impact on the financial statements from those estimates.
Rate-regulated accountingUnder GAAP, an asset qualifies to use rate-regulated accounting (RRA) when it meets three criteria:
106 TransCanada Management's discussion and analysis 2014
We believe that the regulated natural gas pipelines and certain liquids pipelines projects we account for using RRA meet these criteria. The most significant impact of using these principles is the timing of when we recognize certain expenses and revenues, which is based on the economic impact of the regulators' decisions about our revenues and tolls, and may be different from what would otherwise be expected under GAAP. Regulatory assets represent costs that are expected to be recovered in customer rates in future periods. Regulatory liabilities are amounts that are expected to be refunded through customer rates in future periods.
Regulatory assets and liabilities
Impairment of long-lived assets and goodwillWe review long-lived assets (such as plant, property and equipment) and intangible assets for impairment whenever events or changes in circumstances lead us to believe we might not be able to recover an asset's carrying value. If the total of the undiscounted future cash flows we estimate for an asset is less than its carrying value, we consider its fair value to be less than its carrying value and we calculate and record an impairment loss to recognize this.
Goodwill We test goodwill for impairment annually or more frequently if events or changes in circumstances lead us to believe it might be impaired. We first assess qualitative factors to determine whether events or changes in circumstances indicate that goodwill might be impaired, and if we conclude that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, we use a two-step process to test for impairment:
We base these valuations on our projections of future cash flows, which involves making estimates and assumptions about:
If our assumptions change significantly, our requirement to record an impairment charge could also change. There is a risk that adverse changes in key assumptions could result in a future impairment of a portion of the goodwill balance relating to Great Lakes. These assumptions could be negatively impacted by factors including changes in customer demand at Great Lakes for pipeline capacity and services, weather, North American natural gas production and prices as well as natural gas storage market conditions. Our share of the goodwill related to Great Lakes, net of non-controlling interests, was US$243 million at December 31, 2014 (2013 – US$246 million).
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Asset retirement obligationsWhen there is a legal obligation to set aside funds to cover future abandonment costs, and we can reasonably estimate them, we recognize the fair value of the asset retirement obligation (ARO) in our financial statements.
We cannot determine when we will retire many of our hydro-electric power plants, oil pipelines, natural gas pipelines and transportation facilities and regulated natural gas storage systems because we intend to operate them as long as there is supply and demand, and so we have not recorded obligations for them.
For those we do record, we use the following assumptions:
The ARO is initially recorded when the obligation exists and is subsequently accreted through charges to operating expenses.
We continue to evaluate our future abandonment obligations and costs and monitor developments that could affect the amounts we record.
FINANCIAL INSTRUMENTSAll financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with our normal purchase and normal sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.
Non-derivative financial instruments
Fair value of non-derivative financial instruments The fair value of our notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of long-term debt has been estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data providers. The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative financial instruments.
Certain non-derivative financial instruments including cash and cash equivalents, accounts receivable, intangibles and other assets, notes payable, accounts payable and other, accrued interest and other long-term liabilities have carrying amounts that equal their fair value due to the nature of the item or the short time to maturity.
Derivative instruments We use derivative instruments to reduce volatility associated with fluctuations in commodity prices, interest rates and foreign exchange rates. We apply hedge accounting to derivative instruments that qualify and are designated for hedge accounting treatment. The effective portion of the change in the fair value of hedging derivatives for cash flow hedges and hedges of our net investment in foreign operations are recorded in other comprehensive income (OCI) in the period of change. Any ineffective portion is recognized in net income in the same financial category as the underlying transaction. The change in the fair value of derivative instruments that have been designated as fair value hedges are recorded in net income in interest income and other and interest expense.
The majority of derivative instruments that are not designated or do not qualify for hedge accounting treatment have been entered into as economic hedges to manage our exposure to market risk (held for trading). Changes in the fair value of held for trading derivative instruments are recorded in net income in the
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period of change. This may expose us to increased variability in reported operating results since the fair value of the held for trading derivative instruments can fluctuate significantly from period to period.
The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered or refunded through the tolls charged by us. As a result, these gains and losses are deferred as regulatory assets or regulatory liabilities and are refunded to or collected from the ratepayers in subsequent years when the derivative settles.
Fair value of derivative instruments The fair value of foreign exchange and interest rate derivatives has been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.
Balance sheet presentation of derivative instrumentsThe balance sheet classification of the fair value of derivative instruments is as follows:
Anticipated timing of settlement – derivative instrumentsThe anticipated timing of settlement for derivative instruments assumes constant commodity prices, interest rates and foreign exchange rates. Settlements will vary based on the actual value of these factors at the date of settlement.
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The effect of derivative instruments on the consolidated statement of incomeThe following summary does not include hedges of our net investment in foreign operations.
Derivatives in cash flow hedging relationshipsThe components of the consolidated statement of OCI related to derivatives in cash flow hedging relationships is as follows:
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Credit risk related contingent features of derivative instrumentsDerivatives often contain financial assurance provisions that may require us to provide collateral if a credit risk-related contingent event occurs (for example, if our credit rating is downgraded to non-investment grade). We may also need to provide collateral if the fair value of our derivative financial instruments exceeds pre-defined exposure limits.
Based on contracts in place and market prices at December 31, 2014, the aggregate fair value of all derivative contracts with credit-risk-related contingent features that were in a net liability position was $15 million (2013 – $16 million), with collateral provided in the normal course of business of nil (2013 – nil).
If the credit-risk-related contingent features in these agreements were triggered on December 31, 2014, we would have been required to provide additional collateral of $15 million (2013 – $16 million) to our counterparties. We have sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
ACCOUNTING CHANGES
Changes in accounting policies for 2014
Obligations resulting from joint and several liability arrangements In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This new guidance was effective January 1, 2014 and there was no material impact on our consolidated financial statements as a result of applying this new standard.
Foreign currency matters – cumulative translation adjustment In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This new guidance was applied prospectively from January 1, 2014.
Unrecognized tax benefit In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014 and there was no material impact on our consolidated financial statements as a result of applying this new standard.
Future accounting changes
Reporting discontinued operations In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance is effective from January 1, 2015 and will be applied prospectively. We do not expect the adoption of this new standard to have a material impact on our consolidated financial statements.
Revenue from contracts with customers In May 2014, the FASB issued new guidance on Revenue from Contracts with Customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This new guidance is effective from January 1, 2017 with two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. Early application is not permitted. We are currently evaluating the impact of the adoption of this ASU and have not yet determined the effect on our consolidated financial statements.
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Reconciliation of Non-GAAP measures
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Comparable EBITDA and comparable EBIT by business segment
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QUARTERLY RESULTS
Selected quarterly consolidated financial data(unaudited, millions of $, except per share amounts)
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Factors affecting quarterly financial information by business segmentQuarter-over-quarter revenues and net income fluctuate for reasons that vary across our business segments.
In Natural Gas Pipelines, except for seasonal fluctuations in short-term throughput volumes on U.S. pipelines, quarter-over-quarter revenues and net income generally remain relatively stable during any fiscal year. Over the long term, however, they fluctuate because of:
In Liquids Pipelines, annual revenues and net income are based on contracted crude oil transportation and uncommitted spot transportation. Quarter-over-quarter revenues and net income are affected by:
In Energy, quarter-over-quarter revenues and net income are affected by:
Factors affecting financial information by quarterWe calculate comparable measures by adjusting certain GAAP and non-GAAP measures for specific items we believe are significant but not reflective of our underlying operations in the period.
Comparable earnings exclude the unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain financial and commodity price risks. These derivatives provide effective economic hedges, but do not meet the criteria for hedge accounting. As a result, the changes in fair value are recorded in net income. As these amounts do not accurately reflect the gains and losses that will be realized at settlement, we do not consider them part of our underlying operations.
In fourth quarter 2014, comparable earnings excluded an $8 million after-tax gain on the sale of Gas Pacifico/INNERGY.
In second quarter 2014, comparable earnings excluded a $99 million after-tax gain on the sale of Cancarb Limited and a $32 million after-tax loss related to the termination of the Niska Gas Storage contract.
In second quarter 2013, comparable earnings excluded a $25 million favourable income tax adjustment due to the enactment of Canadian Federal tax legislation relating to Part VI.I tax in June 2013.
In first quarter 2013, comparable earnings excluded $84 million of net income in 2013 related to 2012 from the NEB 2013 Decision.
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FOURTH QUARTER 2014 HIGHLIGHTS
Net income attributable to common shares increased by $38 million for the three months ended December 31, 2014 compared to the same period in 2013. Net income included a gain on the sale of Gas Pacifico/INNERGY of $8 million after tax and unrealized gains and losses from changes in certain risk management activities. Excluding the impact of these items, comparable earnings in the three months ended December 31, 2014 increased over the same period in 2013 as discussed below in Comparable earnings.
The items discussed above were excluded from comparable earnings for the relevant periods. Certain unrealized fair value adjustments relating to certain risk management activities are also excluded from comparable earnings. The remainder of net income is equivalent to comparable earnings. A reconciliation of net income attributable to common shares to comparable earnings is shown in the following table.
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Comparable earnings Comparable earnings in fourth quarter 2014 increased by $101 million or $0.14 per share compared to the same period in 2013. This was primarily the net effect of:
The stronger U.S. dollar this quarter compared to the same period in 2013 positively impacted the translated results of our U.S. businesses, however, this impact was mostly offset by a corresponding increase in interest
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expense on U.S. dollar-denominated debt as well as realized losses on foreign exchange hedges used to manage our net exposure through our hedging program.
Highlights by business segment
Natural Gas Pipelines Natural Gas Pipelines segmented earnings increased by $123 million for the three months ended December 31, 2014 compared to the same period in 2013 and included a $9 million pre-tax gain related to the sale of Gas Pacifico/INNERGY in November 2014. This amount has been excluded in our calculation of comparable EBIT. The remainder of the Natural Gas Pipelines segmented earnings are equivalent to comparable EBIT and comparable EBITDA.
Comparable depreciation and amortization decreased by $8 million for the three months ended December 31, 2014 compared to the same period in 2013 as fourth quarter 2013 included the annual impact of the 2013-2014 NGTL Settlement approved by the NEB in November 2013. This settlement increased depreciation for 2013 and 2014. This decrease compared to 2013 was partially offset by depreciation on the Tamazunchale Extension for the period in 2014.
Canadian Pipelines Net income and comparable earnings for the Canadian Mainline increased by $39 million for the three months ended December 31, 2014 compared to the same period in 2013 because of higher incentive earnings recorded in fourth quarter partially offset by higher carrying charges owed to shippers on the positive TSA balance. Results for both periods reflect an ROE of 11.50 per cent on deemed common equity of 40 per cent.
Net income for the NGTL System decreased by $13 million for the three months ended December 31, 2014 compared to the same period in 2013. The decrease was due to increased OM&A costs at risk under the terms of the 2013-2014 NGTL Settlement approved by the NEB in November 2013, partially offset by a higher average investment base in 2014. Additionally, results for the three months ended December 31, 2013 reflect the annual impact of the 2013-2014 NGTL Settlement, which included an ROE of 10.10 per cent on deemed common equity of 40 per cent and annual fixed amounts for certain OM&A costs.
U.S. and International Pipelines Comparable EBITDA for the U.S. and international pipelines increased by US$35 million for the three months ended December 31, 2014 compared to the same period in 2013. This was due to:
A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. and International operations.
Liquids Pipelines Liquids Pipelines segmented earnings increased by $70 million for the three months ended December 31, 2014 compared to the same period in 2013, and are equivalent to comparable EBIT, which along with comparable EBITDA are discussed below.
Comparable EBITDA for the Keystone Pipeline System increased by $94 million for the three months ended December 31, 2014 compared to the same period in 2013. This increase was primarily due to:
Comparable depreciation and amortization increased by $20 million for the three months ended December 31, 2014 compared to the same period in 2013 due to the Keystone Gulf Coast extension being placed in service.
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Energy Energy segmented earnings decreased by $82 million for the three months ended December 31, 2014 compared to the same period in 2013.
Energy segmented earnings for the three months ended December 31, 2014 and 2013 included unrealized gains and losses from changes in the fair value of certain derivatives used to reduce our exposure to certain commodity price risks as follows:
The quarterly variances in these unrealized gains and losses reflect the impact of changes in forward natural gas and power prices and the volume of our position for these particular derivatives over a certain period of time however; they do not accurately reflect the gains and losses that will be realized on settlement, or the offsetting impact of other derivative and non-derivative transactions that make up our business as a whole. As a result, we do not consider them part of our underlying operations and exclude them in our calculation of comparable EBIT.
Comparable EBITDA for Energy increased by $39 million for the three months ended December 31, 2014 compared to the same period in 2013 due to the net effect of:
A stronger U.S. dollar had a positive impact on the Canadian dollar equivalent comparable earnings from our U.S. operations.
Comparable EBITDA for Eastern Power increased by $20 million for the three months ended December 31, 2014 compared to the same period in 2013 because of higher Bécancour contractual earnings and incremental earnings from solar facilities acquired in December 2013 and in the second half of 2014.
Equity income from Bruce A increased by $30 million for the three months ended December 31, 2014 compared to the same period in 2013 mainly due to higher generation levels and lower operating expenses. Fourth quarter 2014 results also include the impact of a deemed generation adjustment related to a prior quarter.
Equity income from Bruce B decreased $30 million for the three months ended December 31, 2014 compared to the same period in 2013 mainly due to lower volumes and higher operating costs resulting from higher planned outage days.
Comparable EBITDA for U.S. Power increased US$20 million for the three months ended December 31, 2014 compared to the same period in 2013. The increase was the net effect of:
Comparable EBITDA for Natural Gas Storage and Other decreased $15 million for the three months ended December 31, 2014 compared to the same period in 2013 mainly due to lower realized natural gas storage spreads and lower volumes of third party sales.
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120 TransCanada Management's discussion and analysis 2014
Management's report on Internal Control over Financial Reporting
The consolidated financial statements and Management's Discussion and Analysis (MD&A) included in this Annual Report are the responsibility of the management of TransCanada Corporation (TransCanada or the Company) and have been approved by the Board of Directors of the Company. The consolidated financial statements have been prepared by management in accordance with United States generally accepted accounting principles (GAAP) and include amounts that are based on estimates and judgments. The MD&A is based on the Company's financial results. It compares the Company's financial and operating performance in 2014 to that in 2013, and highlights significant changes between 2013 and 2012. The MD&A should be read in conjunction with the consolidated financial statements and accompanying notes. Financial information contained elsewhere in this Annual Report is consistent with the consolidated financial statements.
Management is responsible for establishing and maintaining adequate internal control over financial reporting for the Company. Management has designed and maintains a system of internal control over financial reporting, including a program of internal audits to carry out its responsibility. Management believes these controls provide reasonable assurance that financial records are reliable and form a proper basis for the preparation of financial statements. The internal control over financial reporting include management's communication to employees of policies that govern ethical business conduct.
Under the supervision and with the participation of the President and Chief Executive Officer and the Chief Financial Officer, management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management concluded, based on its evaluation, that internal control over financial reporting was effective as of December 31, 2014, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external reporting purposes.
The Board of Directors is responsible for reviewing and approving the financial statements and MD&A and ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors carries out these responsibilities primarily through the Audit Committee, which consists of independent, non-management directors. The Audit Committee meets with management at least five times a year and meets independently with internal and external auditors and as a group to review any significant accounting, internal control and auditing matters in accordance with the terms of the Charter of the Audit Committee, which is set out in the Annual Information Form. The Audit Committee's responsibilities include overseeing management's performance in carrying out its financial reporting responsibilities and reviewing the Annual Report, including the consolidated financial statements and MD&A, before these documents are submitted to the Board of Directors for approval. The internal and independent external auditors have access to the Audit Committee without the requirement to obtain prior management approval.
The Audit Committee approves the terms of engagement of the independent external auditors and reviews the annual audit plan, the Auditors' Report and the results of the audit. It also recommends to the Board of Directors the firm of external auditors to be appointed by the shareholders.
The shareholders have appointed KPMG LLP as independent external auditors to express an opinion as to whether the consolidated financial statements present fairly, in all material respects, the Company's consolidated financial position, results of operations and cash flows in accordance with GAAP. The reports of KPMG LLP outline the scope of its examinations and its opinions on the consolidated financial statements and the effectiveness of the Company's internal control over financial reporting.
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Independent Auditors' Report of Registered Public Accounting Firm
TO THE SHAREHOLDERS OF TRANSCANADA CORPORATION We have audited the accompanying consolidated financial statements of TransCanada Corporation, which comprise the consolidated balance sheets as at December 31, 2014 and December 31, 2013, the consolidated statements of income, cash flows, comprehensive income, and equity for each of the years in the three-year period ended December 31, 2014, and notes, comprising a summary of significant accounting policies and other explanatory information.
MANAGEMENT'S RESPONSIBILITY FOR THE CONSOLIDATED FINANCIAL STATEMENTS Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with U.S. generally accepted accounting principles, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
AUDITORS' RESPONSIBILITY Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
OPINION In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of TransCanada Corporation as at December 31, 2014 and December 31, 2013, and its consolidated results of operations and its consolidated cash flows for each of the years in the three-year period ended December 31, 2014 in accordance with U.S. generally accepted accounting principles.
OTHER MATTER We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), TransCanada Corporation's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 12, 2015 expressed an unmodified (unqualified) opinion on the effectiveness of TransCanada Corporation's internal control over financial reporting.
Chartered AccountantsCalgary, Canada
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Report of Independent Registered Public Accounting Firm
TO THE SHAREHOLDERS OF TRANSCANADA CORPORATION We have audited TransCanada Corporation's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). TransCanada Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, TransCanada Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of TransCanada Corporation as of December 31, 2014 and December 31, 2013, and the related consolidated statements of income, comprehensive income, cash flows, and equity for each of the years in the three-year period ended December 31, 2014, and our report dated February 12, 2015 expressed an unmodified (unqualified) opinion on those consolidated financial statements.
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Consolidated statement of income
The accompanying notes to the consolidated financial statements are an integral part of these statements.
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Consolidated statement of comprehensive income
TransCanada Consolidated financial statements 2014 125
Consolidated statement of cash flows
126 TransCanada Consolidated financial statements 2014
Consolidated balance sheet
Commitments, Contingencies and Guarantees (Note 26)
Subsequent Events(Note 27)
On behalf of the Board:
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Consolidated statement of equity
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Notes to consolidated financial statements
1. DESCRIPTION OF TRANSCANADA'S BUSINESS
TransCanada Corporation (TransCanada or the Company) is a leading North American energy infrastructure company which operates in three business segments, Natural Gas Pipelines, Liquids Pipelines and Energy, each of which offers different products and services.
Natural Gas Pipelines The Natural Gas Pipelines segment consists of the Company's investments in 68,000 km (42,000 miles) of regulated natural gas pipelines and 400 Bcf of regulated natural gas storage facilities. These assets are located in Canada, the United States and Mexico.
Liquids Pipelines The Liquids Pipelines segment consists of 4,250 km (2,600 miles) of wholly owned and operated crude oil pipeline systems which connect Alberta and U.S. crude oil supplies to U.S. refining markets in Illinois, Oklahoma and Texas.
Energy The Energy segment primarily consists of the Company's investments in 19 electrical power generation plants and 2 non-regulated natural gas storage facilities. These include Canadian plants in Alberta, Ontario, Québec and New Brunswick and U.S. plants in New York, New England and Arizona.
2. ACCOUNTING POLICIES
The Company's consolidated financial statements have been prepared by management in accordance with United States generally accepted accounting principles (GAAP). Amounts are stated in Canadian dollars unless otherwise indicated.
Basis of Presentation The consolidated financial statements include the accounts of TransCanada and its subsidiaries. The Company consolidates its interest in entities over which it is able to exercise control. To the extent there are interests owned by other parties, these interests are included in Non-Controlling Interests. TransCanada uses the equity method of accounting for joint ventures in which the Company is able to exercise joint control and for investments in which the Company is able to exercise significant influence. TransCanada records its proportionate share of undivided interests in certain assets. Certain prior year amounts have been reclassified to conform to current year presentation.
Use of Estimates and Judgments In preparing these financial statements, TransCanada is required to make estimates and assumptions that affect both the amount and timing of recording assets, liabilities, revenues and expenses since the determination of these items may be dependent on future events. The Company uses the most current information available and exercises careful judgment in making these estimates and assumptions. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to:
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Actual results could differ from those estimates.
Regulation In Canada, regulated natural gas pipelines and liquids pipelines are subject to the authority of the National Energy Board (NEB) of Canada. In the U.S., natural gas pipelines, liquids pipelines and regulated natural gas storage assets are subject to the authority of the U.S. Federal Energy Regulatory Commission (FERC). In Mexico, natural gas pipelines are subject to the authority of the Energy Regulatory Commission of Mexico (CRE). The Company's Canadian, U.S. and Mexican natural gas transmission operations are regulated with respect to construction, operations and the determination of tolls. Rate-regulated accounting (RRA) standards may impact the timing of the recognition of certain revenues and expenses in TransCanada's rate-regulated businesses which may differ from that otherwise expected in non-rate-regulated businesses to appropriately reflect the economic impact of the regulators' decisions regarding revenues and tolls. TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain of our liquids pipelines projects. RRA is not applicable to the Keystone Pipeline System and, as a result, the regulators' decisions regarding operations and tolls on that system generally do not have an impact on timing of recognition of revenues and expenses.
Revenue Recognition
Natural Gas and Liquids Pipelines Revenues from the Company's natural gas and liquids pipelines, with the exception of Canadian natural gas pipelines which are subject to RRA, are generated from contractual arrangements for committed capacity and from the transportation of natural gas or crude oil. Revenues earned from firm contracted capacity arrangements are recognized ratably over the contract period regardless of the amount of natural gas or crude oil that is transported. Transportation revenues for interruptible or volumetric-based services are recognized when physical deliveries of natural gas or crude oil are made. The U.S. natural gas pipelines are subject to FERC regulations and, as a result, revenues collected may be subject to refund during a rate proceeding. Allowances for these potential refunds are recognized at the time of the regulatory decision.
Revenues from Canadian natural gas pipelines subject to RRA are recognized in accordance with decisions made by the NEB. The Company's Canadian natural gas pipeline rates are based on revenue requirements designed to recover the costs of providing natural gas transportation services, which include a return of and return on capital, as approved by the NEB. The Company's Canadian natural gas pipelines are not subject to risks related to variances in revenues and most costs. These variances are generally subject to deferral treatment and are recovered or refunded in future rates. The Company's Canadian natural gas pipelines are periodically subject to incentive mechanisms, as negotiated with shippers and approved by the NEB. These mechanisms can result in the Company recognizing more or less revenue than required to recover the costs that are subject to incentives. Revenues are recognized on firm contracted capacity ratably over the contract period. Revenues from interruptible or volumetric-based services are recorded when physical delivery is made. Revenues recognized prior to an NEB decision on rates for that period reflect the NEB's last approved rate of return on common equity (ROE) assumptions. Adjustments to revenue are recorded when the NEB decision is received.
Revenues from the Company's regulated natural gas storage services are recognized ratably over the contract period for firm committed capacity regardless of the amount of natural gas that is stored and when gas is injected or withdrawn for interruptible or volumetric-based services. The Company does not take ownership of the gas or oil that it transports or stores for others.
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Power Revenues from the Company's Energy business are primarily derived from the sale of electricity and from the sale of unutilized natural gas fuel, which are recorded at the time of delivery. Revenues also include capacity payments and ancillary services, as well as gains and losses resulting from the use of commodity derivative contracts. The accounting for derivative contracts is described in the Derivative Instruments and Hedging Activities section of this note.
Natural Gas Storage Revenues earned from providing non-regulated natural gas storage services are recognized in accordance with the terms of the natural gas storage contracts, which is generally over the term of the contract. Revenues earned on the sale of proprietary natural gas are recorded in the month of delivery. Derivative contracts for the purchase or sale of natural gas are recorded at fair value with changes in fair value recorded in Revenues.
Cash and Cash Equivalents The Company's Cash and Cash Equivalents consist of cash and highly liquid short-term investments with original maturities of three months or less and are recorded at cost, which approximates fair value.
Inventories Inventories primarily consist of materials and supplies, including spare parts and fuel, and natural gas inventory in storage, and are carried at the lower of weighted average cost or market.
Plant, Property and Equipment
Natural Gas Pipelines Plant, property and equipment for natural gas pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and compression equipment are depreciated at annual rates ranging from one per cent to six per cent, and metering and other plant equipment are depreciated at various rates, reflecting their estimated useful lives. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. The cost of regulated natural gas pipelines includes an allowance for funds used during construction (AFUDC) consisting of a debt component and an equity component based on the rate of return on rate base approved by regulators. AFUDC is reflected as an increase in the cost of the assets in plant, property and equipment and the equity component of AFUDC is a non-cash expenditure with a corresponding credit recognized in Interest Income and Other. Interest is capitalized during construction of non-regulated natural gas pipelines.
When regulated natural gas pipelines retire plant, property and equipment from service, the original book cost is removed from the gross plant amount and recorded as a reduction to accumulated depreciation. Costs incurred to remove a plant from service, net of any salvage proceeds, are also recorded in accumulated depreciation.
Liquids Pipelines Plant, property and equipment for liquids pipelines are carried at cost. Depreciation is calculated on a straight-line basis once the assets are ready for their intended use. Pipeline and pumping equipment are depreciated at annual rates ranging from two per cent to 2.5 per cent, and other plant and equipment are depreciated at various rates. The cost of these assets includes interest capitalized during construction for non-regulated liquids pipelines and AFUDC for regulated pipelines. When liquids pipelines retire plant, property and equipment from service, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.
Energy Power generation and natural gas storage plant, equipment and structures are recorded at cost and, once the assets are ready for their intended use, depreciated by major component on a straight-line basis over their estimated service lives at average annual rates ranging from two per cent to 20 per cent. Other equipment is
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depreciated at various rates. The cost of major overhauls of equipment is capitalized and depreciated over the estimated service lives of the overhauls. Interest is capitalized on facilities under construction. When these assets are retired from plant, property and equipment, the original book cost and related accumulated depreciation and amortization are derecognized and any gain or loss is recorded in earnings.
Corporate Corporate plant, property and equipment are recorded at cost and depreciated on a straight-line basis over their estimated useful lives at average annual rates ranging from three per cent to 20 per cent.
Impairment of Long-Lived Assets The Company reviews long-lived assets, such as plant, property and equipment, and intangible assets for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. If the total of the estimated undiscounted future cash flows is less than the carrying value of the assets, an impairment loss is recognized for the excess of the carrying value over the fair value of the assets.
Acquisitions and Goodwill The Company accounts for business acquisitions using the acquisition method of accounting and, accordingly, the assets and liabilities of the acquired entities are primarily measured at their estimated fair value at the date of acquisition. Goodwill is not amortized and is tested for impairment on an annual basis or more frequently if events or changes in circumstances indicate that the asset might be impaired. The annual review for goodwill impairment is performed at the reporting unit level which is one level below the Company's operating segments. The Company initially assesses qualitative factors to determine whether events or changes in circumstances indicate that the goodwill might be impaired. If TransCanada concludes that it is not more likely than not that fair value of the reporting unit is greater than its carrying value, the first step of the two-step impairment test is performed by comparing the fair value of the reporting unit to its book value, which includes goodwill. If the fair value is less than book value, an impairment is indicated and a second step is performed to measure the amount of the impairment. In the second step, the implied fair value of goodwill is calculated by deducting the recognized amounts of all tangible and intangible net assets of the reporting unit from the fair value determined in the initial assessment. If the carrying value of goodwill exceeds the calculated implied fair value of goodwill, an impairment charge is recorded in an amount equal to the difference.
Power Purchase Arrangements A PPA is a long-term contract for the purchase or sale of power on a predetermined basis. Substantially all PPAs under which TransCanada buys power are accounted for as operating leases. Initial payments for these PPAs were recognized in Intangible and Other Assets and amortized on a straight-line basis over the term of the contracts, which expire in 2017 and 2020. A portion of these PPAs has been subleased to third parties under terms and conditions similar to the PPAs. The subleases are accounted for as operating leases and TransCanada records the margin earned from the subleases as a component of Revenues.
Income Taxes The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred income tax assets and liabilities for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred income tax assets and liabilities are measured using enacted tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are expected to be reversed or settled. Changes to these balances are recognized in income in the period during which they occur except for changes in balances related to the Canadian Mainline, NGTL System and Foothills, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.
Canadian income taxes are not provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future.
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Asset Retirement Obligations The Company recognizes the fair value of a liability for asset retirement obligations (ARO) in the period in which it is incurred, when a legal obligation exists and a reasonable estimate of fair value can be made. The fair value is added to the carrying amount of the associated asset and the liability is accreted through charges to operating expenses.
Recorded ARO relates to the non-regulated natural gas storage operations and certain power generation facilities. The scope and timing of asset retirements related to natural gas pipelines, liquids pipelines and hydroelectric power plants is indeterminable. As a result, the Company has not recorded an amount for ARO related to these assets, with the exception of certain abandoned facilities.
Environmental Liabilities The Company records liabilities on an undiscounted basis for environmental remediation efforts that are likely to occur and where the cost can be reasonably estimated. The estimates, including associated legal costs, are based on available information using existing technology and enacted laws and regulations. The estimates are subject to revision in future periods based on actual costs incurred or new circumstances. Amounts expected to be recovered from other parties, including insurers, are recorded as an asset separate from the associated liability.
Emission allowances or credits purchased for compliance are recorded on the Balance Sheet at historical cost and expensed when they are utilized. Compliance costs are expensed when incurred. Allowances granted to or internally generated by TransCanada are not attributed a value for accounting purposes. When required, TransCanada accrues emission liabilities on the Balance Sheet upon the generation or sale of power using the best estimate of the amount required to settle the obligation. Allowances and credits not used for compliance are sold and any gain or loss is recorded in Revenues.
Stock Options and Other Compensation Programs TransCanada's Stock Option Plan permits options for the purchase of common shares to be awarded to certain employees, including officers. Stock options granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value as calculated using a binomial model and is recognized on a straight-line basis over the vesting period, with an offset to Additional Paid-In Capital. Upon exercise of stock options, amounts originally recorded against Additional Paid-In Capital are reclassified to Common Shares.
The Company has medium-term incentive plans, under which payments are made to eligible employees. The expense related to these incentive plans is accounted for on an accrual basis. Under these plans, benefits vest when certain conditions are met, including the employees' continued employment during a specified period and achievement of specified corporate performance targets.
Employee Post-Retirement Benefits The Company sponsors defined benefit pension plans (DB Plans), defined contribution plans (DC Plans), a savings plan and other post-retirement benefit plans. Contributions made by the Company to the DC Plans and savings plan are expensed in the period in which contributions are made. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined using the projected benefit method pro-rated based on service and management's best estimate of expected plan investment performance, salary escalation, retirement age of employees and expected health care costs.
The DB Plans' assets are measured at fair value at December 31 of each year. The expected return on the DB Plans' assets is determined using market-related values based on a five-year moving average value for all of the DB Plans' assets. Past service costs are amortized over the expected average remaining service life of the employees. Adjustments arising from plan amendments are amortized on a straight-line basis over the average remaining service life of employees active at the date of amendment. The Company recognizes the overfunded or underfunded status of its DB Plans as an asset or liability, respectively, on its Balance Sheet and
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recognizes changes in that funded status through Other Comprehensive Income (OCI) in the year in which the change occurs. The excess of net actuarial gains or losses over 10 per cent of the greater of the benefit obligation and the market-related value of the DB Plans' assets, if any, is amortized out of Accumulated Other Comprehensive Loss (AOCI) over the average remaining service life of the active employees. When the restructuring of a benefit plan gives rise to both a curtailment and a settlement, the curtailment is accounted for prior to the settlement.
For certain regulated operations, post-retirement benefit amounts are recoverable through tolls as benefits are funded. The Company records any unrecognized gains or losses or changes in actuarial assumptions related to these post-retirement benefit plans as either regulatory assets or liabilities. The regulatory assets or liabilities are amortized on a straight-line basis over the expected average remaining service life of active employees.
Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the company or reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date whereas non-monetary assets and liabilities are translated at the historical rate of exchange in effect on the date of the transaction. Exchange gains and losses resulting from translation of monetary assets and liabilities are recorded in income except for exchange gains and losses of the foreign currency debt related to Canadian regulated natural gas pipelines, which are deferred until they are refunded or recovered in tolls, as permitted by the NEB.
Gains and losses arising from translation of foreign operations' functional currencies to the Company's Canadian dollar reporting currency are reflected in OCI. Asset and liability accounts are translated at the period-end exchange rates while revenues, expenses, gains and losses are translated at the exchange rates in effect at the time of the transaction. The Company's U.S. dollar-denominated debt has been designated as a hedge of the net investment in foreign subsidiaries and, as a result, the unrealized foreign exchange gains and losses on the U.S. dollar denominated debt are also reflected in OCI.
Derivative Instruments and Hedging Activities All derivative instruments are recorded on the balance sheet at fair value, unless they qualify for and are designated under a normal purchase and normal sales exemption, or are considered to meet other permitted exemptions.
The Company applies hedge accounting to arrangements that qualify and are designated for hedge accounting treatment, which includes fair value and cash flow hedges, and hedges of foreign currency exposures of net investments in foreign operations. Hedge accounting is discontinued prospectively if the hedging relationship ceases to be effective or the hedging or hedged items cease to exist as a result of maturity, expiry, sale, termination, cancellation or exercise.
In a fair value hedging relationship, the carrying value of the hedged item is adjusted for changes in fair value attributable to the hedged risk and these changes are recognized in Net Income. Changes in the fair value of the hedged item, to the extent that the hedging relationship is effective, are offset by changes in the fair value of the hedging item, which are also recorded in Net Income. Changes in the fair value of foreign exchange and interest rate fair value hedges are recorded in Interest Income and Other and Interest Expense, respectively. If hedge accounting is discontinued, the carrying value of the hedged item is no longer adjusted and the cumulative fair value adjustments to the carrying value of the hedged item are amortized to Net Income over the remaining term of the original hedging relationship.
In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is initially recognized in OCI, while any ineffective portion is recognized in Net Income in the same financial statement category as the underlying transaction. When hedge accounting is discontinued, the
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amounts recognized previously in AOCI are reclassified to Revenues, Interest Expense and Interest Income and Other, as appropriate, during the periods when the variability in cash flows of the hedged item affects Net Income or as the original hedged item settles. Gains and losses on derivatives are reclassified immediately to Net Income from AOCI when the hedged item is sold or terminated early, or when it becomes probable that the anticipated transaction will not occur.
In hedging the foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instruments is recognized in OCI and the ineffective portion is recognized in Net Income. The amounts recognized previously in AOCI are reclassified to Net Income in the event the Company reduces its net investment in a foreign operation.
In some cases, derivatives do not meet the specific criteria for hedge accounting treatment. In these instances, the changes in fair value are recorded in Net Income in the period of change.
The recognition of gains and losses on derivatives for Canadian natural gas regulated pipelines exposures is determined through the regulatory process. Gains and losses arising from changes in the fair value of derivatives accounted for as part of RRA, including those that qualify for hedge accounting treatment, can be recovered through the tolls charged by the Company. As a result, these gains and losses are deferred as Regulatory Assets or Regulatory Liabilities and are refunded to or collected from the ratepayers, in subsequent years when the derivative settles.
Derivatives embedded in other financial instruments or contracts (host instrument) are recorded as separate derivatives. Embedded derivatives are measured at fair value if their economic characteristics are not clearly and closely related to those of the host instrument, their terms are the same as those of a stand-alone derivative and the total contract is not held for trading or accounted for at fair value. When changes in the fair value of embedded derivatives are measured separately, they are included in Net Income.
Long-Term Debt Transaction Costs The Company records Long-Term Debt transaction costs as other assets and amortizes these costs using the effective interest method for all costs except those related to the Canadian natural gas regulated pipelines, which continue to be amortized on a straight-line basis in accordance with the provisions of regulatory tolling mechanisms.
Guarantees Upon issuance, the Company records the fair value of certain guarantees entered into by the Company or partially owned entities for which contingent payments may be made. The fair value of these guarantees is estimated by discounting the cash flows that would be incurred by the Company if letters of credit were used in place of the guarantees as appropriate in the circumstances. Guarantees are recorded as an increase to Equity Investments, Plant, Property and Equipment, or a charge to Net Income, and a corresponding liability is recorded in Other Long-Term Liabilities.
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3. ACCOUNTING CHANGES
Changes in Accounting Policies for 2014
Obligations resulting from joint and several liability arrangements In February 2013, the FASB issued guidance for recognizing, measuring, and disclosing obligations resulting from joint and several liability arrangements when the total amount of the obligation is fixed at the reporting date. Debt arrangements, other contractual obligations, and settled litigation and judicial rulings are examples of these obligations. This new guidance was effective January 1, 2014 and there was no material impact on the Company's consolidated financial statements as a result of applying this new standard.
Foreign currency matters – cumulative translation adjustment In March 2013, the FASB issued amended guidance related to the release of the cumulative translation adjustment into net income when a parent either sells a part or all of its investment in a foreign entity or no longer holds a controlling financial interest in a subsidiary or group of assets that is a business. This new guidance was applied prospectively from January 1, 2014 and there was no material impact on the Company's consolidated financial statements as a result of applying this new standard.
Unrecognized tax benefit In July 2013, the FASB issued amended guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. This new guidance was effective January 1, 2014. There was no material impact on the Company's consolidated financial statements as a result of applying this new standard.
Future Accounting Changes
Reporting discontinued operations In April 2014, the FASB issued amended guidance on the reporting of discontinued operations. The criteria of what will qualify as a discontinued operation has changed and there are expanded disclosures required. This new guidance is effective from January 1, 2015 and will be applied prospectively. The Company does not expect the adoption of this new standard to have a material impact on its consolidated financial statements.
Revenue from contracts with customers In May 2014, the FASB issued new guidance on revenue from contracts with customers. This guidance supersedes the current revenue recognition requirements and most industry-specific guidance. This new guidance requires that an entity recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. This new guidance is effective from January 1, 2017 with two methods in which the amendment can be applied: (1) retrospectively to each prior reporting period presented, or (2) retrospectively with the cumulative effect recognized at the date of initial application. Early application is not permitted. The Company is currently evaluating the impact of the adoption of this ASU and has not yet determined the effect on its consolidated financial statements.
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4. SEGMENTED INFORMATION
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Geographic Information
5. OTHER CURRENT ASSETS
6. ASSETS HELD FOR SALE
The Company classifies assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and expects the sale to close within the next twelve months. Upon classifying an asset as held for sale, an asset is recorded at the lower of its carrying amount or its estimated fair value, reduced for selling costs, and depreciation expense is no longer recorded for that asset.
At December 31, 2013, the Company classified Cancarb Limited and its related power generation facility as assets held for sale in the Energy segment. The assets were recorded at their carrying amount at December 31, 2013.
On April 15, 2014, the Company sold these assets for aggregate gross proceeds of $190 million and recognized a gain of $108 million ($99 million after tax).
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7. PLANT, PROPERTY AND EQUIPMENT
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8. EQUITY INVESTMENTS
Distributions received from equity investments for the year ended December 31, 2014 were $726 million (2013 – $725 million; 2012 – $436 million) of which $147 million (2013 – $120 million; 2012 – $60 million) were returns of capital and are included in Deferred Amounts and Other in the Consolidated Statement of Cash Flows. The undistributed earnings from equity investments as at December 31, 2014 were $551 million (2013 – $754 million; 2012 – $883 million).
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Summarized Financial Information of Equity Investments
9. RATE-REGULATED BUSINESSES
TransCanada's businesses that apply RRA currently include Canadian, U.S. and Mexican natural gas pipelines, regulated U.S. natural gas storage and certain Canadian liquids pipelines currently under development. Regulatory assets and liabilities represent future revenues that are expected to be recovered from or refunded to customers based on decisions and approvals by the applicable regulatory authorities.
Canadian Regulated Operations The Canadian Mainline, NGTL System, Foothills and TQM pipelines are regulated by the NEB under the National Energy Board Act (Canada). The NEB regulates the construction and operation of facilities, and the terms and conditions of services, including rates, for the Company's Canadian regulated natural gas transmission systems.
TransCanada's Canadian natural gas transmission services are supplied under natural gas transportation tariffs that provide for cost recovery, including return of and return on capital as approved by the NEB. Rates charged for these services are typically set through a process that involves filing an application with the regulator wherein forecasted operating costs, including a return of and on capital, determine the revenue requirement for the upcoming year or multiple years. To the extent that actual costs and revenues are more or less than the forecasted costs and revenues, the regulators generally allow the difference to be deferred to a future period and recovered or refunded in rates at that time. Differences between actual and forecasted costs that the regulator does not allow to be deferred are included in the determination of net income in the year they occur.
Canadian Mainline On November 28, 2014, the NEB released its decision on TransCanada's 2015-2030 Tolls Application (the NEB 2014 Decision). The NEB 2014 Decision acknowledged that an off-ramp had been reached on the NEB 2013 Decision (discussed below) and approved fixed tolls for 2015 to 2020 as well as certain parameters for a toll setting methodology to 2030. Features of the settlement reached with shippers as approved in the NEB 2014 Decision include an ROE of 10.1 per cent on a deemed common equity of 40 per cent, an incentive mechanism that has both upside and downside risk and a $20 million after-tax annual TransCanada contribution to reduce the revenue requirement. Toll stabilization is achieved through the continued use of deferral accounts, namely the Long Term Adjustment Account (LTAA) and the Bridging Amortization Account, to capture the surplus or the shortfall between the Company's revenues and cost of service for each year over
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the six-year fixed toll term of the NEB 2014 Decision. TransCanada is required to file a compliance filing with the NEB in first quarter 2015 and a toll review for the 2018 to 2020 period prior to December 31, 2017.
In March 2013, TransCanada received a decision from the NEB which set tolls for 2013 through 2017 at competitive levels, fixing tolls for some services and providing unlimited pricing discretion for others (the NEB 2013 Decision). The decision established an ROE of 11.5 per cent on a deemed common equity of 40 per cent and included mechanisms to achieve the fixed tolls through the use of a LTAA as well as the establishment of a Tolls Stabilization Account (TSA) to capture the surplus or the shortfall between our revenues and our cost of service for each year over the five-year term of the decision. In addition, the decision provided an opportunity to generate incentive earnings by increasing revenues and reducing costs. The NEB also identified certain circumstances that would require a new tolls application prior to the end of the five-year term. One of those circumstances occurred in 2013 when the TSA balance became positive. In December 2013, TransCanada filed the 2015-2030 Tolls Application with the NEB that addressed tolls moving forward including tolls for 2014.
The Canadian Mainline's 2012 results reflect an ROE of 8.08 per cent on a deemed common equity of 40 per cent and excluded incentive earnings.
NGTL System In November 2013, the NEB approved the NGTL System's 2013-2014 Revenue Requirement Settlement Application. This settlement is structured similar to the previous multi-year settlement with fixed annual operating, maintenance and administration (OM&A) costs and a 10.1 per cent ROE on a deemed common equity of 40 per cent. Any variance between fixed OM&A costs in the settlement and actual costs accrue to TransCanada. The Settlement also establishes an increase in the composite depreciation rates to 3.05 per cent in 2013 and 3.12 per cent in 2014.
The NGTL System's 2012 results reflected a 9.70 per cent ROE on a deemed common equity of 40 per cent and fixed certain annual OM&A costs. Any variances between actual costs and those agreed to in the settlement then in effect accrued to TransCanada. All other costs were treated on a flow-through basis.
Energy East Energy East is currently in the development stage, awaiting regulatory approval from the NEB. Tolls will be designed to provide for cost recovery including return of and on capital as approved by the NEB.
Other Canadian Pipelines The Foothills operating model for 2012 through 2014 provides for recovery of all revenue requirement components on a flow-through basis. TQM operates under a model consisting of fixed and flow-through revenue requirement components for 2012 through 2016. Any variances between actual costs and those included in the fixed component accrue to TQM.
U.S. Regulated Operations TransCanada's U.S. natural gas pipelines are "natural gas companies" operating under the provisions of the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (NGA) and the Energy Policy Act of 2005, and are subject to the jurisdiction of the FERC. The NGA grants the FERC authority over the construction and operation of pipelines and related facilities. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. The Company's significant regulated U.S. natural gas pipelines are described below.
ANR ANR's natural gas transportation and storage services are provided under tariffs regulated by the FERC. These tariffs include maximum and minimum rates for services and allow ANR to discount or negotiate rates on a non-discriminatory basis. ANR Pipeline Company rates were established pursuant to a settlement approved by the FERC that was effective for all periods presented, beginning in 1997. ANR Pipeline Company is not required to conduct a review of currently effective rates with the FERC at any time in the future, but is not prohibited from filing for new rates if necessary.
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ANR Storage Company rates were established pursuant to a settlement approved by the FERC in August 2012. ANR Storage Company is required to file a NGA Section 4 general rate case no later than July 1, 2016.
TC Offshore LLC, another ANR-related regulated entity, began operating under FERC approved tariff rates on November 1, 2012. TC Offshore LLC is required to file a cost and revenue study to justify its existing approved cost-based rates after its first three years of operation.
Great Lakes Great Lakes is regulated by the FERC and operates in accordance with a FERC-approved tariff that establishes maximum and minimum rates for its various services and permits Great Lakes to discount or negotiate rates on a non-discriminatory basis. Great Lakes operated under a July 2010 FERC approved rate settlement through October 2013. Effective November 1, 2013, Great Lakes operates under rates established pursuant to a settlement approved by the FERC in November 2013. The settlement provides for a moratorium between November 2013 and March 2015 during which Great Lakes and the settling parties are prohibited from taking certain actions under the NGA, including filing to adjust rates. Great Lakes is required to file for new rates to be effective no later than January 2018.
Other U.S. Pipelines GTN and Bison are regulated by the FERC and operate in accordance with FERC-approved tariffs that establish maximum and minimum rates for various services. Both pipelines are permitted to discount or negotiate these rates on a non-discriminatory basis. GTN's rates were established pursuant to a settlement approved by the FERC in January 2012. GTN is required to file for new rates to be effective no later than January 2016.
Bison's rates were established pursuant to its initial certificate to construct and operate the pipeline that initiated service in January 2011. Bison filed a cost and revenue study as required by FERC to justify its existing approved cost-based rates after its first three years of operations. This study was filed by Bison on April 10, 2014 and accepted by FERC on May 20, 2014. At this time Bison is not required to conduct a review of currently effective rates with the FERC at any time in the future but is not prohibited from filing for new rates if necessary.
Mexico Regulated Operations TransCanada's Mexican operations are regulated by the CRE and operate in accordance with CRE-approved tariffs. In 2014, TransCanada began using RRA for all natural gas pipelines in Mexico. The rates were established based on CRE approved negotiated contracts.
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Regulatory Assets and Liabilities
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Allowance for Funds Used During Construction The total amount of AFUDC included in the Consolidated Statement of Income was $95 million in 2014, $19 million in 2013 and $15 million in 2012.
10. GOODWILL
The Company has recorded the following Goodwill on its acquisitions in the U.S.:
11. INTANGIBLE AND OTHER ASSETS
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The following amounts related to PPAs are included in Intangible and Other Assets:
Amortization expense for these PPAs was $52 million for the year ended December 31, 2014 (2013 and 2012 – $52 million). The expected annual amortization expense for 2015 to 2017 is $52 million, and $39 million for 2018 and 2019.
12. NOTES PAYABLE
Notes Payable consists of commercial paper issued by TransCanada PipeLines Limited (TCPL), TransCanada PipeLine USA Ltd. (TCPL USA), TransCanada American Investments Ltd. (TAIL), and TransCanada Keystone Pipeline, LP (TC Keystone) and drawings on credit facilities. The TC Keystone commercial paper program and facility were terminated in November 2013. The TAIL commercial paper program was initiated in November 2013, replacing the TCPL USA program which was terminated in April 2014.
Notes Payable also includes a US$170 million short-term loan, which was issued on October 1, 2014, by TC Pipelines LP.
At December 31, 2014, total committed revolving and demand credit facilities of $6.7 billion (2013 – $6.2 billion) were available. When drawn, interest on these lines of credit is charged at prime rates of
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Canadian and U.S. banks, and at other negotiated financial bases. These unsecured credit facilities included the following:
13. ACCOUNTS PAYABLE AND OTHER
14. OTHER LONG-TERM LIABILITIES
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15. LONG-TERM DEBT
150 TransCanada Consolidated financial statements 2014
Principal Repayments Principal repayments on the Long-Term Debt of the Company for the next five years are approximately as follows:
Long-Term Debt Issued The Company issued Long-Term Debt over the last three years ended December 31 as follows:
Long-Term Debt Retired The Company retired Long-Term Debt over the last three years ended December 31 as follows:
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Interest Expense
The Company made interest payments of $1,123 million in 2014 (2013 – $985 million; 2012 – $966 million) on Long-Term Debt and Junior Subordinated Notes, net of interest capitalized.
16. INCOME TAXES
Provision for Income Taxes
Geographic Components of Income
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Reconciliation of Income Tax Expense
Deferred Income Tax Assets and Liabilities
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The above deferred tax amounts have been classified in the Consolidated Balance Sheet as follows:
At December 31, 2014, the Company has recognized the benefit of unused non-capital loss carryforwards of $1,131 million (2013 – $1,026 million) for federal and provincial purposes in Canada, which expire from 2015 to 2034.
At December 31, 2014, the Company has recognized the benefit of unused net operating loss carryforwards of US$2,267 million (2013 – US$1,432 million) for federal purposes in the U.S., which expire from 2028 to 2034.
Unremitted Earnings of Foreign Investments Income taxes have not been provided on the unremitted earnings of foreign investments that the Company does not intend to repatriate in the foreseeable future. Deferred income tax liabilities would have increased at December 31, 2014 by approximately $236 million (2013 – $182 million) if there had been a provision for these taxes.
Income Tax Payments Income tax payments of $109 million, net of refunds, were made in 2014 (2013 – payments, net of refunds, of $202 million; 2012 – refunds, net of payments made, of $190 million).
Reconciliation of Unrecognized Tax Benefit Below is the reconciliation of the annual changes in the total unrecognized tax benefit:
TransCanada recognized a favourable income tax adjustment of approximately $25 million due to the enactment of certain Canadian Federal tax legislation in June 2013.
Subject to the results of audit examinations by taxing authorities and other legislative amendments, TransCanada does not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on its financial statements.
TransCanada and its subsidiaries are subject to either Canadian federal and provincial income tax, U.S. federal, state and local income tax or the relevant income tax in other international jurisdictions. The Company has substantially concluded all Canadian federal and provincial income tax matters for the years through 2009. Substantially all material U.S. federal income tax matters have been concluded for years through 2007 and U.S. state and local income tax matters through 2007.
154 TransCanada Consolidated financial statements 2014
TransCanada's practice is to recognize interest and penalties related to income tax uncertainties in Income Tax Expense. Income Tax Expense for the year ended December 31, 2014 reflects a $1 million reversal of Interest Expense and nil for penalties (2013 – $1 million increase of Interest Expense and nil for penalties; 2012 – $2 million reversal for Interest Expense and nil for penalties). At December 31, 2014, the Company had $5 million accrued for Interest Expense and nil accrued for penalties (December 31, 2013 – $6 million accrued for Interest Expense and nil accrued for penalties).
17. JUNIOR SUBORDINATED NOTES
Junior Subordinated Notes of US$1.0 billion mature in 2067 and bear interest at 6.35 per cent per annum until May 15, 2017, when interest will convert to a floating rate that is reset quarterly to the three-month London Interbank Offered Rate plus 221 basis points. The Company has the option to defer payment of interest for periods of up to 10 years without giving rise to a default or permitting acceleration of payment under the terms of the Junior Subordinated Notes, however, the Company would be prohibited from paying dividends during any such deferral period. The Junior Subordinated Notes are subordinated in right of payment to existing and future senior indebtedness and are effectively subordinated to all indebtedness and other obligations of TCPL. The Junior Subordinated Notes are callable at the Company's option at any time on or after May 15, 2017 at 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption. The Junior Subordinated Notes are callable earlier, in whole or in part, upon the occurrence of certain events and at the Company's option at an amount equal to the greater of 100 per cent of the principal amount of the Junior Subordinated Notes plus accrued and unpaid interest to the date of redemption and an amount determined by a specified formula in accordance with the terms of the Junior Subordinated Notes.
18. NON-CONTROLLING INTERESTS
The Company's Non-Controlling Interests included in the Consolidated Balance Sheet were as follows:
TransCanada Consolidated financial statements 2014 155
The Company's Non-Controlling Interests included in the Consolidated Statement of Income were as follows:
During 2014, the non-controlling interest in TC PipeLines, LP increased from 71.1 per cent to 71.7 per cent due to the issuance of common units in TC PipeLines, LP to non-controlling interests. The non-controlling interest in TC PipeLines, LP from May 2013 to August 2014 was 71.1 per cent and from May 2011 to May 2013 was 66.7 per cent.
The non-controlling interest in Portland as at December 31, 2014 represented the 38.3 per cent interest not owned by TransCanada (2013 and 2012 – 38.3 per cent).
On October 15, 2013, TCPL redeemed all of the four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series U at a price of $50 per share plus $0.5907 representing accrued and unpaid dividends to the redemption date.
On March 5, 2014, TCPL redeemed all of the four million outstanding 5.60 per cent cumulative redeemable first preferred shares Series Y at a price of $50 per share plus $0.2455 representing accrued and unpaid dividends to the redemption date.
In 2014, TransCanada received fees of $3 million from TC PipeLines, LP (2013 and 2012 – $3 million) and $8 million from Portland (2013 and 2012 – $7 million) for services provided.
19. COMMON SHARES
Common Shares Issued and Outstanding The Company is authorized to issue an unlimited number of common shares without par value.
156 TransCanada Consolidated financial statements 2014
Basic and Diluted Net Income per Share Net income per share is calculated by dividing Net Income Attributable to Common Shares by the weighted average number of common shares outstanding. The higher weighted average number of shares for the diluted earnings per share calculation is due to options exercisable under TransCanada's Stock Option Plan.
Stock Options
Stock options outstanding at December 31, 2014 were as follows:
An additional 8.2 million common shares were reserved for future issuance under TransCanada's Stock Option Plan at December 31, 2014. The weighted average fair value of options granted to purchase common shares under the Company's Stock Option Plan was determined to be $5.54 for the year ended December 31, 2014 (2013 – $5.74; 2012 – $5.08). The contractual life of options granted is seven years. Options may be exercised at a price determined at the time the option is awarded and vest 33.3 per cent on the anniversary date in each
TransCanada Consolidated financial statements 2014 157
of the three years following the award. Forfeiture of stock options results from their expiration and, if not previously vested, upon resignation or termination of the option holder's employment.
The Company used a binomial model for determining the fair value of options granted applying the following weighted average assumptions:
The amount expensed for stock options, with a corresponding increase in Additional Paid-In Capital, was $9 million in 2014 (2013 – $6 million; 2012 – $5 million).
The following table summarizes additional stock option information:
As at December 31, 2014, the aggregate intrinsic value of the total options exercisable was $85 million and the total intrinsic value of options outstanding was $118 million.
Shareholder Rights Plan TransCanada's Shareholder Rights Plan is designed to provide the Board with sufficient time to explore and develop alternatives for maximizing shareholder value in the event of a takeover offer for the Company and to encourage the fair treatment of shareholders in connection with any such offer. Attached to each common share is one right that, under certain circumstances, entitles certain holders to purchase two common shares of the Company for the then current market price of one.
158 TransCanada Consolidated financial statements 2014
20. PREFERRED SHARES
In January 2014, TransCanada completed a public offering of 18 million Series 9 cumulative redeemable first preferred shares at a price of $25.00 per share, resulting in gross proceeds of $450 million.
At December 31, 2014, holders of 12,501,577 Series 1 preferred shares exercised their option to convert to Series 2 preferred shares and receive floating rate, cumulative, quarterly, preferential dividends at a rate equal to the then 90-day Government of Canada Treasury bill rate + 1.92 per cent until December 31, 2019. The floating quarterly dividend rate for the Series 2 preferred shares for the first quarterly floating rate period (being the period from December 31, 2014 to but excluding March 31, 2015) is 2.82 per cent per annum and will reset every quarter. The 9,498,423 Series 1 preferred shares will pay on a quarterly basis, for the five-year period beginning on December 31, 2014 a fixed quarterly dividend based on an annual fixed dividend rate of 3.27 per cent.
TransCanada Consolidated financial statements 2014 159
21. OTHER COMPREHENSIVE INCOME AND ACCUMULATED OTHER COMPREHENSIVE LOSS
Components of OCI including Non-Controlling Interests and the related tax effects are as follows:
160 TransCanada Consolidated financial statements 2014
The changes in AOCI by component is as follows:
TransCanada Consolidated financial statements 2014 161
Details about reclassifications out of AOCI into the Consolidated Statement of Income are as follows:
22. EMPLOYEE POST-RETIREMENT BENEFITS
The Company sponsors DB Plans for its employees. Pension benefits provided under the DB Plans are based on years of service and highest average earnings over three consecutive years of employment. Upon commencement of retirement, pension benefits in the Canadian DB Plan increase annually by a portion of the increase in the Consumer Price Index. Past service costs are amortized over the expected average remaining service life of employees, which is approximately nine years (2013 and 2012 – nine years).
The Company also provides its employees with a savings plan in Canada, DC Plans consisting of 401(k) Plans in the U.S., and post-employment benefits other than pensions, including termination benefits and life insurance and medical benefits beyond those provided by government-sponsored plans. Past service costs are amortized over the expected average remaining life expectancy of former employees, which was approximately 12 years at December 31, 2014 (2013 – 11 years; 2012 – 12 years). In 2014, the Company expensed $37 million (2013 – $29 million; 2012 – $24 million) for the savings plan and DC Plans.
162 TransCanada Consolidated financial statements 2014
Total cash payments for employee post-retirement benefits, consisting of cash contributed by the Company were as follows:
Current Canadian pension legislation allows for partial funding of solvency requirements over a number of years through letters of credit in lieu of cash contributions, up to certain limits. As such, in addition to the cash contributions noted above, in 2014 the Company provided a $47 million letter of credit to the Canadian DB Plan (2013 – $59 million; 2012 – $48 million), resulting in a total of $181 million provided to the Canadian DB Plan under letters of credit at December 31, 2014.
The most recent actuarial valuation of the pension plans for funding purposes was as at January 1, 2014 and the next required valuation will be as at January 1, 2015.
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The amounts recognized in the Company's Balance Sheet for its DB Plans and other post-retirement benefits plans are as follows:
Included in the above benefit obligation and fair value of plan assets were the following amounts for plans that are not fully funded:
The accumulated benefit obligation for all DB pension plans at December 31, 2014 is $2,437 million (2013 – $2,039 million).
The funded status based on the accumulated benefit obligation for all DB Plans is as follows:
Included in the above accumulated benefit obligation and fair value of plan assets are the following amounts in respect of plans that are not fully funded.
164 TransCanada Consolidated financial statements 2014
The Company pension plans' weighted average asset allocations and target allocations by asset category were as follows:
Asset Category
Debt and equity securities include the Company's debt and common shares as follows:
Pension plan assets are managed on a going concern basis, subject to legislative restrictions, and are diversified across asset classes to maximize returns at an acceptable level of risk. Asset mix strategies consider plan demographics and may include traditional equity and debt securities, as well as alternative assets such as infrastructure, private equity, real estate and derivatives to diversify risk. Derivatives are not used for speculative purposes and the use of leveraged derivatives is prohibited.
All investments are measured at fair value using market prices. Where the fair value cannot be readily determined by reference to generally available price quotations, the fair value is determined by considering the discounted cash flows on a risk-adjusted basis and by comparison to similar assets which are publicly traded. In Level I, the fair value of assets is determined by reference to quoted prices in active markets for identical assets that the Company has the ability to access at the measurement date. In Level II, the fair value of assets is determined using valuation techniques, such as option pricing models and extrapolation using significant inputs, which are observable directly or indirectly. In Level III, the fair value of assets is determined using a market approach based on inputs that are unobservable and significant to the overall fair value measurement. For further information on the fair value hierarchy, refer to Note 23.
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The following table presents plan assets for DB Plans and other post-retirement benefits measured at fair value, which have been categorized into the three categories based on a fair value hierarchy.
The following table presents the net change in the Level III fair value category:
The Company's expected funding contributions in 2015 are approximately $70 million for the DB Plans, approximately $7 million for the other post-retirement benefit plans and approximately $36 million for the savings plan and DC Plans. The Company expects to provide an additional estimated $35 million letter of credit to the Canadian DB Plan for the funding of solvency requirements.
166 TransCanada Consolidated financial statements 2014
The following are estimated future benefit payments, which reflect expected future service:
The rate used to discount pension and other post-retirement benefit plan obligations was developed based on a yield curve of corporate AA bond yields at December 31, 2014. This yield curve is used to develop spot rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the spot rate curve to derive a weighted average discount rate.
The significant weighted average actuarial assumptions adopted in measuring the Company's benefit obligations were as follows:
The significant weighted average actuarial assumptions adopted in measuring the Company's net benefit plan costs were as follows:
The overall expected long-term rate of return on plan assets is based on historical and projected rates of return for the portfolio in aggregate and for each asset class in the portfolio. Assumed projected rates of return are selected after analyzing historical experience and estimating future levels and volatility of returns. Asset class benchmark returns, asset mix and anticipated benefit payments from plan assets are also considered in determining the overall expected rate of return. The discount rate is based on market interest rates of high-quality bonds that match the timing and benefits expected to be paid under each plan.
A 7.5 per cent average annual rate of increase in the per capita cost of covered health care benefits was assumed for 2015 measurement purposes. The rate was assumed to decrease gradually to five per cent by
TransCanada Consolidated financial statements 2014 167
2020 and remain at this level thereafter. A one per cent change in assumed health care cost trend rates would have the following effects:
The Company's net benefit cost is as follows:
Pre-tax amounts recognized in AOCI were as follows:
The estimated net loss and prior service cost for the DB Plans that will be amortized from AOCI into net periodic benefit cost in 2015 are $27 million and $2 million, respectively. The estimated net loss and prior service cost for the other post-retirement plans that will be amortized from AOCI into net periodic benefit cost in 2015 is $2 million and nil, respectively.
Pre-tax amounts recognized in OCI were as follows:
168 TransCanada Consolidated financial statements 2014
23. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Risk Management Overview TransCanada has exposure to market risk and counterparty credit risk, and has strategies, policies and limits in place to manage the impact of these risks on earnings, cash flow and, ultimately, shareholder value.
Risk management strategies, policies and limits are designed to ensure TransCanada's risks and related exposures are in line with the Company's business objectives and risk tolerance. Market risk and counterparty credit risk are managed within limits ultimately established by the Company's Board of Directors, implemented by senior management and monitored by the Company's risk management and internal audit groups. The Board of Directors' Audit Committee oversees how management monitors compliance with market risk and counterparty credit risk management policies and procedures, and oversees management's review of the adequacy of the risk management framework. Internal audit personnel assist the Audit Committee in its oversight role by performing regular and ad-hoc reviews of risk management controls and procedures, the results of which are reported to the Audit Committee.
Market Risk The Company constructs and invests in energy infrastructure projects, purchases and sells energy commodities, issues short-term and long-term debt, including amounts in foreign currencies, and invests in foreign operations. Certain of these activities expose the Company to market risk from changes in commodity prices, foreign exchange rates and interest rates, which may affect the Company's earnings and the value of the financial instruments it holds.
The Company uses derivatives as part of its overall risk management strategy to assist in managing the exposure to market risk that results from these activities. These derivative contracts may consist of the following:
Commodity Price Risk The Company is exposed to commodity price movements as part of its normal business operations, particularly in relation to the prices of electricity and natural gas. A number of strategies are used to manage these exposures, including the following:
TransCanada Consolidated financial statements 2014 169
Natural Gas Storage Commodity Price Risk TransCanada manages its exposure to seasonal natural gas price spreads in its non-regulated Natural Gas Storage business by economically hedging storage capacity with a portfolio of third-party storage capacity contracts and proprietary natural gas purchases and sales. TransCanada simultaneously enters into a forward purchase of natural gas for injection into storage and an offsetting forward sale of natural gas for withdrawal at a later period, thereby locking in future positive margins and effectively eliminating exposure to natural gas price movements. Unrealized gains and losses on fair value adjustments recorded each period on these forward contracts are not necessarily representative of the amounts that will be realized on settlement.
Foreign Exchange and Interest Rate Risk Foreign exchange and interest rate risk is created by fluctuations in the fair value or cash flow of financial instruments due to changes in foreign exchange rates and interest rates.
A portion of TransCanada's earnings from its Natural Gas Pipelines, Liquids Pipelines and Energy segments is generated in U.S. dollars and, therefore, fluctuations in the value of the Canadian dollar relative to the U.S. dollar can affect TransCanada's net income. As the Company's U.S. dollar-denominated operations continue to grow, exposure to changes in currency rates increases; some of this foreign exchange impact is partially offset by interest expense on U.S. dollar-denominated debt and by using foreign exchange derivatives.
The Company uses foreign currency and interest rate derivatives to manage the foreign exchange and interest rate risks related to other U.S. dollar-denominated transactions including those that may arise on some of the Company's regulated assets, in which case certain of the realized gains and losses on these derivatives would be deferred as regulatory assets and liabilities until they are recovered from or paid to the shippers.
TransCanada has floating interest rate debt which subjects it to interest rate cash flow risk. The Company uses a combination of interest rate swaps and options to manage its exposure to this risk.
Net Investment in Foreign Operations The Company hedges its net investment in foreign operations (on an after-tax basis) with U.S. dollar-denominated debt, cross-currency interest rate swaps, foreign exchange forward contracts and foreign exchange options.
U.S. Dollar-Denominated Debt Designated as a Net Investment Hedge
Derivatives Designated as a Net Investment Hedge
170 TransCanada Consolidated financial statements 2014
The balance sheet classification of the fair value of derivatives used to hedge the Company's net investment in foreign operations is as follows:
Counterparty Credit Risk Counterparty credit risk represents the financial loss the Company would experience if a counterparty to a financial instrument failed to meet its obligations in accordance with the terms and conditions of the related contract or agreement with the Company.
The Company manages its exposure to this potential loss by using recognized credit management techniques, including:
There is no guarantee that these techniques will protect the Company from material losses.
TransCanada's maximum counterparty credit exposure with respect to financial instruments at December 31, 2014, without taking into account security held, consisted of accounts receivable, portfolio investments recorded at fair value, the fair value of derivative assets and notes, loans and advances receivable. The Company regularly reviews its accounts receivable and records an allowance for doubtful accounts as necessary using the specific identification method. At December 31, 2014, there were no significant amounts past due or impaired, and there were no significant credit losses during the year. The Company had a credit risk concentration due from a counterparty of $258 million (US$222 million) and $240 million (US$225 million) at December 31, 2014 and 2013, respectively. This amount is expected to be fully collectible and is secured by a guarantee from the counterparty's investment grade parent company.
TransCanada has significant credit and performance exposures to financial institutions as they hold cash deposits and provide committed credit lines and letters of credit that help manage our exposure to counterparties and provide liquidity in commodity, foreign exchange and interest rate derivative markets.
Financial Instruments All financial instruments, including both derivative and non-derivative instruments, are recorded on the balance sheet at fair value unless they were entered into and continue to be held for the purpose of receipt or delivery in accordance with the Company's normal purchase and normal sales exemptions and are documented as such. In addition, fair value accounting is not required for other financial instruments that qualify for certain accounting exemptions.
Fair Value of Non-Derivative Financial Instruments The fair value of the Company's notes receivable is calculated by discounting future payments of interest and principal using forward interest rates. The fair value of Long-Term Debt is estimated using an income approach based on quoted market prices for the same or similar debt instruments from external data service providers.
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The fair value of available for sale assets has been calculated using quoted market prices where available. Credit risk has been taken into consideration when calculating the fair value of non-derivative instruments.
Certain non-derivative financial instruments included in Cash and Cash Equivalents, Accounts Receivable, Intangible and Other Assets, Notes Payable, Accounts Payable and Other, Accrued Interest and Other Long-Term Liabilities have carrying amounts that approximates their fair value due to the nature of the item or the short time to maturity and would be classified in Level II of the fair value hierarchy.
Balance Sheet Presentation of Non-Derivative Financial Instruments The following table details the fair value of the non-derivative financial instruments, excluding those where carrying amounts equal fair value, and would be classified in Level II of the fair value hierarchy:
Fair Value of Derivative Instruments The fair value of foreign exchange and interest rate derivatives have been calculated using the income approach which uses year-end market rates and applies a discounted cash flow valuation model. The fair value of power and natural gas derivatives and available for sale assets has been calculated using quoted market prices where available. In the absence of quoted market prices, third-party broker quotes or other valuation techniques have been used. Credit risk has been taken into consideration when calculating the fair value of derivative instruments.
In some cases, even though the derivatives are considered to be effective economic hedges, they do not meet the specific criteria for hedge accounting treatment or are not designated as a hedge and are accounted for at fair value with changes in fair value recorded in Net Income in the period of change. This may expose the Company to increased variability in reported earnings because the fair value of the derivative instruments can fluctuate significantly from period to period.
Balance Sheet Presentation of Derivative Instruments The balance sheet classification of the fair value of the derivative instruments is as follows:
172 TransCanada Consolidated financial statements 2014
2014 Derivative Instruments Summary The following summary does not include hedges of the net investment in foreign operations.
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2013 Derivative Instruments Summary The following summary does not include hedges of the net investment in foreign operations.
174 TransCanada Consolidated financial statements 2014
Derivatives in Cash Flow Hedging Relationships The following table presents the components of OCI (Note 21) related to derivatives in cash flow hedging relationships:
Offsetting of Derivative Instruments The Company enters into derivative contracts with the right to offset in the normal course of business as well as in the event of default. TransCanada has no master netting agreements, however, similar contracts are entered into containing rights of offset. The Company has elected to present the fair value of derivative instruments with the right to offset on a gross basis in the balance sheet. The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis:
TransCanada Consolidated financial statements 2014 175
The following table shows the impact on the presentation of the fair value of derivative instrument assets and liabilities had the Company elected to present these contracts on a net basis as at December 31, 2013:
With respect to all financial arrangements, including the derivative instruments presented above as at December 31, 2014, the Company had provided cash collateral of $459 million (2013 – $67 million) and letters of credit of $26 million (2013 – $85 million) to its counterparties. The Company held $1 million (2013 – $11 million) in cash collateral and $1 million (2013 – $32 million) in letters of credit from counterparties on asset exposures at December 31, 2014.
Credit Risk Related Contingent Features of Derivative Instruments Derivative contracts entered into to manage market risk often contain financial assurance provisions that allow parties to the contracts to manage credit risk. These provisions may require collateral to be provided if a credit-risk-related contingent event occurs, such as a downgrade in the Company's credit rating to non-investment grade.
Based on contracts in place and market prices at December 31, 2014, the aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a net liability position was $15 million (2013 – $16 million), for which the Company has provided collateral in the normal course of business of nil (2013 – nil). If the credit-risk-related contingent features in these agreements were triggered on December 31, 2014, the Company would have been required to provide additional collateral of $15 million (2013 – $16 million) to its counterparties. Collateral may also need to be provided should the fair value of derivative instruments exceed pre-defined contractual exposure limit thresholds.
The Company has sufficient liquidity in the form of cash and undrawn committed revolving bank lines to meet these contingent obligations should they arise.
176 TransCanada Consolidated financial statements 2014
Fair Value Hierarchy The Company's financial assets and liabilities recorded at fair value have been categorized into three categories based on a fair value hierarchy.
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The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2014, are categorized as follows:
The fair value of the Company's assets and liabilities measured on a recurring basis, including both current and non-current portions for 2013, are categorized as follows:
178 TransCanada Consolidated financial statements 2014
The following table presents the net change in fair value of derivative assets and liabilities classified as Level III of the fair value hierarchy:
A 10 per cent increase or decrease in commodity prices, with all other variables held constant, would result in a $1 million decrease or increase, respectively, in the fair value of outstanding derivative instruments included in Level III as at December 31, 2014.
24. CHANGES IN OPERATING WORKING CAPITAL
25. ACQUISITIONS AND DISPOSITIONS
Ontario Solar As part of a purchase agreement with Canadian Solar Solutions Inc. signed in 2011, TransCanada completed the acquisition of three Ontario solar facilities for $181 million in September 2014 and acquired a fourth facility for $60 million in December 2014. In 2013, TransCanada completed the acquisition of four solar facilities for $216 million. The Company's total investment in the eight solar facilities is $457 million. All power produced by the solar facilities is sold under 20-year PPAs with the Ontario Power Authority.
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Cancarb On April 15, 2014, TransCanada sold Cancarb Limited and its related power generation for aggregate gross proceeds of $190 million. Please refer to Note 6 for further information on the sale.
CrossAlta In December 2012, TransCanada purchased BP's 40 per cent interest in the assets of the Crossfield Gas Storage facility and BP's interest in CrossAlta Gas Storage & Services Ltd. (collectively CrossAlta) for $214 million in cash, net of cash acquired, resulting in the Company owning and operating 100 per cent of these operations.
The Company measured the assets and liabilities acquired at fair value and the transaction resulted in no goodwill. Upon completion of the acquisition, TransCanada began consolidating CrossAlta. Prior to the acquisition, TransCanada applied equity accounting to its 60 per cent ownership interest in CrossAlta.
TC PipeLines, LP On October 1, 2014, TransCanada completed the sale of its remaining 30 per cent interest in Bison Pipeline LLC (Bison LLC) to TC PipeLines, LP for an aggregate purchase price of US$215 million.
In July 2013, TransCanada completed the sale of a 45 per cent interest in each of GTN LLC and Bison LLC to TC PipeLines, LP for an aggregate purchase price of US$1.05 billion, which included US$146 million of long-term debt for 45 per cent of GTN LLC debt outstanding, plus normal closing adjustments. GTN LLC and Bison LLC own the GTN and Bison natural gas pipelines, respectively.
In May 2013, TC PipeLines, LP completed a public offering of 8,855,000 common units at a price of US$43.85 per unit, resulting in gross proceeds of approximately US$388 million and net proceeds of US$373 million after unit issuance costs. TransCanada contributed approximately US$8 million to maintain its two per cent general partnership interest and did not purchase any other units. Upon completion of this offering, TransCanada's ownership interest in TC PipeLines, LP decreased from 33.3 per cent to 28.9 per cent and an after-tax dilution gain of $29 million ($47 million pre-tax) was recorded in Additional Paid-In Capital.
Gas Pacifico/INNERGY On November 26, 2014, TransCanada sold its 30 per cent equity investments in Gas Pacifico and INNERGY for aggregate gross proceeds of $9 million and recognized a gain of $9 million ($8 million after tax).
180 TransCanada Consolidated financial statements 2014
26. COMMITMENTS, CONTINGENCIES AND GUARANTEES
Commitments
Operating Leases Future annual payments, net of sub-lease receipts, under the Company's operating leases for various premises, services and equipment are approximately as follows:
The operating lease agreements for premises, services and equipment expire at various dates through 2052, with an option to renew certain lease agreements for periods of one year to five years. Net rental expense on operating leases in 2014 was $114 million (2013 – $98 million; 2012 – $84 million).
TransCanada's commitments under the Alberta PPAs are considered to be operating leases and a portion of these PPAs have been subleased to third parties under similar terms and conditions. Fixed payments under these PPAs have been included in the above operating leases table. Variable payments have been excluded as these payments are dependent upon plant availability and other factors. TransCanada's share of payments under the PPAs in 2014 was $391 million (2013 – $242 million; 2012 – $238 million). The generating capacities and expiry dates of the PPAs are as follows:
TransCanada and its affiliates have long-term natural gas transportation and natural gas purchase arrangements as well as other purchase obligations, all of which are transacted at market prices and in the normal course of business.
Other Commitments Capital expenditure commitments include obligations related to the construction of growth projects and are based on the projects proceeding as planned. Changes to these projects, including cancellation, would reduce or possibly eliminate these commitments as a result of cost mitigation efforts.
At December 31, 2014, TransCanada was committed to Natural Gas Pipelines capital expenditures totaling approximately $0.9 billion (2013 – $1.3 billion), primarily related to construction costs related to the Mexican and other natural gas pipeline projects.
At December 31, 2014, the Company was committed to Liquids Pipelines capital expenditures totaling approximately $1.8 billion (2013 – $2.5 billion), primarily related to construction costs of Keystone XL, Grand Rapids and Northern Courier.
At December 31, 2014, the Company was committed to Energy capital expenditures totaling approximately $0.2 billion (2013 – $0.1 billion), primarily related to capital costs of the Napanee Generating Station.
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Contingencies TransCanada is subject to laws and regulations governing environmental quality and pollution control. As at December 31, 2014, the Company had accrued approximately $31 million (2013 – $32 million; 2012 – $37 million) related to operating facilities, which represents the present value of the estimated future amount it expects to expend to remediate the sites. However, additional liabilities may be incurred as assessments occur and remediation efforts continue.
TransCanada and its subsidiaries are subject to various legal proceedings, arbitrations and actions arising in the normal course of business. While the final outcome of such legal proceedings and actions cannot be predicted with certainty, it is the opinion of management that the resolution of such proceedings and actions will not have a material impact on the Company's consolidated financial position or results of operations.
Guarantees TransCanada and its joint venture partner on Bruce Power, BPC Generation Infrastructure Trust (BPC), have each severally guaranteed certain contingent financial obligations of Bruce B related to a lease agreement and contractor and supplier services. In addition, TransCanada and BPC have each severally guaranteed one-half of certain contingent financial obligations of Bruce A related to a sublease agreement and certain other financial obligations. The Company's exposure under certain of these guarantees is unlimited.
In addition to the guarantees for Bruce Power, the Company and its partners in certain other jointly owned entities have either (i) jointly and severally, (ii) jointly or (iii) severally guaranteed the financial performance of these entities related primarily to redelivery of natural gas, PPA payments and the payment of liabilities. For certain of these entities, any payments made by TransCanada under these guarantees in excess of its ownership interest are to be reimbursed by its partners.
The carrying value of these guarantees has been included in Other Long-Term Liabilities. Information regarding the Company's guarantees is as follows:
27. SUBSEQUENT EVENTS
On January 12, 2015 TCPL completed its offering of US$500 million 1.88 per cent Senior Notes due January 12, 2018 and US$250 million Floating Rate Senior Notes due January 12, 2018.
182 TransCanada Consolidated financial statements 2014
Supplementary information
SELECTED QUARTERLY AND ANNUAL CONSOLIDATED FINANCIAL DATA
TransCanada Corporation 2014 183
Five year financial highlights
184 TransCanada Corporation 2014
TransCanada Corporation 2014 185
Investor information
STOCK EXCHANGES, SECURITIES AND SYMBOLS
TransCanada CorporationCommon shares are listed on the Toronto and New York stock exchanges under the symbol: TRP
First Preferred Shares, Series 1 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.A
First Preferred Shares, Series 2 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.F
First Preferred Shares, Series 3 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.B
First Preferred Shares, Series 5 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.C
First Preferred Shares, Series 7 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.D
First Preferred Shares, Series 9 are listed on the Toronto Stock Exchange under the symbol: TRP.PR.E
Annual Meeting The annual and special meeting of shareholders is scheduled for May 1, 2015 at 10:00 a.m. (Mountain Daylight Time) at the BMO Centre, Calgary, Alberta.
Dividend Payment Dates Scheduled common share dividend payment dates in 2015 are January 30, April 30, July 31 and October 30.
For information on dividend payment dates for TransCanada Corporation visit our website at www.transcanada.com.
Dividend Reinvestment and Share Purchase Plan TransCanada's dividend reinvestment and share purchase plan (Plan) allows common and preferred shareholders of TransCanada to purchase common shares of TransCanada by reinvesting their cash dividends without incurring brokerage or administrative fees. Participants in the Plan may also buy additional common shares, up to Cdn$10,000 per quarter. For more information on the Plan please contact our Plan agent, Computershare Trust Company of Canada or visit our website at www.transcanada.com.
TRANSFER AGENTS, REGISTRARS AND TRUSTEES
TransCanada Corporation Common Shares Computershare Trust Company of Canada (Montréal, Toronto, Calgary, Halifax and Vancouver) and Computershare Trust Company, N.A. (Golden)
TransCanada Corporation First Preferred Shares, Series 1 Computershare Trust Company of Canada (Montréal, Toronto, Calgary, Halifax and Vancouver)
TransCanada Corporation First Preferred Shares, Series 2 Computershare Trust Company of Canada (Montréal, Toronto, Calgary, Halifax and Vancouver)
TransCanada Corporation First Preferred Shares, Series 3 Computershare Trust Company of Canada (Montréal, Toronto, Calgary, Halifax and Vancouver)
TransCanada Corporation First Preferred Shares, Series 5 Computershare Trust Company of Canada (Montréal, Toronto, Calgary, Halifax and Vancouver)
TransCanada Corporation First Preferred Shares, Series 7 Computershare Trust Company of Canada (Montréal, Toronto, Calgary, Halifax and Vancouver)
TransCanada Corporation First Preferred Shares, Series 9 Computershare Trust Company of Canada (Montréal, Toronto, Calgary, Halifax and Vancouver)
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TCPL Debentures
Canadian Series: BNY Trust Company of Canada (Halifax, Montréal, Toronto, Calgary and Vancouver)
U.S. Series: The Bank of New York (New York) 9.875%
TCPL Canadian Medium-Term Notes CIBC Mellon Trust Company (Halifax, Montréal, Toronto, Calgary and Vancouver)
TCPL U.S. Medium-Term Notes and Senior Notes The Bank of New York Mellon (New York)
TCPL U.S. Junior Subordinated Notes Computershare Trust Company, N.A.
NOVA Gas Transmission Ltd. (NGTL) Debentures
U.S. Series: U.S. Bank Trust National Association (New York) 7.875%
NGTL Canadian Medium-Term Notes BNY Trust Company of Canada (Halifax, Montréal, Toronto, Calgary and Vancouver)
NGTL U.S. Medium-Term Notes U.S. Bank Trust National Association (New York)
REGULATORY FILINGS
Annual Information Form TransCanada's 2014 Annual information form, as filed with Canadian securities commissions and as filed under Form 40-F with the SEC, is available on our website at www.transcanada.com.
A printed copy may be obtained from:
Corporate Secretary, TransCanada Corporation, 450 1st Street SW, Calgary, Alberta, Canada T2P 5H1
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Shareholder assistance
If you are a registered shareholder and have questions regarding your account, please contact our transfer agent in writing, by telephone or e-mail at:
Computershare Trust Company of Canada, 100 University Avenue, 8th Floor, Toronto, Ontario, Canada M5J 2Y1
E-mail: transcanada@computershare.com
www.computershare.com
If you hold your shares in a brokerage account (beneficial shareholder), questions should be directed to your broker on all administrative matters.
If you would like to receive quarterly reports, please contact Computershare or visit our website at www.transcanada.com.
Electronic Proxy Voting and Delivery of Documents TransCanada is pleased to offer registered and beneficial shareholders the ability to receive their documents (annual report, management information circular, notice of meeting and view-only proxy form) and vote online.
In 2015, registered shareholders who opt to receive their documents electronically will have a tree planted on their behalf through eTree. For more information and to sign up online, registered shareholders can visit www.etree.ca/transcanada.
Shareholders also have the ability to choose whether to receive TransCanada's annual report by regular mail. Each year, shareholders are required to renew their option and will receive a notification for doing so. The annual report is available on the TransCanada website at www.transcanada.com at the same time that the report is mailed to shareholders.
Electronic delivery and the ability to opt out of receiving the annual report by mail, provides increased convenience to shareholders, benefits to the environment and reduced mailing and printing costs for the company.
TransCanada in the Community TransCanada's annual Corporate Responsibility Report is available at www.transcanada.com. If you would like to receive a copy of this report by mail, please contact:
Communications 450 1st Street SW, Calgary, Alberta T2P 5H1, 1.403.920.2000 or 1.800.661.3805 or Communications@transcanada.com
Visit our website at www.transcanada.com to access TransCanada's corporate and financial information, including quarterly reports, news releases, real-time conference call webcasts and investor presentations.
Si vous désirez vous procurer un exemplaire de ce rapport en français, veuillez consulter notre site Web ou vous adresser par écrit à TransCanada Corporation, bureau du secrétaire.
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Board of directors
(as at December 31, 2014)
TransCanada Corporation 2014 189
Please refer to TransCanada's Notice of 2015 annual and special meeting of shareholders and Management information circular for the company's statement of corporate governance.
TransCanada's Corporate Governance Guidelines, Board charter, Committee charters, Chair and Chief Executive Officer terms of reference and Code of business ethics are available on our website at www.transcanada.com. Also available on our website is a summary of the significant ways in which TransCanada's corporate governance practices differ from those required to be followed by U.S. domestic companies under the New York Stock Exchange's listing standards.
Additional information relating to the company is filed with securities regulators in Canada on SEDAR (www.sedar.com) and in the United States on EDGAR (www.sec.gov). The documents referred to in this Annual report may be obtained free of charge by contacting TransCanada's Corporate Secretary at 450 1st Street SW, Calgary, Alberta, Canada T2P 5H1, or by telephoning 1.800.661.3805.
Ethics Help-Line The Audit Committee of the Board of Directors has established an anonymous and confidential toll-free telephone number for employees, contractors and others to call with respect to accounting irregularities and ethical violations. The Ethics Help-Line number is 1.888.920.2042.
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designed and produced by smith + associates www.smithandassoc.com Please recycle. Shareholder Information TransCanada welcomes questions from shareholders and investors. Please contact: David Moneta, Vice-President, Investor Relations 1.800.361.6522 (Canada and U.S. Mainland) investor_relations@transcanada.com www.transcanada.com Listing Information Common Shares (TSX, NYSE): TRP Preferred Shares (TSX): Series 1: TRP.PR.A Series 2: TRP.PR.F Series 3: TRP.PR.B Series 5: TRP.PR.C Series 7: TPR.PR.D Series 9: TPR.PR.E Transfer Agent Computershare Investor Services 100 University Avenue, 8th Floor Toronto, Ontario M5J 2Y1 Phone: +1 416 263 9200 Fax: +1 888 453 0330 Corporate Social Responsibility Report Building a successful future means doing the right thing today. View our CSR report: www.csrreport.transcanada.com Corporate Head Office TransCanada Corporation 450 - 1 Street SW Calgary, Alberta, Canada T2P 5H1 Follow us on Twitter: @TransCanada and @TransCanadaJobs Search Careers: Jobs.TransCanada.com Connect on Linkedin: Linkedin.com/Company/TransCanada Subscribe to us on YouTube: YouTube.com/TransCanada Check out our blog: Blog.TransCanada.com
Our annual report is online, visit our site for more information. www.transcanada.com Printed in Canada March 2015
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