UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 40-F
 
[Check one]
 
o           REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
 
OR
 
x   ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2020 Commission file number 001-15214
 
 
TRANSALTA CORPORATION
(Exact name of Registrant as specified in its charter)
 
 
Not applicable
(Translation of Registrant’s name into English (if applicable))
 
 
Canada
(Province or other jurisdiction of incorporation or organization)
 
 
4911
(Primary Standard Industrial Classification Code Number (if applicable))
 
 
Not Applicable
(I.R.S Employer Identification Number (if applicable))
 
 
 
110-12th Avenue S.W., Box 1900, Station “M”,
Calgary, Alberta, Canada, T2P 2M1,
(403) 267-7110
(Address and telephone number of Registrant’s principal executive offices)
 
 
TransAlta Centralia Generation LLC
913 Big Hanaford Road, Centralia, Washington 98531, (360) 736-9901
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)


Securities registered or to be registered pursuant to Section 12(b) of the Act:
 
Title of each class   Name of each exchange  
    on which registered  
       
     
Common Shares, no par value New York Stock Exchange  
     
Common Share Purchase Rights New York Stock Exchange  
 
 
Securities registered or to be registered pursuant to Section 12(g) of the Act:
 
None
 
 
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
 
Debt Securities
 
 
For annual reports, indicate by check mark the information filed with this form:
 
x        Annual information form
x        Audited annual financial statements

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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, 2020, 270,244,741 common shares were issued and outstanding.
 
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.
 
Yes  x
No  o
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).
 
Yes  x
No  o
 

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ¨

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

 
INCORPORATION BY REFERENCE
 
The documents, forming part of this Form 40-F, are incorporated by reference into the following registration statements under the Securities Act of 1933, as amended.
 
Form Registration No.
S-8 333-72454
S-8 333-101470
S-8 333-236894
F-10 333-229991
 
 
CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS
AND MANAGEMENT’S DISCUSSION & ANALYSIS
 
A.                                             Consolidated Audited Annual Financial Statements
 
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For consolidated audited annual financial statements for the year ended December 31, 2020, including the report of independent chartered professional accountants with respect thereto, see Exhibit 13.3 incorporated by reference herein.
 
B.                                              Management’s Discussion and Analysis
 
For management’s discussion and analysis, see Exhibit 13.2 incorporated by reference herein.

DISCLOSURE CONTROLS AND PROCEDURES
 
As required by Rule 13a-15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act are recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission (the "Commission"). Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under the Exchange Act are accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding our required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management was required to apply its judgment in evaluating and implementing possible controls and procedures.
 
Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2020, the end of the period covered by this report, our disclosure controls and procedures were effective at a reasonable assurance level.
 
MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
 
Management is responsible for establishing and maintaining adequate internal control over financial reporting.
 
Internal control over financial reporting refers to a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer 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 generally accepted accounting principles and includes those policies and procedures that:
 
•pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of our assets;
 
•provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and members of our board of directors; and
 
•provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
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Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2020 using the Committee of Sponsoring Organizations of the Treadway Commission (COSO) 2013 framework.  Management concluded that our internal control over financial reporting was effective as of December 31, 2020.  Certain matters relating to the scope of management’s evaluation and limitations of management’s conclusions are described below.  See “Limitations and Scope of Management’s Report on Internal Control over Financial Reporting.”
 
Our Chartered Professional Accountants, Ernst & Young LLP, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2020.  For the Report of Independent Registered Public Accounting Firm see page F3 of the Consolidated Audited Annual Financial Statements for the year ended December 31, 2020, filed as Exhibit 13.3 and incorporated by reference herein, under the heading “Report of Independent Registered Public Accounting Firm”.
 
There has been no change in our internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
LIMITATIONS AND SCOPE OF MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations.  Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures.  Internal control over financial reporting also can be circumvented by collusion or improper overrides.  Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting.  However, these inherent limitations are known features of the financial reporting process, and it is possible to design safeguards into the process to reduce, though not eliminate, this risk.
 
TransAlta Corporation (“TransAlta” or the “Company”) proportionately consolidates the accounts of the Sheerness and Pioneer Pipeline joint operations, and equity accounts for investments in SP Skookumchuck Investment, LLC and EMG International, (the “Excluded Entities”), in accordance with International Financial Reporting Standards (“IFRS”). Management does not have the contractual ability to assess the internal controls of these Excluded Entities. Management’s conclusion regarding the effectiveness of internal controls does not extend to the internal controls at the transactional level of these Excluded Entities. Accordingly, management’s evaluation of the Company’s internal control over financial reporting did not include an evaluation of the internal controls of any of the Excluded Entities, and management’s conclusion regarding the effectiveness of the Company’s internal control over financial reporting does not extend to the internal controls of any of the Excluded Entities.
 
The 2020 consolidated financial statements of TransAlta, in accordance with EITF 00-1, included for joint operations are CDN$381 million and CDN$294 million of total and net assets, respectively, as of December 31, 2020, and CDN$112 million and CDN$5 million of revenues and net earnings, respectively, for the year then ended related to Excluded Entities.  In addition, as of December 31, 2020, we also included CDN$100 million of equity investments and CDN$1 million of equity income for the year then ended related to Excluded Entities.Once the financial information is obtained from these Excluded Entities it falls within the scope of TransAlta’s internal control framework.
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AUDIT COMMITTEE FINANCIAL EXPERT
 
TransAlta’s board of directors has determined that it has two audit committee financial experts serving on its Audit, Finance and Risk Committee (the “AFRC”). Ms. Beverlee F. Park, and Mr. Bryan D. Pinney have each been determined to be an audit committee financial expert, within the meaning of Section 407 of the United States Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”), and are independent, as that term is defined by the New York Stock Exchange’s (“NYSE”) listing standards applicable to TransAlta. For further information regarding the experience and qualification of Ms. Park and Mr. Pinney, see the section titled “Audit, Finance and Risk Committee” in our Annual Information Form for the year ended December 31, 2020 filed as Exhibit 13.1 and incorporated by reference herein. Under the Commission rules, the designation of persons as audit committee financial experts does not make them “experts” for any other purpose, impose any duties, obligations or liability on them that are greater than those imposed on members of their committee and the board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of their committee.
 
CODE OF ETHICS
 
TransAlta has adopted a code of ethics as part of its “Corporate Code of Conduct” that applies to all employees and officers which has been filed with the Commission. In addition, TransAlta has adopted a code of conduct applicable to all directors of the Company, a separate financial code of conduct which applies to all financial management employees and an Energy Trading code of conduct for our employees working within energy marketing. Our codes of conduct are available on our Internet website at www.transalta.com. There has been no waiver of the codes granted during the 2020 fiscal year.
 
PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
For the years ended December 31, 2020 and December 31, 2019, Ernst & Young LLP and its affiliates billed or expect to bill , including out-of-pocket costs, $4,703,316 and $4,306,184, respectively, as detailed below:
 
Ernst & Young LLP
 
Year Ended Dec. 31 2020 2019
Audit Fees(1)
$ 2,574,625  $ 2,492,025 
Audit-related fees(1)(2)
1,294,822  1,375,038 
Tax fees 833,869  439,121 
All other fees —  — 
Total $ 4,703,316  $ 4,306,184 
 (1) Comparative figures have been reclassified to confirm to the current periods classification of fees.
(2) Included in the audit-related fees are $861,338 (2019 - $887,257) of fees billed to TransAlta Renewables.

All amounts are in Canadian dollars unless otherwise stated.
 
No other audit firms provided audit services in 2020 or 2019.
 
The nature of each category of fees is described below:
 
Audit Fees
 
Audit fees are for professional services rendered for the audit and review of our financial statements or services provided in connection with statutory and regulatory filings and providing comfort letters associated with securities documents.
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Audit-Related Fees
 
Assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not included under "Audit Fees". Audit-Related fees include statutory audits, pension audits and other compliance audits. In 2020 and 2019, we have included the fees billed to TransAlta Renewables, a controlled and consolidated subsidiary of TransAlta.
 
Tax Fees
 
Tax fees are tax-related services for review of tax returns, assistance with questions on tax audits, and tax planning.
 
All Other Fees
 
Products and services provided by the Corporation's auditor other than those services reported under "Audit Fees", "Audit-Related Fees" and "Tax Fees". This includes fees related to training services provided by the auditor.

 
Pre-Approval Policies and Procedures
 
The AFRC has considered whether the provision of services other than audit services is compatible with maintaining the auditors’ independence.  In May 2002, the AFRC adopted a policy that prohibits TransAlta from engaging the auditors for “prohibited” categories of non-audit services and requires pre-approval of the AFRC for other permissible categories of non-audit services, such categories being determined under the Sarbanes-Oxley Act of 2002. This policy also provides that the Chair of the AFRC may approve permissible non-audit services during the quarter and report such approval to the AFRC at its next regularly scheduled meeting.
 
Percentage of Services Approved by the AFRC
 
For the year ended December 31, 2020, none of the services described above were approved by the AFRC pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.
 
 
OFF-BALANCE SHEET ARRANGEMENTS
 
TransAlta currently has no off-balance sheet arrangements.  See page M53 of Exhibit 13.2, incorporated by reference herein under the heading “Unconsolidated Structured Entities or Arrangements”.
 
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
 
See page M54 of Exhibit 13.2, incorporated by reference herein, under the heading “Other Consolidated Analysis” and page F94 under the heading “Commitments and Contingencies” of Exhibit 13.3, all incorporated by reference herein.
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IDENTIFICATION OF THE AUDIT COMMITTEE
 
We have a separately-designated standing AFRC established in accordance with Section 3(a)58(A) of the Exchange Act, and made up of independent directors.  The members of the AFRC are:
 
Beverlee F. Park (Chair)
Georgia R. Nelson
Alan J. Fohrer
Bryan D. Pinney

 
MINE SAFETY
 
The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 13.1, incorporated herein, under the heading “Business of TransAlta – Centralia Business Segment”.
 
FORWARD-LOOKING INFORMATION
 
This Form 40-F, the documents incorporated herein by reference, and other reports and filings of the Company made with the securities regulatory authorities, include "forward-looking statements" within the meaning of applicable US securities laws, including the US Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made, and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may," "will," "can," "could," "would," "shall," "believe," "expect," "estimate," "anticipate," "intend," "plan," "forecast," "foresee," "potential," "enable," "continue" or other comparable terminology. These statements are not guarantees of our future performance, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from that set out in or implied by the forward-looking statements.
In particular, this Form 40-F contains forward-looking statements including, but not limited to: operating performance and transition to clean power generation, including our goal to eliminate coal as a fuel source in the Alberta thermal fleet by 2021; our Clean Energy Investment Plan and the benefits thereof; transitioning to 100 per cent clean electricity by 2025; the source of funding for the Clean Energy Investment Plan; our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2021 and beyond, including potential for growth in renewables and on-site and cogeneration assets, including the demand therefor and greenfield development acquisitions; the amount of capital allocated to new growth or development projects and the funding thereof; our business, anticipated future financial performance and anticipated results, including our outlook and performance targets; our expectation that the sale of TransAlta's interest in the Pioneer Pipeline will close in 2021; receiving funding under the Canada Emergency Wage Subsidy program; the ability to reach a commercial solution with Energy Transfer Canada regarding the construction and operation of the Kaybob 3 cogeneration facility; the timing and the completion of growth and development projects, and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations and maintenance, and the variability of those costs; the conversion or repowering of our coal-fired units to natural gas, and the timing and costs thereof; expectations relating to the benefits of the conversions and repowering; the terms of the current or any further proposed share buyback programs, including timing and number of shares to be repurchased pursuant to any normal course issuer bid and the acceptance thereof by the Toronto Stock Exchange ("TSX"); the mothballing of certain units; the impact of certain hedges on future earnings, results and cash flows; estimates of fuel supply and demand conditions
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and the costs of procuring fuel; expectations for demand for electricity, including for clean energy, in both the short term and long term, and the resulting impact on electricity prices; the impact of load growth, increased capacity and natural gas and other fuel costs on power prices; expectations in respect of generation availability, capacity and production; expectations regarding the role that different energy sources will play in meeting future energy needs; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation, as well as the cost of complying with resulting regulations and laws; our marketing and trading strategy and the risks involved in these strategies; estimates of future tax rates, future tax expense and the adequacy of tax provisions; changes in accounting estimates and accounting policies; the mitigation of risks and effectiveness thereof, including as it pertains to climate change risk, environmental management, cybersecurity, commodity prices and fuel supply; anticipated growth rates and competition in our markets; our expectations and obligations and anticipated liabilities relating to the outcome of existing or potential legal and contractual claims, regulatory investigations and disputes, including the litigation with Fortescue Metals Group Ltd. relating to the South Hedland facility and the Mangrove (as defined below) proceedings relating to the Brookfield Investment, each discussed further below; our ability to achieve our E2SG targets; expectations regarding the renewal of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the US dollar, the Australian dollar and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment and growing scrutiny by investors relating to sustainability performance; and our credit practices.
The forward-looking statements contained in this Form 40-F are based on many assumptions including, but not limited to, the following: the impacts arising from COVID-19 not becoming significantly more onerous on the Corporation, which includes the Corporation being permitted to continue to operate as an essential service; no significant changes to applicable laws and regulations, including any tax and regulatory changes in the markets in which we operate; no material adverse impacts to investment and credit markets; Alberta spot power prices being in the range of $58 to $68 per megawatt hour ("MWh") in 2021; Mid-C spot power prices being in the range of US$25 to US$35 per MWh in 2021; sustaining capital in 2021 being between $175 million and $210 million; productivity capital of $3 million to $7 million; applicable discount rates; our proportionate ownership of TransAlta Renewables Inc. ("TransAlta Renewables") not changing materially; no decline in the dividends to be received from TransAlta Renewables; the expected life extension of the Alberta thermal fleet and anticipated financial results generated on conversion or repowering; assumptions regarding the ability of the converted units to successfully compete in the Alberta energy market; and assumptions regarding our current strategy and priorities, including as it pertains to our current priorities relating to the conversion to gas, growing TransAlta Renewables and realizing the full economic benefit from our capacity, energy and ancillary services.
Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this Form 40-F include, but are not limited to, risks relating to the impact of COVID-19, which cannot currently be predicted, and which present risks including, but not limited to: more restrictive directives of government and public health authorities; reduced labour availability and ability to continue to staff our operations and facilities; disruptions to our supply chains, including our ability to secure necessary equipment or to obtain regulatory approvals on the expected timelines or at all; COVID-19-related force majeure claims; restricted access to capital and increased borrowing costs; a further decrease in short-term and/or long-term electricity demand and lower merchant pricing in Alberta and Mid-C; reductions in production; increased costs resulting from our efforts to mitigate the impact of COVID-19; deterioration of worldwide credit and financial markets; a higher rate of losses on our accounts receivable due to credit defaults; impairments and/or writedowns of assets; and adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats. The forward-looking statements are also subject to other risk factors that include, but are not limited to: fluctuations in market prices; changes in demand for electricity and capacity and our ability to contract our generation for prices that will provide expected returns and replace contracts as they expire; changes to the legislative,
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regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic or market conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather and other climate-change related risks; unexpected increases in cost structure; disruptions in the source of fuels, including natural gas required for the conversions and repowering, as well as the extent of water, solar or wind resources required to operate our facilities; failure to meet financial expectations; natural and man-made disasters, including those resulting in dam or dyke failures; the threat of domestic terrorism and cyberattacks; pandemics or epidemics and any associated impact on supply chain; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner, timely manner or at all; commodity risk management and energy trading risks; industry risk and competition; the need to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign political risks; the need for and availability of additional financing; structural subordination of securities; counterparty credit risk; changes to our relationship with, or ownership of, TransAlta Renewables; risks associated with development projects and acquisitions, including capital costs, permitting, labour and engineering risks, and delays in the construction or commissioning of projects or delays in the closing of acquisitions; changes in expectations in the payment of future dividends, including from TransAlta Renewables; inadequacy or unavailability of insurance coverage; downgrades in credit ratings; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland facility and in relation to the Brookfield Investment; reliance on key personnel; and labour relations matters. The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of our Management Discussion & Analysis and in the Risk Factors section in our Annual Information Form for the year ended Dec. 31, 2020, which form part of this Form 40-F.
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on them, which reflect the Corporation's expectations only as of the date hereof. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. The purpose of the financial outlooks contained herein is to give the reader information about management's current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.
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UNDERTAKING
 
TransAlta 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.
 
CONSENT TO SERVICES OF PROCESS
 
TransAlta has previously filed a Form F-X in connection with the class of securities in relation to which the obligation to file this report arises and is filing contemporaneously herewith an amendment to the Form F-X to report a change in the agent for service of process.  Any change to the name or address of the agent for service of process of TransAlta shall be communicated promptly to the Commission by an amendment to the Form F-X referencing the file number of TransAlta.
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EXHIBIT INDEX

13.1 TransAlta Corporation Annual Information Form for the year ended Dec. 31, 2020
13.2 Management’s Discussion and Analysis for the year ended Dec. 31, 2020
13.3 Consolidated Audited Annual Financial Statements for the year ended Dec. 31, 2020
13.4 Management’s Annual Report on Internal Control over Financial Reporting, (included on page F2 of Exhibit 13.3 filed herewith).
23.1 Consent of Independent Registered Public Accounting Firm.
31.1 Certification of President and 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 President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101 Interactive Data File

 
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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.
 
 
  TRANSALTA CORPORATION
   
   
   
  /s/ Todd Stack
  Todd Stack
  Executive Vice-President, Finance and Chief Financial Officer
   
Dated: March 2, 2021  

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TRANSALTALOGO_CMYKXPOWERIN.JPG


TRANSALTA CORPORATION
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2020


March 2, 2021





Table of Contents
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North American Gas Business Segment
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Alberta Thermal Business Segment
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Presentation of Information
Unless otherwise noted, the information contained in this annual information form ("Annual Information Form" or "AIF") is given as at or for the year ended Dec. 31, 2020. All dollar amounts are in Canadian dollars unless otherwise noted. Unless the context otherwise requires, all references to the "Corporation" and to "TransAlta," "we," "our" and "us" herein refer to TransAlta Corporation and its subsidiaries, including TransAlta Renewables Inc., on a consolidated basis. Reference to "TransAlta Corporation" herein refers to TransAlta Corporation, excluding its subsidiaries. Capitalized terms not defined in the body of this AIF shall have their respective meanings set forth in Appendix "B" – Glossary of Terms hereto.
Special Note Regarding Forward-Looking Statements
This Annual Information Form, including the documents incorporated herein by reference, includes "forward-looking information," within the meaning of applicable Canadian securities laws, and "forward-looking statements," within the meaning of applicable United States securities laws, including the Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may,", "will", "can," "could," "would," "shall," "believe," "expect," "estimate," "anticipate," "intend," "plan," "forecast," "foresee," "potential," "enable," "continue" or other comparable terminology. These statements are not guarantees of our future performance, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from that set out in the forward-looking statements.
In particular, this Annual Information Form (or a document incorporated herein by reference) contains forward-looking statements including, but not limited to: our operating performance and transition to clean power generation, including our goal to have no generation from coal by the end of 2025; the conversion or repowering of our coal-fired units to natural gas and the timing thereof, the amount of capital allocated thereto and the expectations relating to shareholder returns relating to such conversions; the benefits of our Clean Energy Investment Plan, including being a low-cost generator, extending the life of the assets and reducing air emissions and costs; the source of funding for the Clean Energy Investment Plan; our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2020 to 2031 and beyond; potential for growth in renewables and on-site and cogeneration assets, including the timing of commercial operation, and cost, for projects currently under development and construction; the amount of capital allocated to new growth or development projects; our business and anticipated future financial performance and anticipated results, including our outlook and performance targets; our expected success in executing on our growth and development projects; our expectation regarding the anticipated closing date for the sale of TransAlta's interest in the Pioneer Pipeline; the benefits of the Brookfield Investment (as defined below); the timing and completion of growth projects and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations, capital spend, and maintenance, and the variability of those costs; the terms of the current or any further proposed share buyback program and the acceptance thereof by the Toronto Stock Exchange ("TSX"), including the timing and number of shares to be repurchased pursuant to any normal course issuer bid; the mothballing of certain units; the impact of certain hedges on future earnings, results and cash flows; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity, including for clean energy, in both the short-term and long-term, and the resulting impact on electricity prices; the impact of load growth, increased capacity and natural gas and other fuel costs on power prices; expectations in respect of generation availability, capacity and production; expectations regarding the role different energy sources, including renewable power generation, will play in meeting future energy needs; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation, including the timing of the implementation of such regimes and regulations, as well as the cost of complying with resulting regulations and laws; our trading strategy and the risks involved in these strategies; estimates of future tax rates, future tax expense and the adequacy of tax provisions; accounting estimates and accounting policies; anticipated growth rates and competition in our markets; our expectations relating to the outcome of existing or potential legal and contractual claims, regulatory investigations and disputes; expectations regarding the renewal of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms or at all; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the US dollar and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment and growing scrutiny by investors relating to sustainability performance; and our credit practices.

The forward-looking statements contained in this Annual Information Form (or a document incorporated herein by reference) are based on many assumptions including, but not limited to, the following material assumptions: impacts arising from COVID-19 not becoming significantly more onerous on the Corporation, which includes the Corporation
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being permitted to continue as an essential service; merchant power prices in Alberta and the Pacific Northwest; our proportionate ownership of TransAlta Renewables not changing materially; no material decline in the dividends expected to be received from TransAlta Renewables; the expected life extension of the coal fleet and anticipated financial results generated on conversion; assumptions regarding the ability of the converted units to successfully compete in the Alberta energy-only market; and assumptions regarding our current strategy and priorities, including as it pertains to our current priorities relating to our conversions to gas, growing TransAlta Renewables and being able to realize the full economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets.
Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this AIF (or a document incorporated herein by reference) include, but are not limited to, risks relating to the impact of COVID-19, which cannot currently be predicted, and which present risks including, but not limited to: more restrictive directives of government and public health authorities; reduced labour availability and ability to continue to staff our operations and facilities; disruptions to our supply chains, including our ability to secure necessary equipment and to obtain regulatory approvals on the expected timelines or at all; COVID-19-related force majeure claims; restricted access to capital and increased borrowing costs; a further decrease in short-term and/or long-term electricity demand and lower merchant pricing in Alberta and Mid-C; further reductions in production; increased costs resulting from our efforts to mitigate the impact of COVID-19; deterioration of worldwide credit and financial markets; a higher rate of losses on our accounts receivable due to credit defaults; impairments and/or writedowns of assets; and adverse impacts on our information technology systems and our internal control systems, including increased cyber security threats. The forward-looking statements are also subject to other risk factors that include, but are not limited to: fluctuations in demand, market prices and the availability of fuel supplies required to generate electricity; changes in demand for electricity and capacity and our ability to contract our generation for prices that will provide expected returns and replace contracts as they expire; the outcome of pending legal proceedings described in this AIF being adverse to TransAlta; the Brookfield investment being successfully challenged; the legislative, regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic or market conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather and other climate-change related risks; unexpected increases in cost structure and disruptions in the source of fuels, water or wind required to operate our facilities; failure to meet financial expectations; natural and man-made disasters resulting in dam failures; the threat of domestic terrorism and cyberattacks; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner; commodity risk management; industry risk and competition; the need to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign political risks; the need for and availability of additional financing; structural subordination of securities; counterparty credit risk; changes in credit and market conditions; changes to our relationship with, or ownership of, TransAlta Renewables Inc.; risks associated with development projects and acquisitions, including capital costs, permitting, labour and engineering risks; increased costs or delays in the construction or commissioning of pipelines, or sourcing sufficient quantities of natural gas, for the converted units; changes in expectations in the payment of future dividends, including from TransAlta Renewables Inc.; insurance coverage; credit ratings; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland facility; outcomes of investigations and disputes; reliance on key personnel; labour relations matters; and development projects and acquisitions. The foregoing risk factors, among others, are described in further detail under the heading "Risk Factors" in this Annual Information Form or in a document incorporated herein by reference, including our management's discussion and analysis for the year ended Dec. 31, 2020 (the "Annual MD&A").
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on them, which reflect the Corporation's expectations only as of the date hereof. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described or might not occur at all. We cannot assure that projected results or events will be achieved.
Documents Incorporated by Reference
TransAlta's audited consolidated financial statements for the year ended Dec. 31, 2020, and related annual management's discussion and analysis are hereby specifically incorporated by reference in this AIF. Copies of these documents are available on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
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Corporate Structure
Name and Incorporation
TransAlta Corporation is a corporation organized under the Canada Business Corporations Act (the "CBCA"). It was formed by Certificate of Amalgamation issued on Oct. 8, 1992. On Dec. 31, 1992, a Certificate of Amendment was issued in connection with a plan of arrangement involving TransAlta Corporation and TransAlta Utilities Corporation ("TransAlta Utilities" or "TAU") under the CBCA. The plan of arrangement, which was approved by shareholders on Nov. 26, 1992, resulted in common shareholders of TransAlta Utilities exchanging their common shares for shares of TransAlta Corporation on a one-for-one basis. Upon completion of the arrangement, TransAlta Utilities became a wholly owned subsidiary of TransAlta Corporation.
Effective Jan. 1, 2009, TransAlta completed a reorganization, whereby the assets and business affairs of TAU and TransAlta Energy Corporation ("TransAlta Energy" or "TEC") (with the exception of the wind business) were transferred to TransAlta Generation Partnership, a then new Alberta general partnership, whose partners are TransAlta Corporation and TransAlta Generation Ltd., a wholly-owned subsidiary of TransAlta Corporation. TransAlta Generation Partnership is managed by TransAlta Corporation pursuant to the terms of a partnership agreement and a management services agreement. Immediately following the transfer of assets by TAU and TEC to TransAlta Generation Partnership, TransAlta Corporation amalgamated with TAU, TEC and Keephills 3 GP Ltd. pursuant to the provisions of the CBCA.
TransAlta amended its articles on Dec. 7, 2010, to create the Series A Shares and Series B Shares; again on Nov. 23, 2011, to create the Series C Shares and Series D Shares; again on Aug. 3, 2012, to create the Series E Shares and Series F Shares; and again on Aug. 13, 2014, to create the Series G Shares and Series H Shares. TransAlta further amended its articles in on Oct. 1, 2020, to create the new series of redeemable, retractable first preferred shares that were issued to an affiliate of Brookfield Renewable Partners ("Brookfield") in October 2020. See "Capital and Loan Structure - Exchangeable Securities".
The registered and head office of TransAlta is located at 110 ‑ 12th Avenue S.W., Calgary, Alberta, Canada, T2R 0G7.
Our Subsidiaries
As at the date of this AIF, the principal subsidiaries of TransAlta Corporation and their respective jurisdictions of formation are set out below.
Certain of our subsidiaries are not wholly owned. The most significant subsidiary is TransAlta Renewables Inc. ("TransAlta Renewables"), which completed its initial public offering in August 2013. In connection with the offering, TransAlta Corporation transferred to TransAlta Renewables certain wind and hydro power generation assets previously held directly or indirectly by TransAlta Corporation. As at Dec. 31, 2020, TransAlta Corporation owned, directly or indirectly, approximately 60 per cent of the outstanding voting equity in TransAlta Renewables. See "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables."


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Notes:
(1) Unless otherwise stated, ownership is 100 per cent. As noted elsewhere in this AIF, TransAlta Renewables has economic interests in a number of projects through tracking preferred shares in the capital of TA Energy Inc. and TransAlta Power Ltd., which are both wholly owned by TransAlta Corporation.
(2) We own, directly or indirectly, an aggregate interest of approximately 60 per cent of TransAlta Renewables, which includes 37.38 per cent through direct ownership and 22.73 per cent through TransAlta Generation Partnership. The remaining approximately 40 per cent interest in TransAlta Renewables is publicly owned.


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Overview
TransAlta
We are one of Canada's largest publicly traded power generators with over 109 years of operating experience. We own, operate and manage highly contracted and geographically diversified portfolio of assets representing a broad range of fuels that include water, wind and solar, natural gas and thermal coal. We are currently undertaking a multi-year transition to convert or retire all of our thermal coal units completely by the end of 2025. This transition will see our thermal units in Alberta discontinue all firing with thermal coal and the discontinuation of all coal mining operations by the end of Dec. 31, 2021. Our Centralia coal-fired facility in Washington State is committed to be retired under the TransAlta Energy Transition Bill. Consistent with our commitment under this bill, Centralia Unit 1 retired on Dec. 31, 2020 and the remaining unit is set to retire on Dec. 31, 2025. Our energy marketing operations maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions.
Our vision is to be a leader in clean electricity and we are committed to a sustainable future. Our mission is to provide safe, low-cost and reliable clean electricity. With our 109-year history of powering economies and communities, we apply our expertise, scale and diversified fuel mix to capitalize on opportunities in our core markets and grow in areas where our competitive advantages can be employed.
Our values are grounded in safety, innovation, sustainability, respect and integrity, all of which enable us to work towards our common goals. These values are the principles that define our corporate culture. They reflect our skills and mindset, while providing a framework for everything we do, guiding both internal conduct and external relationships. These values are at the heart of our success.
•Safety – Ensure the health and safety of our people, partners and stakeholders
•Innovation – Develop and embrace innovative solutions to challenges
•Sustainability – Reduce the impact of resource use in everything we do
•Respect – Support our people, our partners, our communities and our environment
•Integrity – Focus on honesty, transparency and doing what's right
TransAlta and its predecessors have been engaged in the development, production and sale of electric energy since 1911. We are among Canada's largest non-regulated electricity generation and energy marketing companies with a total of 8,128 megawatts ("MW") of net maximum capacity. We are focused on generating and marketing electricity in Canada, the United States and Western Australia through our diversified portfolio of facilities fuelled by hydro, wind, solar, energy storage, natural gas and thermal coal.
TransAlta's diversified portfolio of power generating assets across multiple geographies, technologies and mix of merchant and contracted assets provides cash flows that support our ability to pay dividends to our shareholders, reinvest in growth and fund sustaining and capital expenditures.
Corporate Strategy
Our strategic focus is to invest in a disciplined manner in a range of clean and renewable power generation such as hydro, wind, solar, energy storage and thermal (natural- gas fired and cogeneration) and develop customer-centric green power solutions that produce electricity for the needs of our industrial customers and communities in order to deliver returns to our shareholders.
TransAlta's Clean Energy Investment Plan, announced in 2019, includes converting our existing Alberta coal assets to natural gas and advancing our leadership position in on-site generation and renewable electricity. The Clean Energy Investment Plan identified opportunities of $1.9 billion to $2.1 billion that TransAlta is pursuing. A significant number of these opportunities have been completed with the projects achieving commissioned status in 2019 and 2020.

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The following provides an overview of our Clean Energy Investment Plan:
1. Successfully convert to natural gas as the primary fuel source in the Alberta thermal fleet
We are transitioning our Alberta thermal fleet to natural gas as part of our Clean Energy Investment Plan. We plan to invest between $900 million to $1.0 billion to convert or repower our Alberta thermal fleet to natural gas. This will repurpose and reposition our fleet to a cleaner, gas-fired fleet while delivering attractive returns by leveraging the Corporation's existing infrastructure.
The highlights of these gas conversion investments include:
•Positioning TransAlta’s fleet as a low-cost clean energy generator in the Alberta energy-only market;
•Generating attractive returns by leveraging the Corporation’s existing infrastructure;
•Significantly extending the life and cash flows of our Alberta thermal assets; and
•Significantly reducing air emissions and costs.
2. Deliver growth in our renewables fleet
We expanded our renewables platform in the U.S. in 2020 and continue to identify additional opportunities with customers on electricity offerings with a higher component of power coming from renewable sources. Our focus is to deliver solid returns using exceptional project development, construction and integration of skills and capabilities.
3. Expand presence in the U.S. renewables market
A major focus of our business development efforts is on the renewables segment of the U.S. market. Demand for new renewables in the U.S. is expected to continue its strong growth in the near term and President Biden is expected to initiate policies designed to support further renewables growth. We have started prospecting for new renewable development sites in a number of attractive U.S. markets. These opportunities are expected to grow TransAlta Renewables, use its excess debt capacity and deliver stable dividends back to TransAlta.
4. Advance and expand our on-site generation and cogeneration business
We are focused on growing our on-site and cogeneration asset base, a business segment we have deep experience in, having provided on-site cogeneration services to customers since the early 1990s. Our current pipeline under evaluation is approximately 600 MW and our technical design, operations experience and safety culture make us a strong partner in this segment. We see this segment growing as industrial and large-scale customers are looking to find solutions to help lower the costs of power production, replace aging or inefficient equipment, reduce network costs and meet their environmental,social, and governance objectives.
5. Maintain a strong financial position
We intend to remain disciplined in our capital investment strategy and continue to build on our already strong financial position. The Clean Energy Investment Plan is being funded from the cash raised through the strategic investment by Brookfield, cash generated from operations and capital raised through TransAlta Renewables.
Our Economic, Environmental, Social and Governance Leadership (E2SG)
Sustainability means ensuring that our financial returns consider short- and long-term economics, environmental impacts and societal and community needs. We refer to this as E2SG. As we execute our strategy, our decisions are governed with a view to also deliver on our E2SG objectives. We have a long history of adopting leading-sustainability practices, including over 25 years of sustainability reporting and voluntarily integrating our sustainability report into our annual report. We have been issuing an integrated annual report since 2015. We test our practices and our reporting against standards set by CDP (formerly the Carbon Disclosure Project), the Task Force on Climate-related Financial Disclosures and the Canadian Council for Aboriginal Business.
Our key strategic sustainability pillars build on our corporate strategy and weave through our business. Some of these focus areas are already part of our DNA, and our track record in these areas illustrate our commitment to sustainability (including climate change leadership and safety). In other areas where we have set new goals in recent years (including, Diversity, Equity and Inclusion), we believe the focus will only strengthen our corporate strategy and support value creation into the future. Our pillars include:
1.Clean, Reliable and Sustainable Electricity Production
2.Safe, Healthy, Diverse, and Engaged Workplace
3.Positive Indigenous, Stakeholder and Customer Relationships
4.Progressive Environmental Stewardship
5.Technology and Innovation
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In 1990, we were the first Canadian company to purchase carbon offsets and in 2000 we were an early adopter of wind power generation. Through our ongoing transformational efforts, to date we have reduced our total greenhouse gas emissions by over 60 per cent, or over 25 million tonnes, since 2005. Our goal is to have no generation fuelled by coal by the end of 2025. The Corporation aligns its E2SG targets with the UN Sustainable Development Goals.
The key components of our Corporation's approved 2020 E2SG targets include:
•a continued focus on safe operations and environmentally sustainable practices, including undertaking significant reclamation work;
•by 2026, achieving a 95 per cent reduction in sulphur dioxide emissions and an 80 per cent reduction of nitrogen oxide ("NOx") emissions over 2005 levels from our coal facilities, and by 2030 a company-wide reduction in GHG emissions of 60 per cent below 2015 levels;
•undertaking initiatives that will enhance the environmental performance of the Corporation, including converting coal facilities to natural gas and developing new renewable projects that support customer E2SG goals to achieve both long-term power price affordability and carbon reductions;
•supporting equal access to all levels of education for youth and Indigenous peoples through financial assistance and employment opportunities;
•enhancing our commitment to workplace gender diversity, including adopting a target of 50 per cent representation of women on the Board by 2030 and at least 40 per cent representation of women among all of our employees by 2030; and
•maintaining our commitment to leading E2SG disclosures.
Our Capital Allocation and Financing Strategy
Our goal is to remain disciplined with our capital investment program and ensure that we continue to enhance our financial position. We are focused on strengthening our financial position and cash flow coverage ratios to ensure that a strong balance sheet is maintained and sufficient capital is available to execute our strategy.
Our goal is to return our deconsolidated debt levels to below a 3.0x debt-to-EBITDA ratio and to continue to pay and grow our dividend. We have adopted a debt-to-EBITDA target range of between 2.5x to 3.0x, based on TransAlta's deconsolidated comparable EBITDA.
We have also committed to a capital allocation program that provides investors with a line of sight on how we would consider changes into the future and provide further transparency on how the dividends that we receive from our ownership in TransAlta Renewables are either being returned to shareholders or reinvested at TransAlta. The Board has set a target of returning between 10 per cent and 15 per cent of TransAlta deconsolidated funds from operations to common shareholders.
We are confident that the above program balances the demands associated with meeting our goals around reinvestment, new growth and debt repayments along with providing shareholders a return on their capital.
Our Business Segments
The Hydro segment has a net ownership interest of approximately 926 MW of owned electrical-generating capacity. The facilities within this segment are predominantly located in Alberta, British Columbia, and Ontario.
The Wind and Solar segment has a net ownership interest of approximately 1,544 MW of owned electrical-generating capacity and includes facilities located in Alberta, Ontario, New Brunswick and Québec, and the states of Massachusetts, Minnesota, New Hampshire, Pennsylvania, Washington and Wyoming.
The North American Gas segment has a net ownership interest of approximately 866 MW of owned electrical-generating capacity and includes facilities located in Alberta, Ontario and Michigan.
The Australian Gas segment has a net ownership interest of approximately 450 MW of owned electrical-generating capacity and a pipeline located in Western Australia.
The Alberta Thermal segment has a net ownership interest of approximately 2,666 MW of owned electrical-generating capacity as well as our interest in the Pioneer Pipeline. Sundance Unit 6 underwent a simple boiler conversion in the fourth quarter of 2020 and the future conversions to gas and repowerings will remain in this segment.
The Centralia segment holds our Centralia thermal facility, which, as of Dec. 31, 2020, represented a net ownership interest of 1,340 MW of owned electrical-generating capacity. One of the units, which represents half of the facility's generating capacity, was retired on Dec. 31, 2020. From 2021 to 2025, the remaining unit has a capacity of 670 MW. The Centralia facility is located in the state of Washington.
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The Energy Marketing segment is responsible for marketing our production through short-term and long-term contracts, for securing cost-effective and reliable fuel supply, and for maximizing margins by optimizing our assets as market conditions change. Our Energy Marketing segment is actively engaged in the trading of power, natural gas and environmental products across a variety of markets.
The Corporate segment supports each of the above segments and includes the Corporation's central finance, legal, administrative, business development and investor relation functions.
We regularly review our operations in order to optimize our generating assets and evaluate appropriate growth opportunities to maximize value to the Corporation. We have in the past made, and may in the future make, changes and additions to our fleet of hydro, wind, solar, energy storage, natural gas and thermal coal.
TransAlta Renewables
TransAlta Corporation is the majority owner of TransAlta Renewables, with an approximate 60 per cent direct and indirect ownership interest as of the date of this Annual Information Form. TransAlta Renewables is one of the largest generators of wind power and among the largest publicly traded renewable power generation companies in Canada.
TransAlta Renewables was formed in 2013 to realize specific strategic and financial benefits, including: (a) establishing a focused vehicle for pursuing and funding growth opportunities in the renewable power and gas generation sector; (b) unlocking the value of TransAlta’s renewable asset platform; (c) retaining TransAlta’s majority ownership and operatorship of the underlying assets; (d) providing proceeds of approximately $200-$250 million to repay debt and support TransAlta’s balance sheet; and (e) creating additional financial flexibility for TransAlta by providing another source of capital with a separate cost of capital.
We continue to realize the benefit of having assets with different risk/return profiles in two separate entities as it enables each company to secure appropriate financing and investors. TransAlta holds mainly merchant assets in hydro and natural gas while TransAlta Renewables holds assets primarily with long-term contracts generating stable cash flows in wind, solar, natural gas and energy storage. TransAlta’s majority ownership of TransAlta Renewables has supported the Corporation in implementing its overall strategy of developing, constructing or acquiring additional renewable assets.
TransAlta Renewables, or one or more of its wholly-owned subsidiaries, directly own certain of our wind, hydro, natural gas and energy storage facilities. TransAlta Renewables also owns economic interests in a number of our other facilities. TransAlta Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets pursuant to the Management and Operational Services Agreement and the Governance and Cooperation Agreement between TransAlta Corporation and TransAlta Renewables. See "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables."
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TransAlta's Map of Operations
The following map outlines TransAlta's operations as of Dec. 31, 2020.
TRANSALTAFACILITIESMAP_TAC.JPG
Note:
(1) Includes facilities directly owned by TransAlta Renewables or its subsidiaries, as well as facilities in which TransAlta Renewables or one of its subsidiaries has an economic interest. We own, directly or indirectly, an aggregate interest of approximately 60 per cent of TransAlta Renewables.
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General Development of the Business
Significant regulatory changes continue to have extensive impacts on the Corporation's business and strategy. In 2015, the Government of Alberta announced the Alberta Climate Leadership Plan that set goals to reduce carbon emissions and phase out pollution from coal-generated electricity by 2030. TransAlta responded quickly to this announcement and set down the path to fully transform itself into a leading clean electricity company. Part of this strategy is to fully convert our existing coal fleet in Canada to natural gas. This will eliminate thermal coal as a fuel source on our operating units by the end of 2021 in Canada. In addition, we continue to expand our renewable generation and cogeneration fleet with numerous wind and gas projects currently under development. Throughout this transformation, we always keep our mission statement in mind: to provide safe, low-cost and reliable clean electricity.
The significant events and conditions affecting our business during the three most recently completed financial years, and during the current year to date, are summarized below. Certain of these events and conditions are discussed in greater detail under the heading "Business of TransAlta."
Three-Year History
Generation and Business Development
2021
TransAlta Completes First Off-Coal Conversion and Achieves Major Milestone in Phase-Out of Coal
On Feb. 1, 2021, the Corporation announced that it had completed the first of three planned boiler conversions to gas at the Sundance and Keephills power generation facilities near Wabamun, Alberta. The full conversion of Sundance Unit 6 from thermal coal to natural gas allows the unit to reduce its carbon dioxide emissions by half from approximately 1.05 tonnes carbon dioxide equivalent ("CO2e") per megawatt hour ("MWh") to approximately 0.52 tonnes of CO2e per MWh.
TransAlta's Alberta Power Purchase Arrangements Expire
On Dec. 31, 2020, the Alberta Power Purchase Arrangements for many of our Alberta hydro facilities and Keephills 1 and 2 units expired and, commencing Jan. 1, 2021, these facilities began operating on a merchant basis in the Alberta market. The facilities are now dispatched to benefit from the price volatility in the Alberta energy-only electricity market and to provide ancillary services. As such, they form part of our Alberta electricity portfolio optimization activities. The variability in production by facility is driven by the diversity in our fuel types which enables portfolio management. The Alberta portfolio of production includes hydro, wind, energy storage and thermal units. A portion of the base load of the portfolio is hedged to provide cash flow certainty.
2020
TransAlta Sells 303 MW Portfolio Including 274 MW of Wind to TransAlta Renewables
On Dec. 23, 2020, the Corporation and TransAlta Renewables entered into definitive agreements for the acquisition of three assets consisting of: (a) a 100 per cent direct interest in the 207 MW Windrise wind project located in the Municipal District of Willow Creek, Alberta; (b) a 49 per cent economic interest in the 137 MW Skookumchuck wind facility in operation located across Thurston and Lewis counties in Washington State; and (c) a 100 per cent economic interest in the 29 MW Ada facility in operation located in Ada, Michigan. The total acquisition price for the portfolio was $439 million and includes the remaining construction costs for the Windrise wind project. The transaction will close in separate tranches early in 2021 subject to the satisfaction of certain closing condition; however, the economic benefit of the transaction will be effective as at Jan. 1, 2020. The sale of the Windrise wind project to TransAlta Renewables closed on Feb. 26, 2021. TransAlta Renewables will fund the cash consideration and remaining construction costs with the proceeds from the South Hedland financing.
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TransAlta Acquired 30 per cent Equity Interest in EMG International LLC ("EMG")
On Nov. 30, 2020, the Corporation acquired a 30 per cent equity investment in EMG. The Corporation and EMG have joined forces to leverage their complementary customer bases to grow each business and further enhance product offerings to help customers reach their sustainability goals. EMG is an established company with over 25 years of experience in process wastewater treatment and specializes in the design and construction of high-rate anaerobic digester systems. TransAlta’s investment in EMG provides a low-risk entry point into the wastewater treatment industry and creates strong synergies with the Corporation's existing customer service offerings.
Skookumchuck Wind Project Equity Investment
On Nov. 25, 2020, the Corporation closed its 49 per cent equity investment in the Skookumchuck wind project ("Skookumchuck") with Southern Power Company, a subsidiary of Southern Company. Skookumchuck is a 137 MW wind project located in Lewis and Thurston counties, Washington consisting of 38 Vestas V136 wind turbines. Skookumchuck began commercial operation on Nov. 7, 2020 and has a 20-year power purchase agreement (PPA) with Puget Sound Energy. The economic interest in this facility is being sold to TransAlta Renewables in the first half of 2021.
TransAlta Fast- Tracks Off Coal and Highvale Mine to Discontinue Mining by End of 2021
On Nov. 4, 2020, the Corporation announced that it would discontinue all mining operations at its Highvale mine by Dec. 31, 2021. Effective Jan. 1, 2022, TransAlta will cease coal-fired generation in Canada. TransAlta’s Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal and will only operate on gas, resulting in the maximum capability of these units being reduced to 70 MW and 113 MW, respectively, effective Jan. 1, 2022. The Corporation continues to evaluate these units as candidates for boiler conversions or full repowering based on market fundamentals.
BHP Nickel West 15-Year Contract Extension
On Oct. 22, 2020, Southern Cross Energy ("SCE"), a subsidiary of the Corporation, replaced and extended its current PPA with BHP Billiton Nickel West Pty Ltd. ("BHP"). SCE is composed of four generation facilities with a combined capacity of 245 MW in the Goldfields region of Western Australia.
The new agreement was effective Dec. 1, 2020 and replaces the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038, and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross facilities for BHP's mining operations located in the Goldfields region of Western Australia. The extension will provide SCE a return on new capital investments, which will be required to support BHP's future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. Evaluation of renewable energy supply and carbon emissions reduction initiatives under the extended PPA with SCE are underway, including a 18.5 MW solar photovoltaic project supported by a battery energy storage system and a waste heat steam turbine system.
TransAlta Renewables Announced Commercial Operation of WindCharger, Alberta's First Utility-Scale Battery Storage Project
On Oct. 15, 2020, the WindCharger battery storage project began commercial operation. WindCharger is Alberta’s first utility-scale, lithium-ion energy storage project and it uses Tesla Megapack technology. TransAlta is expected to receive co-funding of almost 50 per cent of the $14 million construction cost from Emissions Reduction Alberta. The 10 MW / 20 MWh battery storage facility was acquired by TransAlta Renewables from the Corporation on Aug. 1, 2020. The Corporation also executed a 20-year battery storage usage contract with TransAlta Renewables in which the Corporation pays a fixed monthly capacity charge for the exclusive right to operate and dispatch the battery in the Alberta market. WindCharger is participating in both the Alberta wholesale energy and Ancillary Services market of the AESO.
TransAlta and Tidewater Midstream ("Tidewater") Enter into an Agreement to Sell the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. (“ATCO”)
On Oct. 1, 2020, TransAlta announced that it had entered into a definitive Purchase and Sale Agreement providing for the sale of its 50 per cent interest in the Pioneer Pipeline to ATCO. The aggregate purchase price of $255 million represents both TransAlta's and Tidewater's interests. This agreement replaces the previous Purchase and Sale Agreement to sell the Pioneer Pipeline to NOVA Gas Transmission Ltd. ("NGTL"). Following the closing of the transaction, the Pioneer Pipeline will be integrated into NGTL's and ATCO's Alberta integrated natural gas transmission systems to provide reliable natural gas supply to TransAlta's Sundance and Keephills power generating stations.
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Retirement of Sundance 3 Coal-Fired Thermal Facility
On July 22, 2020, the Corporation announced that it gave notice to the Alberta Electric System Operator ("AESO") to retire Sundance Unit 3 effective July 31, 2020. The retirement decision was largely driven by TransAlta’s assessment of future market conditions, the age and condition of the unit and our ability to supply energy and capacity from our generation portfolio in Alberta.
Acquisition of Contracted Cogeneration Asset in Michigan
On May 19, 2020, we closed the acquisition of a contracted cogeneration asset from two private companies for a purchase price of US$27 million. The asset is a 29 MW cogeneration facility ("Ada") in Michigan which is contracted under a long-term PPA and steam sale agreement for approximately six years with Consumers Energy and Amway. Ada has been included in the North American Gas segment results, which was previously known as the Canadian Gas segment. The economic interest in this facility is being sold to TransAlta Renewables in the first half of 2021.
2019
TransAlta Renewables Inc. Delivers on Two Contracted US Wind Projects
The Big Level wind facility and the Antrim wind facility began commercial operation on Dec. 19, 2019, and Dec. 24, 2019, respectively. TransAlta Renewables has an economic interest in these two US wind facilities. The 90 MW Big Level wind facility located in Pennsylvania is under a 15-year contract with Microsoft and the 29 MW Antrim wind facility located in New Hampshire is under two 20-year contracts with Partners Healthcare and New Hampshire Electric Co-op, respectively. All counterparties have a Standard & Poor’s credit rating of A+ or better.
During the third quarter of 2019, subsidiaries of TransAlta entered into final agreements with an external party for a planned tax equity investment in the Antrim and Big Level wind facilities. In December 2019, following Antrim and Big Level each achieving commercial operation, approximately $166 million (US$126 million) of tax equity proceeds were raised by the TransAlta project entities to partially fund the Antrim and Big Level wind facilities, for US$41 million and US$85 million, respectively.

TransAlta Renewables, through its economic interest ownership, provided construction funding with a combination of tracking preferred shares and interest-bearing notes issued by the project entity. The tax equity proceeds were used to repay TransAlta Renewables the principal and accrued interest outstanding on the interest-bearing promissory notes utilized to fund the construction.
Advancing our Clean Energy Investment Plan
In 2019, we announced our Clean Energy Investment Plan, which included plans to convert our existing Alberta coal assets to natural gas and advance our leadership position in on-site generation and renewable energy. TransAlta’s initial plan included converting three of its existing Alberta thermal units to gas in 2020 and 2021 by replacing existing coal burners with natural gas burners. The cost to convert is estimated to be approximately $35 million per unit.
On Oct. 30, 2019, we acquired two 230 MW Siemens F-class gas turbines and related equipment for $84 million from Kineticor Holdings Limited Partnership #2 ("Kineticor") and pertaining to their Three Creeks project. These turbines will be redeployed to our Sundance site as part of the strategy to repower Sundance Unit 5 to a highly efficient combined-cycle unit, with an expected commercial operation date in 2023. The Sundance Unit 5 repowered combined-cycle unit will have a capacity of approximately 730 MW and is expected to cost approximately $800 million to $825 million, well below a greenfield combined-cycle project. 
Kaybob Generation Project
In 2019, TransAlta and Energy Transfer Canada ("ET Canada", formerly known as SemCAMS Midstream ULC) entered into agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant (“K3”). The facility was expected to receive its final regulatory approvals in the second half of the year and begin construction in December 2020. On Sept. 25, 2020, the AUC released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. We are in ongoing commercial and technical discussions with ET Canada relative to the project at K3, or potentially developing a new project at another site owned and/or operated by ET Canada.
Agreement to Swap Non-Operating Interests in Keephills 3 and Genesee 3
On Aug. 2, 2019, we entered into definitive agreements with Capital Power Corporation (“Capital Power”) providing for the swap of our respective non-operating interests in the Keephills 3 facility and the Genesee 3 facility. On Oct. 1, 2019, we closed the transaction with Capital Power. As a result, we own 100 per cent of the Keephills 3 facility and Capital Power owns 100 per cent of the Genesee 3 facility.
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Strategic Investment by Brookfield Renewable Partners
On March 25, 2019, we announced a strategic investment by Brookfield that crystallizes the future value of our Hydro Assets, enhances our financial position to execute our strategy, accelerates the opportunity to return capital to shareholders, and provides TransAlta with a partner who has world-class expertise in renewable power platforms and hydroelectric generation . This investment ensures TransAlta will transition to 100 per cent clean electricity by the end of 2025.
Under the terms of an investment agreement (the "Investment Agreement"), Brookfield agreed to invest $750 million in TransAlta through the purchase of exchangeable securities (described below), which are exchangeable by Brookfield into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted EBITDA. In addition, subject to the exceptions in the Investment Agreement, Brookfield has committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to 9 per cent. On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for 7 per cent unsecured subordinated debentures due May 1, 2039. The further $400-million investment tranche closed on Oct. 30, 2020 in exchange for a new series of redeemable, retractable first preferred shares.
Benefits of the investment are highlighted below:
•includes a significant $750 million capital injection that is being used to advance our gas conversion transition strategy, advance the development of existing and new growth projects and for general corporate purposes;
•recognizes the future anticipated value of our Hydro Assets;
•creates a long-term cornerstone shareholder;
•strengthens our operating capabilities;
•accelerates the return of capital to shareholders through share buy backs; and
•adds extensive renewables experience and expertise by electing two experienced Brookfield directors to our Board of Directors.
Extended Mothballing of Sundance Unit 3 and Unit 5
On March 8, 2019, we announced that the AESO granted the extension of the mothballing for the Sundance Units described below:
•Sundance Unit 3 until Nov. 1, 2021, extended from the previous date of April 1, 2020; and
•Sundance Unit 5 will remain mothballed until Nov. 1, 2021, extended from the previous date of April 1, 2020.
The extensions were requested by us based on the Corporation's assessment of market prices and market conditions Subsequently, on July 31, 2020, we retired Sundance Unit 3.
2018
Pioneer Pipeline
On Dec. 17, 2018, we exercised our option to acquire 50 per cent ownership in the Pioneer Pipeline. During the second quarter of 2019, the Pioneer Pipeline transported its first gas four months ahead of schedule to our generating units at Sundance and Keephills. The sale of the Pioneer Pipeline by TransAlta and Tidewater to ATCO is expected to close in the second quarter of 2021.
Alberta Renewable Energy Program Project – Windrise
On Dec. 17, 2018, our 207 MW Windrise wind project was selected by the AESO as one of the three selected projects in the third round of its Renewable Electricity Program. TransAlta and the AESO executed a Renewable Electricity Support Agreement with a 20-year term. The Windrise project is situated on 11,000 acres of land located in the county of Willow Creek, Alberta.
TransAlta Renewables' New Brunswick Wind Power Expansion Complete
On Oct. 19, 2018, TransAlta Renewables announced that the 17.25 MW expansion of the wind facility at Kent Hills, in New Brunswick, reached commercial operation, bringing total generating capacity to 167 MW. Under the 17-year PPA, New Brunswick Power receives both energy to the province's electricity grid and renewable energy credits ("RECs"). The Kent Hills 3 expansion is located on approximately 20 acres of Crown land and consists of five Vestas V126 turbines. Natural Forces Technologies Inc., a wind-energy developer based in Atlantic Canada, co-developed and co-owns the wind facility with TransAlta Renewables.
Retirement of Sundance Unit 1 and Unit 2 and Mothball Schedule Update
Effective July 31, 2018, we retired Sundance Unit 2 due to its shorter useful life relative to other units, age, size, and the capital requirements needed to return the unit to service. In addition to the retirement of Sundance Unit 2 our mothball
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outage schedule had been updated to provide that Sundance Unit 5 will continue to be mothballed up to Nov. 1, 2021 (extended from the previous date of April 1, 2020).
Sale of Three Renewable Assets
On May 31, 2018, TransAlta Renewables acquired from us an economic interest in the 50 MW Lakeswind wind facility in Minnesota and 21 MW of solar projects located in Massachusetts. In addition, TransAlta Renewables acquired ownership of the 20 MW Kent Breeze wind facility located in Ontario. The total purchase price payable for the three assets, which had an average weighted contract life of 15 years, was $166 million, including the assumption by TransAlta Renewables of $62 million of tax equity obligations and project debt. TransAlta Renewables funded the equity portion of the acquisitions using its existing liquidity. On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million (US$25 million) of tracking preferred shares of a subsidiary of TransAlta, to fund the repayment of Mass Solar's project debt.
Acquisition of US Wind Projects
On Feb. 20, 2018, TransAlta Renewables entered into an arrangement to acquire economic interests in the Big Level and Antrim wind facilities. On Feb. 28, 2018, TransAlta Renewables acquired tracking preferred shares from the Corporation that provide TransAlta Renewables with an economic interest in the Big Level and Antrim wind facilities. The Big Level and Antrim wind facilities began commercial operation on Dec. 19, 2019, and Dec. 24, 2019, respectively. See "- 2020 - TransAlta Renewables Inc. Delivers on Two Contracted US Wind Projects."
Corporate and Energy Marketing
2021
Management and Board of Directors Changes
On Feb. 4, 2021, TransAlta announced that John Kousinioris will succeed Dawn Farrell as President and Chief Executive Officer and will join the Board of TransAlta on April 1, 2021. As part of the transition, Mr. Kousinioris stepped down as President and as a member of the Board of Directors of TransAlta Renewables. effective Feb. 5, 2021. Todd Stack assumed the role of President of TransAlta Renewables, and also joined the Board of TransAlta Renewables effective Feb. 6, 2021. Mr. Stack continues as TransAlta's Executive Vice President, Finance & Trading and Chief Financial Officer. During the first quarter of 2021, Brett Gellner, our Chief Development Officer, announced he will retire effective April 30, 2021. Mr. Gellner will remain on the TransAlta Renewables' Board of Directors.
2020
Declaration of a 6% Common Share Dividend Increase
On Dec. 23, 2020, the Corporation announced a 6 per cent increase on its common share dividend for the quarter ending March 31, 2021. The quarterly dividend of $0.045 per common share represents an annualized dividend of $0.18 per common share, an increase of $0.01 per common share.
TransAlta Receives an A- Industry Leader Score from CDP
On Dec. 14, 2020, the Corporation announced that CDP (the global disclosure system for environmental impacts formerly known as the Climate Disclosure Project) recognized TransAlta with an A- score, ranking the Corporation among industry leaders on climate change management.
Redemption of Medium-Term Notes
On Nov. 25, 2020, the Corporation redeemed all of its outstanding and due 5.0 per cent Senior Unsecured Medium-Term Notes, in the aggregate principal amount of $400-million. The redemption was funded with cash-on-hand.
Diversity and Inclusion Pledge
On Nov. 4, 2020, the Corporation announced that the Board has adopted a Diversity and Inclusion Pledge that commits the Corporation to advancing diversity and inclusion in the workplace. By committing to this pledge, the Corporation will seek to remove systemic barriers that may prevent diverse employees from thriving, including visible minorities, Indigenous people, members of the LGBTQ+ community, persons with disabilities, and women. The persistent inequities around the world underscore the urgent need to address and alleviate racial, ethnic, and other tensions, to remove barriers that perpetuate these inequalities and to promote an inclusive working environment for all employees. TransAlta firmly believes that true diversity is good for the economy, it improves corporate performance, drives growth, and enhances employee engagement. The Diversity and Inclusion Pledge acknowledges these challenges and seeks to: (a) encourage conversations about diversity and inclusion within the workplace; (b) expand education regarding
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diversity, equality and inclusion; (c) create best practices that result in the establishment of programs and initiatives relating to diversity and inclusion within the workplace; and (d) drive accountability by regularly reporting and evaluating the success of the Corporation’s programs and initiatives.
TEC Hedland Pty Ltd. ("TEC") Secures AU$800 Million Financing
On Oct. 22, 2020 TEC, a subsidiary of the Corporation, closed an AU$800-million senior secured note offering ("Offering"), by way of a private placement, which is secured by, among other things, a first-ranking charge over all assets of TEC. The Offering bears interest at 4.07 per cent per annum, payable quarterly and maturing on June 30, 2042 with principal payments starting on March 31, 2022. The Offering has a rating of BBB from Kroll Bond Rating Agency.
TransAlta Renewables received $480 million (AU$515 million) of the proceeds from the Offering through the redemption of certain intercompany structures. An additional AU$200 million has been loaned to TransAlta Renewables by TransAlta Energy (Australia) Pty Ltd., which is a subsidiary of TransAlta. The loan bears interest at 4.32 per cent and will be repaid by Oct. 23, 2022. The remaining proceeds from the Offering were set aside for required reserves and transaction costs.
TransAlta Renewables used a portion of the proceeds from the redemption and the intercompany loan to repay existing indebtedness on its credit facility and to acquire the Windrise wind project and expects to use the remaining proceeds to acquire the economic interests in the Skookumchuck wind facility and the Ada facility.
Normal Course Issuer Bid
On May 26, 2020, the Corporation announced that the TSX accepted the notice filed by the Corporation to implement a Normal Course Issuer Bid ("NCIB") for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its public float of common shares as at May 25, 2020. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.
TransAlta Declares Increased Common Dividend
On Jan. 16, 2020, we declared an increase in the annualized dividend to $0.17 per common share, representing a 6.25 per cent increase over the prior dividend level.
TransAlta Appoints John P. Dielwart as the Chair of the Board
On Jan. 16, 2020, we announced that John P. Dielwart will be appointed Chair of the Board effective immediately following the retirement of Ambassador Gordon D. Giffin at the 2020 annual meeting of shareholders. Mr. Dielwart became Chair effective April 21, 2020.
2019
Favourable Conclusion Regarding the Sundance B and C PPAs Termination Payment
On Aug. 26, 2019, we announced that we were successful in our arbitration with the Balancing Pool for the remaining payment related to the termination of the Sundance B and C PPA. As a result of the arbitration decision, we received the full amount we had been seeking to recover, being equal to $56 million, plus GST and interest from the Balancing Pool. This payment related to TransAlta’s historical investments in certain mining and corporate assets that the we believed should have been included in the net book value calculation of the PPAs that had been disputed by the Balancing Pool.
Appointment of Chief Financial Officer
On May 16, 2019, we appointed Todd Stack as our Chief Financial Officer. Mr. Stack previously served as Managing Director and Corporate Controller of the Corporation and was responsible for providing leadership and direction over TransAlta’s financial activities, corporate accounting and reporting, tax, and corporate planning.
2018
Redemption of Medium-Term Notes
On Aug. 2, 2018, we redeemed all of our then outstanding 6.40 per cent Medium-Term Notes, due Nov. 18, 2019, in the aggregate principal amount of $400 million. The redemption price for these notes was $1,061.736 per $1,000 principal amount of the notes (representing, in aggregate, $425 million) including a prepayment premium and accrued and unpaid interest on the Notes to the redemption date.
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$345 Million Bond Offering
On July 20, 2018, our indirect wholly-owned subsidiary, TransAlta OCP LP, issued approximately $345 million of bonds, sold by way of a private placement, which are secured by, among other things, a first-ranking charge over all but a nominal percentage of the equity interests in TransAlta OCP and its general partner, and a first-ranking charge over all of TransAlta OCP's accounts and certain other assets. The amortizing bonds bear interest from their date of issue at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030.
TransAlta Renewables Completes $150- Million Bought Deal Offering of Common Shares
On June 22, 2018, TransAlta Renewables issued, pursuant to an underwritten offering on a bought deal basis, 11,860,000 common shares in the capital of TransAlta Renewables at a price of $12.65 per share for gross proceeds to TransAlta Renewables of approximately $150 million. As a result of the offering, our interest in TransAlta Renewables was reduced from approximately 64 per cent to 61 per cent.
Redemption of Senior Notes
On March 15, 2018, we redeemed all of our then outstanding US$500 million 6.65 per cent senior notes maturing May 15, 2018. The redemption price for the notes was approximately $617 million, including a $5-million early redemption premium and accrued and unpaid interest on the notes to the redemption date.

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Business of TransAlta
Our Hydro, Wind and Solar North American Gas and Australian Gas, Alberta Thermal, and Centralia business segments are responsible for operating and maintaining our electrical generation facilities as well as the related mining operations in Canada and the US. Our Energy Marketing segment is responsible for marketing our production, securing cost-effective and reliable fuel supply and deploying our competitive knowledge of power, transmission, environmental products and gas markets to capitalize on short-term arbitrage opportunities across various geographic regions aided by market and price volatility without materially changing the risk profile of the Corporation. All the segments are supported by a Corporate segment.
As the Corporation transforms into a leading clean electricity company, it is expected that the proportion of revenue attributable to the Alberta Thermal and Centralia business units will decline relative to the other business units. In addition, the Corporation continues to transition to a leaner organization through continuous optimization with a reduced cost structure to support the new business model.
The following table identifies each revenue-generating business segment's contribution to revenues as at Dec. 31, 2020:
2020 Revenues(1)
2019 Revenues(1)
Alberta Thermal
29% 35%
Centralia 24% 24%
North American Gas
10% 9%
Australian Gas
8% 7%
Wind and Solar
16% 13%
Hydro
7% 7%
Energy Marketing
6% 5%
Note:
(1) Includes 100 per cent of the revenue of TransAlta Renewables or its subsidiaries, as well as facilities in which TransAlta Renewables or one of its subsidiaries has an economic interest. We own, directly or indirectly, an aggregate interest of approximately 60 per cent of TransAlta Renewables.
For further information on our segment earnings and assets, please refer to Note 5 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. See "Documents Incorporated by Reference" in this AIF.
The following sections of this AIF provide detailed information on facilities by geographic location and fuel type.
Hydro Business Segment
The Hydro business segment holds an interest in 926 net MWs. The facilities are located in British Columbia, Alberta, Ontario and Washington State.
As well as contracting for power, we enter into long-term and short-term contracts to sell the environmental attributes from the merchant hydro facilities. These activities help to ensure earnings stability from these assets. Generally, for facilities under long-term contract, the benefit of the environmental attributes generated flow through to the contract holder.
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The following table summarizes our hydroelectric facilities as at Dec. 31, 2020:
Facility Name Province/ State Ownership (%)
Net Capacity Ownership Interest (MW)(1)
Commercial Operation Date Revenue Source
Contract Expiry Date(2)
Alberta - Bow River System
Barrier(3)
AB 100 13 1947 Alberta PPA 2020
Bearspaw(3)
AB 100 17 1954 Alberta PPA 2020
Cascade(3)
AB 100 36 1942, 1957 Alberta PPA 2020
Ghost(3)
AB 100 54 1929, 1954 Alberta PPA 2020
Horseshoe(3)
AB 100 14 1911 Alberta PPA 2020
Interlakes(3)
AB 100 5 1955 Alberta PPA 2020
Kananaskis(3)
AB 100 19 1913, 1951 Alberta PPA 2020
Pocaterra AB 100 15 1955 Merchant ‑
Rundle(3)
AB 100 50 1951, 1960 Alberta PPA 2020
Spray(3)
AB 100 112 1951, 1960 Alberta PPA 2020
Three Sisters(3)
AB 100 3 1951 Alberta PPA 2020
Alberta - Oldman River System
Belly River (4) (5)
AB 100 3 1991 Merchant ‑
St. Mary (4) (5)
AB 100 2 1992 Merchant ‑
Taylor (4) (5)
AB 100 13 2000 Merchant ‑
Waterton (4) (5)
AB 100 3 1992 Merchant ‑
Alberta - North Saskatchewan River System
Bighorn(3)
AB 100 120 1972 Alberta PPA 2020
Brazeau(3)
AB 100 355 1965, 1967 Alberta PPA 2020
BC Hydro Facilities
Akolkolex (4) (5)
BC 100 10 1995 BC Hydro 2046
Pingston (4) (5)
BC 50 23 2003, 2004 BC Hydro 2023
Bone Creek (4) (5)
BC 100 19 2011 BC Hydro 2031
Upper Mamquam(4) (5)
BC 100 25 2005 BC Hydro 2025
Ontario Hydro Facilities
Appleton (4)
ON 100 1 1994 IESO 2030
Galetta (4) (7)
ON 100 2 1998 IESO 2030
Misema (4)
ON 100 3 2003 IESO 2027
Moose Rapids (4)
ON 100 1 1997 IESO 2030
Ragged Chute (4)
ON 100 7 1991 IESO 2029
US Hydro Facilities
Skookumchuck (6)
WA 100 1 1970 PSE 2025
Total Hydroelectric Net Capacity 926
Notes:
(1) MW are rounded to the nearest whole number. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2020, TransAlta owned, directly or indirectly, approximately 60 per cent of the common shares in TransAlta Renewables.
(2) Where no contract expiry date is indicated, the facility operates as merchant.
(3) These facilities form part of the "Hydro Assets" subject to the Brookfield Investment. See "General Development of the Business - Three-Year History - 2019 - Strategic Investment by Brookfield Renewable Partners." The Alberta Power Purchase Arrangement in respect of these assets expired on Dec. 31, 2020 and are now operated as merchant.
(4) Facility owned by TransAlta Renewables.
(5) These facilities are EcoLogo® certified. EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.
(6) This facility is used to provide a reliable water supply to Centralia Coal.
(7) Galetta was originally built in 1907, but was retrofitted in 1998.
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Bow River System
Barrier
Barrier is a hydroelectric facility with installed capacity of 13 MW located on the Kananaskis River in Seebe, Alberta. It has been operating since 1947. The facility operated under an Alberta power purchase arrangement ("Alberta PPA") that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates Emission Performance Credits ("EPCs") under the Alberta Technology Innovation and Emissions Reduction (" TIER") system.
Bearspaw
Bearspaw is a hydroelectric facility with installed capacity of 17 MW located on the Bow River in Calgary, Alberta. It has been operating since 1954. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Cascade
Cascade is a hydroelectric facility with installed capacity of 34 MW located on the Cascade River in Banff National Park, Alberta. We purchased this facility from the Government of Canada in 1941. The following year, we built a new dam and power plant to replace the original, and then, in 1957, added a second generating unit. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Ghost
Ghost is a hydroelectric facility with installed capacity of 54 MW located on the Bow River in Cochrane, Alberta. It has been operating since 1929. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Horseshoe
Horseshoe is a run-of-river hydroelectric facility with installed capacity of 14 MW located on the Bow River in Seebe, Alberta. It has been operating since 1911. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Interlakes
Interlakes is a hydroelectric facility with installed capacity of 5 MW located at Kananaskis Lakes, Alberta. It has been operating since 1955. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Kananaskis
Kananaskis is a run-of-river hydroelectric facility with installed capacity of 19 MW located on the Bow River in Seebe, Alberta. It has been operating since 1913. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Pocaterra
Pocaterra is a hydroelectric facility with installed capacity of 15 MW located at Kananaskis Lakes, Alberta. It has been operating since 1955. Generation from the facility is sold in the Alberta spot market and creates EPCs under the TIER system.
Rundle
Rundle is a hydroelectric facility with installed capacity of 50 MW located in Canmore, Alberta, on the Spray system. The facility uses water from the Spray Lakes storage reservoir. It has been operating since 1951.The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Spray
Spray is a hydroelectric facility with installed capacity of 112 MW located in Canmore, Alberta, on the Spray system. The plant uses water from the Spray Lakes storage reservoir. It has been operating since 1951. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
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Three Sisters
Three Sisters is a hydroelectric facility with installed capacity of 3 MW located at the base of the Three Sisters Dam in Canmore, Alberta, on the Spray system. The facility uses water from the Spray Lakes storage reservoir. It has been operating since 1951. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Waterton-St. Mary River System
Belly River
The Belly River facility is owned by TransAlta Renewables. Belly River is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Waterton-St. Mary Headworks Irrigation Canal System, east of the Waterton Reservoir, approximately 75 kilometres southwest of Lethbridge in Southern Alberta. Due to its location along the irrigation canal, Belly River operates from April to October when water is diverted through the canal as part of the St. Mary Irrigation District Water Management Plan. It has been operating since 1991. We acquire the generation from the facility pursuant to a PPA with TransAlta Renewables (a "Renewables PPA"), and subsequently sell such generation in the Alberta spot market.
St. Mary
The St. Mary facility is owned by TransAlta Renewables. St. Mary is a run-of-river hydroelectric facility with installed capacity of 2 MW located at the base of the dam impounding the St. Mary Reservoir, near Magrath, in southern Alberta. It has been operating since 1992. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Taylor
The Taylor facility is owned by TransAlta Renewables. Taylor is a run-of-river hydroelectric facility with installed capacity of 13 MW and is located adjacent to the Taylor Coulee Chute on the Waterton-St. Mary Headworks Irrigation Canal System, which is owned by the Government of Alberta. It has been operating since 2000. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Waterton
The Waterton facility is owned by TransAlta Renewables. Waterton is a run-of-river hydroelectric facility with installed capacity of 3 MW located at the base of the Waterton Dam on the Waterton Reservoir, near Hill Spring, southwest of Lethbridge, Alberta. It has been operating since 1992. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
North Saskatchewan River System
Bighorn
Bighorn is a hydroelectric facility with installed capacity of 120 MW located in Nordegg, Alberta. It has been operating since 1972. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
Brazeau
Brazeau is a hydroelectric facility with installed capacity of 355 MW located in Drayton Valley, Alberta. It has been operating since 1965. The facility operated under an Alberta PPA that expired Dec. 31, 2020. Generation from the facility is currently sold in the Alberta spot market and creates EPCs under the TIER system.
BC Hydro Facilities
Akolkolex
The Akolkolex facility is owned by TransAlta Renewables. Akolkolex is a run-of-river hydroelectric facility with installed capacity of 10 MW located on the Akolkolex River, south of Revelstoke, British Columbia. It has been operating since 1995. In 2016, TransAlta entered into a new 30-year agreement to sell the output from the facility to the British Columbia Hydro Power Authority ("BC Hydro").
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Bone Creek
The Bone Creek facility is owned by TransAlta Renewables. Bone Creek is a run-of-river hydroelectric facility with installed capacity of 19 MW located on Bone Creek, 90 kilometres south of the town of Valemount, British Columbia. It has been operating since 2011. The output from the facility is under contract with BC Hydro.
Pingston
Pingston is a run-of-river hydroelectric facility with installed capacity of 45 MW located on Pingston Creek, southwest of Revelstoke, British Columbia, and down river of the Akolkolex facility. It has been operating since 2003. TransAlta Renewables owns the facility equally with Brookfield Renewable Power Inc. The output from the facility is sold to BC Hydro under a 20-year agreement that is set to expire in 2023.
Upper Mamquam
The Upper Mamquam facility is owned by TransAlta Renewables. Upper Mamquam is a run-of-river hydroelectric facility with installed capacity of 25 MW located on the Mamquam River, east of Squamish, British Columbia, and north of Vancouver. It has been operating since 2005. The output from the facility is sold to BC Hydro under a PPA that terminates in 2025.
Ontario Hydro Facilities
Appleton
The Appleton facility is owned by TransAlta Renewables. Appleton is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Mississippi River, near Almonte, Ontario. The facility has been operating since 1994. Generation from this facility is sold to Ontario's Independent Electricity System Operator ("IESO") under a contract that terminates on Dec. 31, 2030.
Galetta
The Galetta facility is owned by TransAlta Renewables. Galetta is a run-of-river hydroelectric facility with installed capacity of 2 MW located on the Mississippi River, near Galetta, Ontario. This facility was originally built in 1907 and retrofitted in 1998. Generation from this facility is sold to the IESO under a contract that terminates on Dec. 31, 2030.
Misema
The Misema facility is owned by TransAlta Renewables. Misema is a run-of-river hydroelectric facility with installed capacity of 3 MW located on the Misema River, close to Englehart, in northern Ontario. This facility has been operating since 2003. Generation from this facility is sold to the IESO under a contract that terminates on May 3, 2027.
Moose Rapids
The Moose Rapids facility is owned by TransAlta Renewables. Moose Rapids is a run-of-river hydroelectric facility with installed capacity of 1 MW located on the Wanapitei River, near Sudbury, in northern Ontario. This facility has been operating since 1997. Generation from this facility is sold to the IESO under a contract that terminates on Dec. 31, 2030.
Ragged Chute
The Ragged Chute facility is owned by TransAlta Renewables. Ragged Chute is a run-of-river hydroelectric facility with installed capacity of 7 MW located on the Montréal River, south of Temiskaming Shores, in northern Ontario. We lease this facility from Ontario Power Generation Inc. and it has been operating since 1991. Generation from this facility is sold to the IESO under a contract that terminates on June 30, 2029.
US Hydro Facilities
Skookumchuck Hydro
We own a 1 MW hydroelectric generating facility on the Skookumchuck River near Centralia, Washington, and related assets that are used to provide water supply to our generation facilities in Centralia. On Dec. 7, 2020, we entered into an agreement with Puget Sound Energy for Skookumchuck to provide power until 2025.
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Wind and Solar Business Segment
As at Dec 31, 2020, the Wind and Solar segment held interests in approximately 1,544 MW of net wind generating capacity. This capacity consists of 10 wind facilities in Western Canada, 4 in Ontario, 2 in Québec, 3 in New Brunswick and 5 in the United States, more specifically in the states of Wyoming, Minnesota, Pennsylvania, Washington and New Hampshire. The Corporation also holds a 10 MW utility-scale battery storage in Alberta and an interest in a 21 MW solar facility in the state of Massachusetts.
Wind and solar are not generally a dispatchable fuel. Therefore, in merchant markets, wind and solar assets may not be able to secure the annual average pool price. As such, we make different assumptions in forecast revenue received for generation from a wind or solar asset compared to a base load asset. If these price assumptions and generation production forecasts are not correct, the corresponding revenue received may be reduced. Generation production forecasts are based on the long-term average production forecast for a site, reflecting historical climatic conditions. Within any year there may be variations from this long-term average. In order to forecast generation production, a number of factors have to be assumed based on historic on-site data. For a wind facility, this includes wind facility design including wake and array losses, wind shear and the electrical losses within the site. For a solar facility, long-term energy production depends on panel angle and row spacing, amount of sun, ambient conditions such as temperature and wind speed and losses at the site. If these assumptions are incorrect then actual production will be higher or lower than the long-term forecast for the site.
As well as contracting for the sale of the power generated, we also enter into long-term and short-term contracts to sell the environmental attributes from the merchant wind facilities, including offsets and RECs. These activities help to ensure earnings consistency from these assets. Generally, for facilities under long-term contract, the purchaser under such long-term contracts also has the benefit of any environmental attributes.
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The following table summarizes our Wind and Solar generation facilities as at Dec. 31, 2020:
Facility Name Province/ State Ownership (%)
Net Capacity Ownership Interest (MW)(1)
Commercial Operation Date Revenue Source
Contract Expiry Date(2)
Alberta Wind Facilities
Ardenville (4) (5)
AB 100 69 2010 Merchant ‑
Blue Trail and Macleod Flats (4) (5)
AB 100 69 2009 and 2004 Merchant ‑
Castle River (4) (5) (6)
AB 100 44 1997‑2001 Merchant -
Cowley North (4) (5)
AB 100 20 2001 Merchant ‑
McBride Lake (4) (5)
AB 50 38 2004 ENMAX 2024
Sinnott (4) (5)
AB 100 7 2001 Merchant ‑
Soderglen (4) (5)
AB 50 35 2006 Merchant ‑
Summerview 1 (4) (5)
AB 100 68 2004 Merchant ‑
Summerview 2 (4) (5)
AB 100 66 2010 Merchant ‑
Alberta Battery Energy Storage
WindCharger (4)
AB 100 10 2020 Merchant ‑
Eastern Canada Wind Facilities
Kent Breeze (4)
ON 100 20 2011 IESO 2031
Kent Hills 1(4)
NB 83 80 2008 NB Power 2035
Kent Hills 2 (4)
NB 83 45 2010 NB Power 2035
Kent Hills 3 (4)
NB 83 14 2018 NB Power 2035
Le Nordais (4) (5) (7)
QC 100 98 1999 Hydro-Québec 2033
Melancthon I (4)
ON 100 68 2006 IESO 2026
Melancthon II (4)
ON 100 132 2008 IESO 2028
New Richmond (4) (5)
QC 100 68 2013 Hydro-Québec 2033
Wolfe Island (4)
ON 100 198 2009 IESO 2029
US Wind and Solar Facilities
Antrim (3)
NH 100 29 2019 Partners HealthCare and New Hampshire Electric 2039
Big Level (3)
PA 100 90 2019 Microsoft 2034
Lakeswind (3)
MN 100 50 2014 LTC 2034
Mass Solar (3)(8)
MA 100 21 2012-2015 LTC 2032-2045
Skookumchuck Wind (3)
WA 49 67 2020 Puget Sound Energy 2040
Wyoming Wind (3)
WY 100 140 2003 LTC 2028
Total Wind and Solar Net Capacity (9)
1,544
Notes:
(1) MW are rounded to the nearest whole number. Column may not add due to rounding. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2019, TransAlta owned, directly and indirectly, approximately 60 per cent of the common shares in TransAlta Renewables.
(2) Where no contract expiry date is indicated, the facility operates as merchant.
(3) TransAlta Renewables owns an economic interest in the facility.
(4) Facility owned directly by TransAlta Renewables.
(5) These facilities are EcoLogo® certified. EcoLogo certification is granted to products with environmental performance that meet or exceed all government, industrial safety and performance standards.
(6) Includes seven additional turbines at other locations.
(7) Comprised of two facilities.
(8) Comprised of multiple facilities.
(9) Excludes Windrise, which is a wind project currently under construction.
All of the electricity generated and sold by our wind generating facilities within Alberta and Quebec, are from facilities that are EcoLogo certified. We are an EcoLogo-certified distributor of alternative source electricity through Environment Canada's Environmental Choice Program.
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Alberta Wind Facilities
Ardenville
The Ardenville facility is owned by TransAlta Renewables. Ardenville is a 69 MW wind facility located approximately eight kilometres south of Fort Macleod, Alberta adjacent to the Macleod Flats wind facility. We constructed the project, which began commercial operations on Nov. 10, 2010. In 2018, the Ardenville wind facility was granted an extension to create offset credits under the TIER Regulation until October 2023 and is entitled to receive ecoENERGY for Renewable Power payments until November 2020. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Blue Trail and Macleod Flats
The Blue Trail facility is owned by TransAlta Renewables. Blue Trail is a 66 MW wind facility located in southern Alberta, that began commercial operations in November 2009. The Blue Trail wind facility creates carbon offset credits under TIER until September 2022 and was entitled to receive ecoENERGY payments until November 2019. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
The Macleod Flats facility is owned by TransAlta Renewables. Macleod Flats consists of a single 3 MW turbine and is located near Fort Macleod. It was commissioned in 2004 and was purchased by us in 2009. This facility generates renewable credits. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Castle River
The Castle River facility is owned by TransAlta Renewables. Castle River is a 44 MW wind facility that consists of 66 Vestas wind turbines (three Vestas V44 600 kW wind turbines and 63 Vestas V47 660 kW wind turbines) on 50 metre towers, and is located southwest of Pincher Creek, Alberta. This facility also includes an additional six turbines, totaling 4 MW, that are located individually in the Cardston County and Hill Spring areas of south western Alberta. This facility began commercial operations in stages from November 1997 through to July 2001. This facility generates EPCs under the TIER system. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Cowley North
The Cowley North facility is owned by TransAlta Renewables. Cowley North is a 20 MW wind facility that consists of 15 1.3 MW Nordex N60 wind turbines on 65-metre towers, and is located near the towns of Cowley and Pincher Creek, in southern Alberta. This facility began commercial operations in the fall of 2001. The Cowley North wind facility creates EPCs under the TIER system. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
McBride Lake
The McBride Lake facility is owned by TransAlta Renewables. The 75 MW McBride Lake wind facility, which is equally owned by ENMAX Generation Portfolio Inc., consists of 114 Vestas V47 (660 kW) wind turbines on 50-metre towers, and is located south of Fort Macleod, Alberta. This facility began commercial operations in April 2004. Generation from this facility is sold under a 20-year PPA with ENMAX Energy Corp. that terminates in 2024. This facility generates EPCs under the TIER system.
Sinnott
The Sinnott facility is owned by TransAlta Renewables. Sinnott has a total installed capacity of 7 MW that consists of five, 1.3 MW Nordex N60 wind turbines on 65-metre towers, and is located directly east of the Cowley North wind facility and north of Pincher Creek, Alberta. This facility began commercial operations in the fall of 2001. The Sinnott wind facility creates EPCs under the TIER system. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market.
Soderglen
The Soderglen facility is owned by TransAlta Renewables. Soderglen is a 71 MW facilitythat consists of 47 1.5 MW GE SLE wind turbines on 65-metre towers, and is located southwest of Fort Macleod. This facility began commercial operations in September 2006. The Soderglen wind facility creates EPCs under the TIER system. TransAlta Renewables owns the facility equally with CNOOC Petroleum North America ULC. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell 50 per cent of such generation in the Alberta spot market (which excludes that portion of generation that is owned by CNOOC Petroleum North America ULC).
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Summerview 1
The Summerview 1 facility is owned by TransAlta Renewables. Summerview 1 is a 68 MW wind facility located approximately 15 kilometres northeast of Pincher Creek, Alberta. We constructed Summerview and it began commercial operations in 2004. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market. The Summerview 1 facility creates EPCs under the TIER system.
Summerview 2
The Summerview 2 facility is owned by TransAlta Renewables. Summerview 2 is a 66 MW wind facility that consists of 38, 1.8 MW Vestas V80 wind turbines on 67- metre towers, and is located approximately 15 kilometres northeast of Pincher Creek, Alberta. This facility began commercial operations in September 2004. We acquire the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market. The Summerview 2 wind facility expansion creates carbon offset credits under TIER until November 2022, at which time the facility will become an opt-in facility under TIER.
WindCharger
WindCharger is Alberta's first utility-scale battery storage facility. The facility has a nameplate capacity of 10 MW and a total storage capacity of 20 MWh. WindCharger is located in southern Alberta in the Municipal District of Pincher Creek next to the existing Summerview wind facility substation. The energy storage project achieved commercial operations on Oct. 15, 2020. WindCharger stores energy produced by the nearby Summerview 2 wind facility and discharges it into the Alberta electricity grid at times of high-peak demand. The project received co-funding support from Emissions Reduction Alberta. WindCharger was acquired by TransAlta Renewables on Aug. 1, 2020. The Corporation executed a 20-year battery storage usage contract with TransAlta Renewables, whereby the Corporation pays a fixed-monthly capacity charge for the exclusive right to operate and dispatch the battery in the Alberta power market.
Windrise
On Dec. 17, 2018, TransAlta's Windrise project was selected by the AESO as one of three selected projects in the third round of the Renewable Electricity Program. Windrise is a 207 MW wind project situated on 11,000 acres of land located in the county of Willow Creek. The Windrise wind project will consist of 43 Siemens Gamesa 4.8-145 turbines. The wind facility has an executed Renewable Electricity Support Agreement with AESO to provide wind electricity and associated environmental attributes to the province for a 20-year term. Construction of the Windrise wind project began in mid-April 2020 with enhanced COVID-19 safety measures and protocols in place to ensure the safety and well-being of the employees, contractors and the surrounding community. Commercial operation of the Windrise wind project is expected to be achieved in the second half of 2021. TransAlta Renewables acquired the Windrise project on Feb. 26, 2021, although the economic benefit is effective Jan. 1, 2021.
Eastern Canada Wind Facilities
Kent Breeze
Kent Breeze is a 20 MW wind facility located in Thamesville, Ontario and comprises eight 2.5 MW GE wind turbines on 85-metre towers. This facility began commercial operations in 2011. Generation from this facility is sold to the IESO. Kent Breeze is entitled to receive ecoENERGY payments until Dec. 31, 2021. On May 31, 2018, this facility was acquired by TransAlta Renewables. See "General Development of the Business – Three-Year History - Generation and Business Development."
Kent Hills 1
The Kent Hills 1 facility is owned by TransAlta Renewables. The 96 MW Kent Hills 1 wind facility, in which TransAlta Renewables has an 83 per cent interest, comprises 32 3.0 MW Vestas V90 wind turbines on 80-metre towers, and is located near Moncton, New Brunswick. This facility began commercial operations in December 2008. Natural Forces Technologies Inc., a wind developer based in Atlantic Canada, co-developed this project with TransAlta and exercised its option to purchase 17 per cent of the Kent Hills 1 facility in May 2009. Generation from this facility is sold under a 25-year PPA with New Brunswick Power that terminates in 2033. On June 1, 2017, we extended the term of the PPA by two years to 2035.
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Kent Hills 2
The Kent Hills 2 facility is owned by TransAlta Renewables. The 54 MW Kent Hills 2 wind facility expansion, in which the TransAlta Renewables has an 83 per cent interest, comprises 18 3.0 MW Vestas V90 wind turbines on 80-metre towers. Natural Forces Technologies Inc. owns the remaining 17 per cent interest. The facility began commercial operations in November 2010. Generation from this facility is sold under a 25-year PPA with New Brunswick Power that terminates in 2035. Kent Hills 2 received ecoENERGY payments until November 2020.
Kent Hills 3
TransAlta Renewables has an 83 per cent interest in the Kent Hills 3 facility. On June 1, 2017, we signed a PPA with New Brunswick Power for the further expansion of the Kent Hills wind facility. This expansion project, Kent Hills 3, reached commercial operations on Oct. 19, 2018 and added five 3.45 MW turbines to the Kent Hills fleet for an additional 17.25 MW at the site, bringing total generating capacity of the three Kent Hills facilities to 167 MW. The Kent Hills 3 PPA expires in 2035. See "General Development of the Business – Three-Year History - Generation and Business Development."
Le Nordais
The Le Nordais facility is owned by TransAlta Renewables. The 98 MW Le Nordais wind facility is located at two sites: Cap-Chat with 55.5 MW of installed capacity consisting of 74, 750 kW NEG-Micon wind turbines on 55-metre towers; and Matane with 42 MW of installed capacity consisting of 56, 750 kW NEG-Micon wind turbines on 55-metre towers. Le Nordais is located on the Gaspé Peninsula of Québec. It began commercial operations in 1999. Generation from this facility is sold to Hydro-Québec and generates RECs.
Melancthon I
The Melanchton I facility is owned by TransAlta Renewables. Melancthon I is a 68 MW wind facility consisting of 45, 1.5 MW GE wind turbines on 80 metre towers, and is located in Melancthon Township near Shelburne, Ontario. This facility began commercial operations in March 2006. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2026.
Melancthon II
The Melancthon II facility is owned by TransAlta Renewables. Melancthon II is a 132 MW wind facility consisting of 88, 1.5 MW GE wind turbines on 80 metre towers, and is located adjacent to Melancthon I, in Melancthon and Amaranth townships, Ontario. This facility began commercial operations in November 2008. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2028.
New Richmond
The New Richmond facility is owned by TransAlta Renewables. New Richmond is a 68 MW wind facility consisting of 27, 2.0 MW and six, 2.3 MW Enercon E82 wind turbines on 100 metre towers, and is located in New Richmond, Québec. This facility began commercial operations in March 2013. Generation from this facility is sold under a 20-year electricity supply agreement with Hydro-Québec Distribution that terminates in 2033.
Wolfe Island
The Wolfe Island facility is owned by TransAlta Renewables. Wolfe Island is a 198 MW wind facility consisting of 86, 2.3 MW Siemens SWT 93 wind turbines on 80 metre towers, and is located on Wolfe Island, near Kingston, Ontario. This facility began commercial operations in June 2009. Generation from this facility is sold to the IESO pursuant to a PPA that terminates in 2029.
US Wind and Solar Facilities
Antrim
The Antrim wind facility is 29 MW located in Antrim, New Hampshire. The wind facility was constructed by TransAlta Corporation and was commissioned in December 2019. The wind facility is fully operational and contracted under two long-term PPAs until 2039 with Partners Healthcare and New Hampshire Electric. On Feb. 28, 2018, TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "General Developments of the Business – Three-Year History - Generation and Business Development."
Big Level
The Big Level wind facility is 90 MW located in Potter County, Pennsylvania. The wind facility was constructed by TransAlta Corporation and commissioned in December 2019. The wind facility is fully operational and contracted under a long-term PPA until 2034 with Microsoft. On Feb. 28, 2018, TransAlta Renewables acquired tracking preferred shares
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from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "General Developments of the Business – Generation and Business Development."
Lakeswind
The Lakeswind wind facility is 50 MW located near Rollag, Minnesota. The wind facility was acquired in 2015 from an affiliate of Rockland Capital LLC. The wind facility is fully operational and contracted under a long-term PPA until 2034 with several high-quality counterparties. On May 31, 2018, TransAlta Renewables acquired tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "General Developments of the Business – Generation and Business Development."
Mass Solar
The Mass Solar facility is a 21 MW solar project consisting of multiple facilities located in Massachusetts. The solar facility was acquired in 2015 from an affiliate of Rockland Capital LLC. The operational solar facility is contracted under a long-term PPA with several high-quality counterparties. In addition to revenue generated under the PPA, the project generate solar RECs that expire in 2024. On May 31, 2018 TransAlta Renewables acquired tracking preferred shares from the Corporation that provide TransAlta Renewables with an economic interest in the solar facility. See "General Development of the Business – Three-Year History - Generation and Business Development" and "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables."
Skookumchuck Wind
The Skookumchuck facility is 137 MW located in Lewis and Thurston counties, Washington. It consists of 38 Vestas V136 wind Turbines. Skookumchuck began commercial operations on Nov. 7, 2020, and has a 20-year PPA with Puget Sound Energy Inc. On Dec. 1, 2020, the Corporation acquired a 49 per cent equity interest in the wind facility from its partner Southern Power Company, a subsidiary of Southern Company. TransAlta Renewables has agreed to acquire the economic interest in Skookumchuck wind facility, which is expected to close in the second quarter of 2021 and the economic benefit will be deemed effective Jan. 1, 2021.
Wyoming
The Wyoming wind facility is 140 MW located near Evanston, Wyoming. It was acquired in December 2013 from an affiliate of NextEra Energy Resources, LLC. The wind facility is contracted under a long-term PPA until 2028 with an investment grade counterparty. TransAlta Renewables holds tracking preferred shares from the Corporation that provides TransAlta Renewables with an economic interest in the wind facility. See "Non-Controlling Interests – TransAlta Renewables."
North American Gas Business Segment
The following table summarizes our Canadian natural gas-fired generation facilities as at Dec. 31, 2020:
Facility Name Province/ State Ownership (%)
Net Capacity Ownership Interest (MW)(1)
Commercial Operation Date Revenue Source
Contract Expiry Date(2)
Ada MI 100 29 1991 Consumers Energy/ Amway 2026
Fort Saskatchewan(5)
AB 30 35 1999 Dow Chemical/Merchant 2029
Poplar Creek(4)
AB 100 230 2001 Suncor 2030
Ottawa(5)
ON 50 37 1992 LTC/Merchant 2022-2033
Sarnia(3)
ON 100 499 2003 LTCs 2022-2025
Windsor(5)
ON 50 36 1996 IESO/Merchant 2031
Total North American Gas Net Capacity 866
Notes:
(1) MW are rounded to the nearest whole number. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2020, TransAlta owns, directly or indirectly, approximately 60 per cent of the common shares in TransAlta Renewables.
(2) Where no contract expiry date is indicated, the facility operates as merchant.
(3) Facility is owned by TransAlta Renewables.
(4) The Poplar Creek facility is operated by Suncor Energy Inc. and ownership of the facility will transfer to Suncor in 2030.
(5) Our interests in these facilities are through our ownership interest in TransAlta Cogeneration LP ("TA Cogen").
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Ada
Ada is a 29 MW contracted cogeneration facility located in Ada, Michigan. The facility is contracted under a long-term PPA and steam sale agreement. The facility has been in operation since 1991, and consists of a single GE LM2500 gas turbine and an ABB steam turbine and produces approximately 18,000 tonnes of steam hourly. The electricity and steam output of the facility are fully contracted until 2026 with Consumers Energy and Amway. TransAlta completed the acquisition to own and operate the facility on May 19, 2020. On Dec. 23, 2020, TransAlta Renewables agreed to acquire the economic interest in the facility, which is expected to close in the first half of 2021 and the economic benefit will be deemed effective Jan. 1, 2021.
Fort Saskatchewan
We have a net ownership interest of 30 per cent in the Fort Saskatchewan facility. See "Business of TransAlta – Non-Controlling Interests." The 118 MW natural gas-fired combined-cycle cogeneration Fort Saskatchewan facility is owned by TA Cogen and Prairie Boys Capital Corporation. During the fourth quarter of 2017, we entered into a long-term contract for the Fort Saskatchewan facility providing for the delivery of energy and steam to the customer. The contract has an initial 10-year term, which began on Jan. 1, 2020, with the option for two five-year extensions. The contract allows our customer to continue to benefit from the operational flexibility of the facility.
Poplar Creek
Our Poplar Creek facility is located in Fort McMurray, Alberta. On Aug. 31, 2015, the Corporation restructured its contractual arrangement for the facility's power generation services. The Poplar Creek cogeneration facility had been built and contracted to provide steam and electricity to Suncor's oil sands operations. Under the terms of the new arrangement, Suncor acquired from the Corporation two steam turbines with an installed capacity of 126 MW and certain transmission interconnection assets. In addition, Suncor assumed full operational control of the cogeneration facility and has the right to use the full 230 MW capacity of the Corporation's gas generators until Dec. 31, 2030. Ownership of the entire Poplar Creek cogeneration facility will transfer to Suncor in 2030.
Ottawa
The Ottawa facility is owned by TA Cogen. See "Business of TransAlta – Non-Controlling Interests." It is a combined-cycle cogeneration facility designed to produce 74 MW of electrical energy. On Aug. 30, 2013, the Corporation announced the recontracting of the facility with the IESO for a 20-year term, effective January 2014. The Ottawa facility also provides steam, hot water, and chilled water to the member hospitals and treatment centres of the Ottawa Health Sciences Centre and the National Defence Medical Centre. The thermal energy contract with the Ottawa Health Sciences Centre expires Jan. 1, 2024.
Sarnia
The Sarnia facility is a 499 MW combined-cycle cogeneration facility located in Sarnia, Ontario, that provides power and steam to nearby industrial facilities owned by ARLANXEO Canada Inc. (formerly LANXESS AG, successor to Bayer Inc.), Nova Chemicals Corporation (Canada) Ltd. ("NOVA") (which in turn supplies INEOS Styrolution, a styrene production facility formerly owned by NOVA) and Suncor Energy Products Partnership under contracts terminating in 2022. We are currently evaluating potential extensions to these power and steam off-take agreements. The facility also provides electricity to the IESO under a contract that terminates Dec. 31, 2025.
The Sarnia facility uses three Alstom 11N2 gas turbines, each capable of generating between 102 MW and 118 MW, one condensing steam turbine that can produce 120 MW, and back-pressure steam turbines capable of generating 56 MW. The facility also incorporates a fired boiler, river water pump houses, and water treatment plants. In 2018, Sarnia's capacity was reduced from 506 MW to 499 MW due to the lay-up of one generator. The reduction in capacity has not impacted the facility's ability to meet its contractual requirements.
Windsor
The Windsor facility is owned by TA Cogen. See "Business of TransAlta – Non-Controlling Interests." It is a combined-cycle cogeneration facility designed to produce 72 MW of electrical energy, of which, 50 MW was sold under a long-term contract to the Ontario Electricity Financial Corporation that expired Nov. 30, 2016. Effective Dec. 1, 2016, the Windsor facility began operating under an agreement with the IESO with a 15-year term for up to 72 MW of capacity. The Windsor facility also provides thermal energy to Stellantis Canada's minivan assembly facility in Windsor under a contract that expires in Nov. 2022, with six successive renewal terms of one year each. 
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Kaybob Cogeneration
In 2019, TransAlta and ET Canada entered into agreements to develop, construct and operate a 40 MW cogeneration facility at K3. The facility was expected to receive its final regulatory approvals in the second half of the year and begin construction in December 2020. On Sep. 25, 2020, the AUC released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. We are in ongoing commercial and technical discussions with ET Canada relative to the project at K3, or potentially developing a new project at another site owned and/or operated by ET Canada.

Australian Gas Business Segment
The following table summarizes our Australian assets as at Dec. 31, 2020:
Facility Name Province/ State Ownership (%)
Net Capacity Ownership Interest (MW)(1)
Commercial Operation Date Revenue Source Contract Expiry Date
Parkeston(2)(3)
WA(4)
50 55 1996 Newmont Power Pty Ltd. 2026
South Hedland(2)
WA(4)
100 150
2017(5)
LTCs(5)
2042
Southern Cross Energy(2)(6)
WA(4)
100 245 1996 BHP Billiton Nickel West Pty Ltd 2038
Fortescue River Gas Pipeline
WA(4)
43 N/A 2015 Fortescue Metals Group 2035
Total Australian Gas Net Capacity 450
Notes:
(1) MW are rounded to the nearest whole number. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2020, TransAlta owned approximately 60 per cent of the common shares in TransAlta Renewables.
(2) TransAlta Renewables owns an economic interest in the facility.
(3) Plant contracted to October 2026 with early termination options beginning in 2021.
(4) Western Australia.
(5) Fortescue Metals Group ("FMG") is contracted for 23 per cent of the capacity, with Horizon Power contracting for the remaining 77 per cent of capacity. FMG is disputing the Corporation's declaration of commercial operation. See "Legal Proceedings and Regulatory Actions."
(6) Comprised of four facilities.
All of our Australian assets are owned, directly or indirectly, by TransAlta Energy (Australia) Pty Ltd. ("TEA"), a wholly-owned subsidiary of TransAlta. On May 7, 2015, TransAlta Renewables acquired tracking preferred shares that entitle TransAlta Renewables to an economic interest based on the cash flows broadly equal to the underlying net distributable cash flow of TEA, in consideration for a payment equal to $1.78 billion, which amount included funding the remaining construction costs for South Hedland.
Pursuant to the terms of the tracking preferred shares, TransAlta Renewables is entitled to receive, in priority to the common shares in the capital of TEA, quarterly preferential cash dividends. The preferred shares have no residual right to participate in the earnings of TEA. In the event of the liquidation, dissolution or winding-up of TEA or any other distribution of the assets of TEA among its shareholders for the purpose of winding up its affairs, TransAlta Renewables is entitled, subject to applicable law, to receive from TEA as the sole holder of preferred shares, before any distribution of TEA to the holders of the common shares or any other shares ranking junior to the preferred shares, an amount equal to the fair market value of the Australian assets.
Parkeston
The Parkeston facility is a 110 MW dual-fuel natural gas and diesel-fired power station, which we own in partnership through a 50/50 joint venture with NP Kalgoorlie Pty Ltd., a subsidiary of Newmont Australia Limited. The Parkeston facility primarily supplies energy to Kalgoorlie Consolidated Gold Mines and the initial supply contract ended in 2016. The facility was recontracted effective Nov. 1, 2016, and the agreement extends the previous contract to October 2026, with options for early termination available to either party beginning in 2021. We are evaluating potential opportunities to renew or extend the supply contract. Any merchant capacity and energy are sold into Western Australia's wholesale electricity market. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Parkeston facility on May 7, 2015.
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Southern Cross
Southern Cross Energy is consists of four naturalgas and diesel-fired generation facilities with a combined capacity of 245 MW. Southern Cross Energy sells its output under a contract with BHP Billiton Nickel West, which was renewed in October 2013 for 10 years. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the Southern Cross Energy facilities on May 7, 2015.
On Oct. 22, 2020, Southern Cross Energy replaced and extended its current PPA with BHP Nickel West. The new agreement became effective Dec. 1, 2020 and replaced the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038 and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross facilities for BHP Nickel West's mining operations located in the Goldfields region of Western Australia. The extension provides SCE a return of and on new capital investments, which will be required to support BHP's future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. Evaluation of renewable energy supply and carbon emissions reduction initiative under the extended PPA with SCE are underway, including an 18.5 MW solar photovoltaic facility supported by a battery energy storage system and a waste heat steam turbine system.
South Hedland
The South Hedland Power Station is a 150 MW combined-cycle power station located near South Hedland, Western Australia. Construction began in early 2015 and the plant achieved commercial operation on July 28, 2017. The facility was fully contracted with two customers for a 25-year term. Most of the facility's capacity remains contracted to Horizon Power, the state-owned electricity supplier in the region. The second customer is the port operations of FMG for 35 MW of capacity. In November 2017, we received a notice from FMG purporting to terminate their PPA. We have disputed this notice and are currently in litigation with FMG in respect of this dispute. This matter was adjourned due to the COVID-19 pandemic and is rescheduled to proceed to trial for five weeks starting May 3, 2021. See "Legal Proceedings and Regulatory Actions" for further details. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the South Hedland facility on May 7, 2015.
Fortescue River Gas Pipeline
In 2014, we established the Fortescue River Gas Pipeline joint venture with DBP Development Group. The joint venture (of which TransAlta is a 43 per cent partner) was successfully awarded the contract to design, build, own and operate the 270- kilometre Fortescue River Gas Pipeline to deliver natural gas to the Solomon facility. The pipeline was completed in the first quarter of 2015 and operates under a take-or-pay gas transport agreement with a subsidiary of FMG for an initial term of 20 years. The 16-inch diameter pipeline has an initial free-flow capacity of 64 terajoules (TJ) per day. Under the gas tariff agreement, FMG has the option to purchase the Fortescue River Gas Pipeline commencing March 2020. FMG maintains its option and the joint venture continues to deliver natural gas transportation to the Solomon facility. TransAlta Renewables acquired an economic interest based, in part, on the cash flows of the pipeline on May 7, 2015.
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Alberta Thermal Business Segment
The following table summarizes our Alberta Thermal generation facilities as at Dec. 31, 2020:
Facility Name Province Ownership (%)
Net Capacity Ownership Interest (MW)(1)
Commercial Operation Date Revenue Source
Contract Expiry Date
Keephills Unit No. 1 (2)(3)
AB 100 395 1983 Alberta PPA/Merchant 2020
Keephills Unit No. 2 (2)
AB 100 395 1984 Alberta PPA/Merchant 2020
Keephills Unit No. 3 AB 100 463 2011 Merchant -
Sheerness Unit No. 1 (2)
AB 25 100 1986 Alberta PPA/Merchant 2020
Sheerness Unit No. 2 (2)
AB 25 100 1990 Alberta PPA 2020
Sundance Unit No. 4 (4)
AB 100 406 1977 Merchant -
Sundance Unit No. 5 (5)
AB 100 406 1978 Merchant -
Sundance Unit No. 6
AB 100 401 1980 Merchant -
Pioneer Pipeline (5)
AB 50 N/A 2019 LTC 2034
Total AB Thermal Net Capacity 2,666
Notes:
(1) MW are rounded to the nearest whole number. Column may not add due to rounding.
(2 )The Alberta Power Purchase Arrangement in respect of these assets expired on Dec. 31, 2020 and are now operated as merchant.
(3) The Corporation will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022 and, as a result, the maximum capability of this unit will be reduced to 70 MW.
(4) The Corporation will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022 and, as a result, the maximum capability of this unit will be reduced to 113 MW.
(5) Unit mothballed to Nov. 1, 2021.
(6) TransAlta. and its partner, Tidewater, entered into a definitive Purchase and Sale Agreement providing for the sale of the Pioneer Pipeline to ATCO, which is expected to close in the first half of 2021.
The Keephills and the Sundance facilities are located approximately 70 kilometres west of Edmonton, Alberta, and are wholly-owned by TransAlta.
On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Alberta PPAs for Sundance Unit B (3 & 4) and Unit C (5 & 6) effective March 31, 2018. As a result, Sundance 4 and 6 have since been operating on a merchant basis within the Alberta market. Upon the expiry of the Alberta PPAs on Dec. 31, 2020, Keephills 1 and 2 units are now merchant and dispatched to take advantage of price volatility in the Alberta energy-only electricity market and to provide ancillary services and, as such, are part of our Alberta electricity portfolio optimization activities.
As part of our Clean Energy Investment Plan, the Corporation is converting coal-fired units into gas-fired units through either a simple boiler conversion, or a more involved project to build a repowered combined-cycle unit using existing and new assets. Our current plan involves three boiler conversions for Sundance 6, Keephills 2 and Keephills 3 to be completed by 2021, and completion of a repowered combined-cycle unit for Sundance 5 by end of 2023. We will continue to actively deplete our coal stock and will wind down our mining activity in Alberta by the end of 2021. As a result, the Corporation announced that Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022. The maximum capability of these units will be reduced to 70 MW and 113 MW, respectively.
During 2020, the Sundance 5 and Keephills 1 repowering projects received approvals from both the AUC and Alberta Environment and Parks to repower these respective units into combined-cycle units. The regulatory permits allow the steam turbines of these units to be repowered by installing combustion turbines and heat recovery steam generators thereby creating highly efficient combined-cycle units. Capital costs of repowered units are estimated to be 60 to 70 per cent of the capital investment as compared to a new combined-cycle facility while achieving a similar heat rate.
The Alberta Thermal fleet is currently subject to the federal-"Reduction of Carbon Dioxide Emissions from Coal-fired Generation of Electricity Regulations" and subsequent amendments as long as the units are coal-fired. Once converted to natural-gas-fired, the units become subject to the "Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity." Performance tests will be performed initially and annually to determine the gross
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emissions intensity of a converted unit. The results of the initial performance test will determine the life extension years for a converted unit post conversion.
Sundance 6
Sundance 6 was a coal-fired unit that recently completed its conversion to gas, with its commercial operation as a converted gas-fired unit having been achieved in early 2021. Under the federal gas-fired regulations, we expect this unit's intensity factor to be at or below 550 tonnes of CO2 emissions per GWh, thereby adding an additional eight years of life.
Keephills 2
Keephills Unit 2 is a coal-fired unit that will begin its conversion to gas in the spring of 2021 and will reach commercial operations by the first half of 2021. Under the federal gas-fired regulations, we expect this unit's intensity factor to be at or below 550 tonnes of CO2 emissions per GWh, thereby adding an additional eight years of life.
Keephills 3
Keephills Unit 3 will begin its conversion to gas in the fall of 2021 and will reach commercial operations by the second half of 2021. Under the federal gas-fired regulation, we expect this unit's intensity factor to be at or below 480 tonnes CO2 emissions per GWh, thereby adding an additional 10 years of life. Useful life for this unit is estimated to be through to 2039.
Sundance 5
The Sundance Unit 5 repowering project is on-track to start construction in March 2021. The project will be utilizing the Three Creeks assets acquired by Kineticor in 2019 to construct a highly-efficient combined-cycle unit. Sundance Unit 5's existing steam turbine will be paired with the two existing Siemens F class gas turbines from the Three Creeks acquisition and two new heat recovery steam generators. This combination of technology will increase the unit's current generation capability of 406 MW to 729 MW into the Alberta grid. All power generated will be from natural gas reducing the unit's emission intensity by over 55 per cent. Also, with the addition of a selective catalytic reducer the expected NOx emissions will be 7ppmvd, well below the provincial standard of 15ppmvd. The advantage of the project is that it uses existing infrastructure (including water, transmission, gas, buildings, control room, warehouses) thereby reducing the impact to the environment while keeping capital costs low. The repowered Sundance Unit 5 is expected to reach commercial operation in the fourth quarter of 2023.
Under the federal gas-fired regulation, we expect this unit's intensity factor to be well below 420 tonnes of CO2 emissions per GWh, thereby adding an additional 25 years of life. Useful life for this unit is estimated to be through to 2048.
Keephills 1 and Sundance 4
As the Corporation will discontinue all mining operations at Highvale mine by the end of 2021, effective Jan. 1, 2022, Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal. These units will only operate on gas, resulting in the maximum capability of these units being reduced to 70 MW and 113 MW respectively. The Corporation continues to evaluate these units as candidates for boiler conversion or full repowering based on market fundamentals.
Sheerness 1 and 2
The Sheerness facilities are located approximately 200 kilometres northeast of Calgary, Alberta, and are jointly-owned by TA Cogen and Heartland Generation Ltd. ("Heartland"). Heartland is responsible for the operation and maintenance of these units. During the first quarter of 2020, Sheerness Unit 2 was converted by Heartland to natural gas, and may be operated as a dual-fuel (coal or gas) unit. Also during 2020, Sheerness Unit 2's capacity was increased from 390 MW to 400 MW following a generator rewind and final testing. In the first quarter of 2021, Sheerness Unit 1 is scheduled to be converted by Heartland to natural gas, and may be operated as a dual-fuel (coal or gas) unit. Coal for the Sheerness facilities is provided from the adjacent Sheerness mine. The Sheerness facility will receive it's last coal shipment in the first quarter of 2021, with coal stock being actively depleted until the end of 2021.

The generation from Sheerness was sold under an Alberta PPA that expired Dec. 31, 2020. Commencing Jan. 1, 2021, each owner separately offers their share of generation into the Alberta energy market starting. See "Business of TransAlta – Non-Controlling Interests."

Mothball of Sundance Units
On April 1, 2018, we mothballed Sundance Unit 3 and Sundance Unit 5. In early 2019, the AESO granted an extension to the continued mothballing of Sundance Units 3 and 5. Sundance Unit 3 was subsequently retired from service on July 31, 2020. The Sundance Unit 5 will remain mothballed up to Nov. 1, 2021 (extended from April 1, 2020). The extension was
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requested by TransAlta based on our assessment of market prices and market conditions. TransAlta has the ability to return Sundance Unit 5 back to full operation by providing three months' notice to the AESO.
The decision to mothball selected units ensures that the remaining units operate at high-capacity utilization factors and competitive cost structures. See "General Development of the Business - Three-Year History - Generation and Business Development."
Sundance 1, 2 and 3
On Jan. 1, 2018, we retired Sundance Unit 1 and mothballed Sundance Unit 2. On July 31, 2018, we permanently retired Sundance Unit 2 due to its shorter useful life relative to other units, age, size and the capital requirements needed to return the unit to service. The retirement is consistent with our strategy to transition to clean electricity .
On July 31, 2020, the Corporation retired the Sundance Unit 3. The retirement decision was driven by TransAlta’s assessment of future market conditions, the age and condition of the unit and our ability to supply energy and capacity from our generation portfolio in Alberta.
Keephills 3 and Genesee 3 Swap
On Oct. 1, 2019 TransAlta and Capital Power completed an agreement to swap interests in the Keephills 3 facility and the Genesee 3 facility. As a result, TransAlta now owns 100 per cent of the Keephills 3 facility and Capital Power now owns 100 per cent of the Genesee 3 facility. On closing of the transaction, all of the Keephills 3 and Genesee 3 project agreements with Capital Power were terminated.
Highvale Mine
Fuel requirements for the Alberta thermal coal generation facilities that we operate and have yet to convert to gas generation are currently supplied by a surface strip coal mine located in close proximity to the facilities. We own the Highvale mine that supplies coal to the Sundance and Keephills facilities and perform the mining, reclamation and associated work at the Highvale mine. Furthering the Clean Energy Investment Plan, the Corporation has announced that it will discontinue all mining operations at Highvale mine by the end of 2021. The mine will enter its reclamation phase thereafter.
We also own the Whitewood mine, which formerly supplied coal to the now decommissioned Wabamun facility. The Whitewood mine is no longer in operation and we have completed reclamation of the site.
Off-Coal Agreement
On Nov. 24, 2016, we entered into the Off-Coal Agreement with the Government of Alberta pertaining to our cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired facilities. The Off-Coal Agreement provides that we are entitled to receive annual cash payments of approximately $37.4 million, net to TransAlta, from the Government of Alberta commencing in 2017, and terminating in 2030, subject to satisfaction of certain terms and conditions including our cessation of all coal-fired emissions on or before Dec. 31, 2030. Other conditions include maintaining prescribed spending on investment and investment-related activities in Alberta, maintaining a significant business presence in Alberta (including through the maintenance of prescribed employment levels), maintaining spending on programs and initiatives to support the communities surrounding the facilities and the employees of the Corporation negatively impacted by the phase-out of coal generation, and the fulfillment of all obligations to affected employees, in each case as prescribed by the Off-Coal Agreement. See "General Development of the Business - Three-Year History - Generation and Business Development."
Pioneer Pipeline
We currently have a 50% ownership in the Pioneer Pipeline, which transports natural gas to the Keephills and Sundance facilities. We and Tidewater each own a 50 per cent interest in the Pioneer Pipeline which is backstopped by a 15-year take-or-pay agreement from TransAlta at market rate tolls.
TransAlta and its partner, Tidewater, entered into a definitive sale of the pipeline with ATCO that is expected to receive regulatory approval and close in the first half of 2021. Following closing of the sale, Pioneer Pipeline will be integrated into NGTL's and ATCO's Alberta integrated natural gas transmission systems to provide reliable natural gas supply to TransAlta's Sundance and Keephills power generating stations.

In addition, TransAlta has entered into incremental long-term firm natural gas delivery transportation agreements with NGTL for 275 TJ per day, bringing the total long-term firm natural gas transportation contracts up to 400 TJ per day by 2023. TransAlta’s current commitments, including its 139 TJ per day supply arrangement with Tidewater, will remain in place until the closing of the sale of the Pioneer Pipeline to ATCO.

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Centralia Business Segment
Our Centralia facilities are summarized in the following table as at Dec. 31, 2020:
Facility Name Province/ State Ownership (%) Net Capacity Ownership Interest (MW) Commercial Operation Date Revenue Source Contract Expiry Date
Centralia Thermal No. 1 WA 100 670 1971 LTC/Merchant 2020
Centralia Thermal No. 2 WA 100 670 1971 LTC/Merchant 2025
Total Centralia Net Capacity (1)
1,340
Note:
(1) Centralia Unit 1 retired Dec. 31, 2020.
We own a 670 MW thermal coal-fired facility in Centralia, Washington, located south of Seattle. The Centralia Thermal Unit No. 1 retired on Dec. 31, 2020, resulting in the net capacity being reduced from 1,340 MW to 670 MW pursuant to the TransAlta Energy Transition Bill (chapter 180, Laws of 2011) (the "Bill''), which allowed the Centralia thermal facility to comply with the Washington State's GHG emissions performance standards by ceasing coal generation in one of its two boilers by the end of 2020, and the other by the end of 2025. The Bill removed restrictions that had previously been imposed on the facility limiting the duration of new contracts from the facility and limiting the technology that the facility would be required to implement for NOx controls. Centralia Unit 2 will retire effective Dec. 31, 2025.
On July 25, 2012, we announced that we entered into an 11-year agreement to provide electricity from our Centralia thermal facility to Puget Sound Energy. The contract began in 2014 and runs until 2025 when the facility is scheduled to stop burning coal. Under the agreement, Puget Sound Energy bought 180 MW of firm, base-load power starting in December 2014. In December 2015, the contract volume increased to 280 MW and from December 2016 to December 2024 the contract is for 380 MW. In 2025, the contracted volume is for 300 MW.
On July 30, 2015, we announced that we were moving ahead with plans to invest US$55 million over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives in Washington State. The initiative is part of Centralia's transition from coal-fired operations in Washington, beginning on Dec. 31, 2020. The US$55- million community investment is part of the Bill passed in 2011. The Bill was an agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State, closing Centralia facility's two coal units, one in 2020, and the other in 2025. Approved funding for the three boards totals approximately US$41.3 million as at Dec. 31, 2020.
We sell electricity from the Centralia thermal facility into the Western Electricity Coordinating Council and, in particular, on the spot market in the U.S. Pacific Northwest energy market. Our strategy is to balance contracted and non-contracted sales of electricity to manage production and price risk.
We also own a coal mine adjacent to the Centralia facility. We stopped mining operations at our Centralia coal mine on Nov. 27, 2006. Although we estimate that certain coal reserves remain to be extracted, we have not yet received permits for, nor developed the new area from which this coal could be produced. Coal to fuel the Centralia facility is sourced from the Powder River Basin in Montana and Wyoming. TransAlta is currently party to coal contracts that expire at the end of 2025.
In December 2014, we began fine coal recovery operations at our Centralia mine. This operation recovers previously wasted coal as part of the mine reclamation process.
Under the U.S. Federal Mine Safety and Health Act, TransAlta must report all citations at its Centralia mine. The mine is currently not in operation and there were no injury incidents reported at the mine during 2020. The total dollar value of all Mine Safety and Health Administration ("MSHA") assessments are not material. Centralia successfully petitioned to assess a civil penalty before the Federal Mine Safety and Health Review Commission involving the Centralia mine during 2020. The petition was settled which resulted in a reduction of the assessment from "Negligence - Moderate" to "Negligence - None."
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Mine or
Operating
Name/MSHA
Identification
Number 		Total Number of Section
104
Violations
for which
Citations
Received
(#) 		Total Number of Orders Issued Under Section 104(b)
(#) 		Total Number of Citations and Orders for Unwarrantable Failure to Comply with Mandatory Health or Safety Standards Under Section 104(d)
(#) 		Total Number of Flagrant Violations Under Section 110(b)(2)
(#) 		Total Number of Imminent Danger Orders Issued Under Section 107(a)
(#) 		Total Dollar
Value of
MSHA
Assessments
Proposed
($) 		Total
Number
of
Mining
Related
Fatalities
(#) 		Received
Notice of
Pattern
Violations
Under
Section
104(e)
(yes/no) 		Received
Notice of
Potential
to
Have
Pattern
Under
Section
104(e)
(yes/no) 		Legal
Actions Initiated or
Pending
During Period
(#)
4500416
15(1)
0 0 0 0
7,524 (2)
0 No No 0
Notes:
(1) Section 104 Violations: TransAlta Centralia Mining and Coalview Centralia LLC.
(2) Citations in Contest: Coalview Centralia LLC (104a - $3,573).

Energy Marketing Segment
Our Energy Marketing segment provides a number of strategic functions, including the following:
▪gathering and analyzing market trends to enable more effective strategic planning and decision making;
▪negotiating and entering into contractual agreements with customers for the sale of output from our generation assets, including electricity, steam or other energy-related commodities;
▪actively engaging in the trading of power, natural gas and environmental products across a variety of markets;
▪negotiating and managing fuel supply arrangements with third parties for our generation assets. This includes scheduling, billing and settlement of physical deliveries of natural gas and other fuels;
▪developing and executing our corporate hedging strategy within Board- approved parameters; and
▪optimizing the asset fleet to maximize gross margin and mitigation of market risks.
The Energy Marketing segment also derives additional revenue by providing fee-based asset management services to third parties, earning margins on third-party gas and power transactions, and by trading electricity and other energy commodities (i.e. fuels). The origination and trading activities are primarily focused on the existing asset and customer footprint of the Corporation.
The segment seeks to measure and manage a number of risks for the assets and for our trading books. The key risk control activities of the Energy Marketing segment include the measurement and management of market, credit, operational, reputational, compliance and legal risks.
The segment uses Value at Risk , Gross Margin at Risk , and tail risk measures to monitor and manage the risks within our asset and trading portfolios. Value at Risk and Gross Margin at Risk measure the potential losses that could occur over a given time period due to changes in market risk factors. Back tests are used to provide further sensitivities to the market risks within the portfolio. Compliance, reputational and legal risks are managed within our legal and compliance policies, and monitoring tools are used to flag compliance risks. The Energy Marketing segment actively manages the risks within approved limits and our policies.
Corporate Segment
Our Corporate segment includes the Corporation's central finance, legal, administrative, business development and investor relations functions.
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Non-Controlling Interests
Our subsidiaries and operations in which we have non-controlling interests are as follows:
TransAlta Renewables
As at Dec. 31, 2020, the Corporation held, directly and indirectly, approximately 60 per cent of the issued and outstanding common shares in TransAlta Renewables, which is a publicly traded entity. We remain committed to maintaining our position as the majority shareholder of TransAlta Renewables.
TransAlta Corporation provides all management, administrative and operational services required for TransAlta Renewables to operate and administer its assets and to acquire additional assets pursuant to the Management, Administrative and Operational Services Agreement between TransAlta Corporation and TransAlta Renewables. In connection with the services provided under the Management, Administrative and Operational Services Agreement, TransAlta Renewables pays us an annual fee, which is meant to cover the management, administrative, accounting, planning and other head office costs we incur in connection with providing services to TransAlta Renewables under the Management, Administrative and Operational Services Agreement (the "G&A Reimbursement Fee"). The G&A Reimbursement Fee is payable in equal quarterly installments. On Feb. 28, 2020, the Management Agreement was amended so that the G&A Reimbursement Fee will be calculated quarterly in an amount equal to five per cent of comparable EBITDA of the immediately prior fiscal quarter, without duplication for any indirect costs associated with the management, administrative, accounting, planning and other head office costs of TransAlta that reduce the dividends or distributions that would otherwise be payable to the Corporation on any of the tracking preferred shares. This amendment is not expected to result in any material change to the amount of the G&A Reimbursement Fee. On Aug. 19, 2020, the Management Agreement was amended to clarify comparable EBITDA calculated before taking into account the G&A Reimbursement Fee. During 2020, the G&A Reimbursement Fee was approximately $17 million.
TransAlta Renewables completed its initial public offering in August 2013. In connection with the offering, we transferred to TransAlta Renewables certain wind and hydro power generation assets. On Dec. 20, 2013, we sold to TransAlta Renewables an economic interest in a 140 MW wind facility located in the State of Wyoming for payment equal to US$102 million. The Wyoming wind facility is managed by TransAlta under the terms of the Management, Administrative and Operational Services Agreement and is operated by NextEra Energy Resources, LLC.
On May 7, 2015, we sold to TransAlta Renewables an economic interest based on the cash flows of our Australian assets. The portfolio, held by TEA, consists of six operating assets with an installed capacity of 450 MW as well as a 270 kilometre gas pipeline. The combined value of the Australian transaction was approximately $1.78 billion. At the closing of the Australian transaction, TransAlta Renewables paid us $216.9 million in cash as well as approximately $1,067 million through the issuance of a combination of common shares and Class B shares in the capital of TransAlta Renewables. On Aug. 1, 2017, the Class B shares converted into common shares in the capital of TransAlta Renewables.
On Jan. 6, 2016, we sold to TransAlta Renewables an economic interest in the Corporation's Sarnia cogeneration plant, Le Nordais wind facility and Ragged Chute hydro facility for a combined value of $540 million. The Canadian assets consist of approximately 611 MW of contracted power generation assets located in Ontario and Québec. The Corporation received cash proceeds of $172.5 million, a $215 million convertible unsecured subordinated debenture and approximately $152.5 million in common shares of TransAlta Renewables. In November 2016, the economic interest was converted to direct ownership of the entities that own the Sarnia cogeneration plant, Le Nordais wind facility and Ragged Chute hydro facility. The convertible debenture was redeemed on Nov. 9, 2017.
On May 31, 2018, we sold to TransAlta Renewables an economic interest in the Corporation's 50 MW Lakeswind wind facility in Minnesota and 21 MW of solar projects located in Massachusetts. In addition, we sold to TransAlta Renewables the 20 MW Kent Breeze wind facility located in Ontario. The total purchase price payable to TransAlta for the three assets, which have an average weighted contract life of 15 years, was $166 million, including the assumption by TransAlta Renewables of $62 million of tax equity obligations and project debt.
On Dec. 23, 2020, the Corporation and TransAlta Renewables announced it had entered into a definitive agreement for the acquisition of three assets consisting of: (a) a 100 per cent direct interest in the 207 MW Windrise project located in the Municipal District of Willow Creek, Alberta; (b) a 49 per cent economic interest in the 137 MW Skookumchuck wind facility in operation located across Thurston and Lewis counties in Washington State; and (c) a 100 per cent economic interest in the 29 MW Ada facility in operation located in Ada, Michigan. TransAlta Renewables agreed to acquire the portfolio for a total acquisition cost of $439 million and includes the funding of the remaining construction costs for the Windrise wind project.
The Management, Administrative and Operational Services Agreement has an initial 20-year term; it provides, however, that the agreement shall be automatically renewed for further successive terms of five years after the expiry of the initial term or any renewal term, unless terminated by either party not less than 180 days before the expiration of the initial term or any renewal term, as the case may be. The Management, Administrative and Operational Services
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Agreement may be terminated by: (a) mutual agreement; (b) TransAlta Renewables upon the occurrence of a material default by TransAlta; and (c) TransAlta (i) upon the occurrence of a material default by TransAlta Renewables or (ii) upon a "Change of Control" of TransAlta Renewables, being the acquisition by any person or group of persons acting jointly and in concert (other than us and our affiliates) of more than 50 per cent of the issued and outstanding common shares. In addition, the Management, Administrative and Operational Services Agreement may be terminated by TransAlta Renewables by a majority vote of our independent directors at any time if TransAlta's direct and indirect ownership in TransAlta Renewables falls below 20 per cent.
Kent Hills
We indirectly hold, through our share ownership of TransAlta Renewables, an 83 per cent interest in the 150 MW Kent Hills 1 and 2 wind facility located in New Brunswick. We also indirectly hold, through our ownership of TransAlta Renewables, an 83 per cent interest in the 17.25 MW expansion of the Kent Hills site (Kent Hills 3) that was completed on Oct. 19, 2018, bringing the total generating capacity of the three Kent Hills fleet to 167 MW. A description of the facilities is provided under the heading "General Development of the Business – Three-Year History - Generation and Business Development."
TA Cogen
We hold a 50.01 per cent limited partnership interest in TA Cogen, which is an Ontario limited partnership. The remaining 49.99 per cent ownership is held by Canadian Power Holdings Inc., a subsidiary of CK Infrastructure Holdings Limited.
TA Cogen holds a 50 per cent interest in the 800 MW Sheerness thermal generation facility in Alberta and the 118 MW Fort Saskatchewan natural -gas fired cogeneration facility in Alberta. TA Cogen also holds an interest in two natural gas-fired cogeneration facilities located in Ontario: (i) the 74 MW Ottawa plant; and (ii) the 72 MW Windsor plant. Descriptions of these facilities, ownership levels and contract expiry dates are provided under the headings "North American Gas Business Segment" and "Alberta Thermal Business Segment" in this AIF.
PPAs
Renewables PPAs 
In August 2013, we entered into long-term PPAs with certain subsidiaries of TransAlta Renewables (each a "Merchant Subsidiary") providing for the purchase by TransAlta, for a fixed price, of all of the power produced at the Merchant Subsidiaries (the "Renewables PPAs"). The initial price payable in 2013 by TransAlta for output under the Renewables PPAs was $30.00/MWh for wind facilities and $45.00/MWh for hydroelectric facilities, and these amounts are adjusted annually for changes in the Canadian consumer price index. The Canadian consumer price index adjusted prices for 2020 were $33.52 per MWh for wind facilities and $50.29 per MWh for hydroelectric facilities. Under the terms of each Renewables PPA, the Merchant Subsidiary is under no obligation to deliver any specified amount of energy and, in no event, shall any penalties or curtailment payments be payable under the Renewables PPA. The Merchant Subsidiary will assume all operating and generating risk and TransAlta will only be required to purchase power that is actually produced.
Each Renewables PPA has a term of 20 years or end-of-asset life, where end-of-asset life is less than 20 years. Each Renewables PPA may be terminated by: (a) the mutual agreement of the parties; (b) the Merchant Subsidiary upon the occurrence of a material default by TransAlta; and (c) TransAlta (i) upon the occurrence of a material default by the Merchant Subsidiary; (ii) upon a change of control of TransAlta Renewables; or (iii) upon a change of control of the Merchant Subsidiary.
Alberta PPAs
Until Dec. 31, 2020, many of our Alberta thermal and hydroelectric facilities had operated under Alberta PPAs that established committed capacity and electrical energy generation requirements and availability targets to be achieved by each thermal facility, energy and ancillary services obligations for the hydroelectric facilities, and the price at which electricity is to be supplied. We held the risk or retained the benefit of availability under or above a targeted availability (except for those arising from events considered to be force majeure, in the case of the PPA thermal facilities) and any change in costs (unless due to a change in law) required to maintain and operate the facilities.
In early 2016, the buyers gave notice to the Balancing Pool of the termination of the Alberta PPAs for Sundance A, B, and C, Sheerness, and Keephills. The Balancing Pool confirmed the terminations of the PPAs for Sundance A, B, C, and Sheerness in late 2016, and confirmed the termination of the Keephills PPA in late 2017. For those Alberta PPAs that were terminated, the Balancing Pool had assumed the role of buyer. On Sep. 18, 2017, the Balancing Pool elected to terminate the Sundance B PPA and Sundance C PPA effective on or before March 31, 2018. Pursuant to a written agreement, the Balancing Pool paid us approximately $157 million on March 29, 2018. We disputed the termination payment received as the Balancing Pool excluded certain mining and corporate assets that should have been included in
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the net book value calculation. On Aug. 26, 2019, we announced that we were successful in the arbitration and received the full amount claimed by us to have been owing, being $56 million, plus GST and interest. See "General Development of the Business - Three-Year History - Generation and Business Development."
Our hydroelectric facilities, other than Belly River, Pocaterra, St. Mary, Taylor and Waterton, were aggregated through one Alberta PPA that provides for financial obligations for energy and ancillary services based on hourly targets. We met these targeted amounts through physical delivery or third-party purchases.
The Alberta PPAs expired on Dec. 31, 2020 and these facilities are now merchant units in the Alberta power market.
Competitive Environment
Power generation is an industry in the midst of an exciting transformation and the demand for electricity is expected to grow significantly over the long-term. In addition to the need to keep pace with ongoing demand growth for electricity, there are several key factors driving the need for significant investment in new generating capacity going forward. First, coal-based generation is being retired. These retirements are being driven by asset age, as well as government policy that places a price on emissions and, in some cases, mandates the retirement of these assets. Second, government policies that impose costs or provide incentives for lower emission technologies are creating opportunities for renewable generation technologies. These opportunities are coinciding with a significant decline in the installed costs of both wind and solar generation. As a result, these technologies now account for the majority of the new generating capacity added to many of the world's electricity grids. Third, electrification is seen as a one of the most effective levers to reduce GHG emissions in many sectors such as transportation. As these sectors and others continue to shift to electricity as their primary energy source we will see accelerating demand growth for our product.
We expect that renewable power generation will be one of the fastest-growing sources of power generation in both Canada and the US, a forecast that is well supported by recent trends and announcements. We are ready for this transformation. We have the skills, experience and scale to compete for additional assets within our target markets. Today, we are one of the largest publicly traded renewable power generation companies in Canada.
Alberta
Alberta's annual demand contracted approximately 2.5 per cent from 2019 to 2020 due to the combined impacts of COVID-19 and oil production shut-ins. The drop in demand was most significant in the second and third quarters. The average pool price decreased from $55 per MWh in 2019 to $47 per MWh in 2020. Pool prices were lower in each quarter compared to 2019, with additional weakness during the second quarter as a result of higher power imports into Alberta.
Alberta's Fair, Efficient and Open Competition Regulation generally provides that an electricity market participant shall not control more than of 30 per cent of the total maximum capability of generating units in Alberta. A market participant’s total offer control is measured as the ratio of MW under its control, to the sum of maximum capability of generating units in Alberta. Our market share of offer control in Alberta in 2020 was approximately 21 per cent (16 per cent if the Sundance mothballed units are excluded from offer control).
In November 2016, we announced that we had entered into an Off-Coal Agreement with the Government of Alberta that provides transition payments from the Government in consideration for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired facilities on or before Dec. 31, 2030. The affected facilities are not, however, precluded from generating electricity at any time by any method other than the combustion of coal. We also entered into a Memorandum of Understanding with the Government of Alberta to collaborate and co-operate in the development of a market in Alberta that ensures both current and new electricity generators will have a level economic playing field to build, buy and sell electricity, and to develop a policy framework to facilitate the conversion of coal-fired generation to gas-fired generation.
US Pacific Northwest
Our capacity in the US Pacific Northwest is represented by our 1,340 MW Centralia coal facility which declined to 670 MW as of Jan. 1, 2021. In the fourth quarter of 2020, we added a 49 per cent interest in the Skookumchuck wind facility. The Centralia coal facility is committed to be phased-out over the next five years, with the remaining plant capacity scheduled to retire at the end of 2025.
System capacity in the region is primarily comprised of hydro and gas generation, with some wind additions over the last few years in response to government programs favouring renewable generation. Demand growth in the region has been limited and further constrained by an emphasis on energy efficiency. We expect to see significant change in this market over the next decade as coal generation is retired and renewable portfolio standard requirements continue to strengthen.
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Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining life of the Centralia facility. The contract and our hedges allow us to satisfy power requirements from the market during low-priced periods.
We maintain the right to redevelop Centralia as a gas facility after coal capacity retires, with an opportunity for expedited permitting provided for in our agreement for coal transition established with the State of Washington in 2011.
Contracted Gas and Renewables
The market for developing or acquiring gas and renewable generation facilities is highly competitive in all markets in which we operate. Our solid record as operator and developer supports our competitive position. We expect, where possible, to reduce our cost of capital and improve our competitive profile by using project financing and leveraging the lower cost of capital with TransAlta Renewables. In the U.S., our substantial tax attributes further increase our competitiveness.
While depressed commodity prices have reduced sectoral growth in the oil, gas and mining industries, the change is also creating opportunities for us as a service-provider as some of our potential customers are more carefully evaluating non-core activities and seeking operational efficiencies. In renewables, we are primarily evaluating greenfield opportunities in Western Canada and the United States along with targeted acquisitions in these same markets. We maintain highly qualified and experienced development teams to identify and develop these opportunities. In cogeneration, we are working with customers to evaluate behind-the-fence solutions.
Some of our older gas facilities are now reaching the end of their original contract life. The facilities generally have a substantial cost advantage over new builds and we have been able to add value by recontracting these facilities with limited life-extending capital expenditures. We have recently extended the contracted life of our Ottawa (2033 expiry), Windsor (2031 expiry), Parkeston (2026 expiry), Fort Saskatchewan (2030 expiry) and Southern Cross Energy (2038) facilities in this manner.
Australia
The Australian electricity industry is divided among three distinct markets, the National Electricity Market (NEM) in the East, the Wholesale Electricity Market (WEM) in Western Australia and the Northern Territory Electricity Market. In addition, there is a significant market for "off-grid" generation supporting remote communities and remote mining operations, particularly in Western Australia, Queensland and the Northern Territory.
The NEM is the largest market in Australia, currently with over 53 GW of installed capacity. The installed capacity based on coal generation is about 23 GW and much of this is expected to retire over the next decade due to the age of these assets. Renewables penetration, both wind and solar, has grown strongly in this market and that is expected to continue. The federal Department of Environment and Energy predicts an overall renewables penetration of 50 per cent in the NEM and 55 per cent in the WEM by 2030.
Our business today is solely in Western Australia, and focused on the large remote mining industry in that state. The primary exports from Western Australia are iron ore, nickel and gold and these three industries are all performing well. Commodity prices are strong, especially iron ore. Iron ore exports from Western Australia are forecast to rise driven by large-scale producers ramping up production with new mines. The nickel industry is also experiencing an increase in demand to support both steel and battery manufacturers. Remote mining operations are exploring options to add renewable generation to their existing and new sites in an effort to reduce the amount of gas and diesel required in these operations. Our Southern Cross Energy facilities in the Goldfields region has a number of projects in development under our newly extended contractual arrangement to help our customer achieve their decarbonization objective. We expect this trend to continue and to create further opportunities for our business in Western Australia.
Seasonality and Cyclicality
Our business cyclical, particularly in respect of the renewables generation held by TransAlta Renewables, due to: (a) the nature of electricity and the limited storage capacity; and (b) the nature of wind, solar and run-of-river hydroelectric resources, which fluctuate based on both seasonal patterns and annual weather variation.
Typically, run-of-river hydroelectric facilities and solar facilities generate most of their electricity and revenues during the spring and summer months when the melting snow starts feeding the watersheds and the rivers, and the sun is at its highest peak. Inversely, wind speeds are historically greater during the cold winter months when the air density is at its peak. TransAlta Renewables’ strategy of technological and geographical diversification reduces the Corporation’s exposure to the variations of any one natural resource in any one region. Since TransAlta Renewables’ operations are presently based mainly on power generation from wind, its financial results in any one quarter may not, however, be representative of all quarters. See "Risk Factors."
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Regulatory Framework
Below is a description of the regulatory framework in the markets that are material to the Corporation.
Canadian Federal Government
In November 2016, the Canadian federal government announced that coal-fired generation would be phased out by 2030, following a similar commitment by the Alberta provincial government in November 2015. These decisions changed the coal facility closure requirements, which had previously been guided by federal regulations that became effective on July 1, 2015, which provided for up to 50 years of life for coal units. On Feb. 16, 2018, Environment and Climate Change Canada announced draft regulations to phase out coal-fired generation by 2030, as well as draft regulations for gas-fired electricity generation including provisions for the conversion of boiler units from coal-fired generation to natural-gas fired generation. Please refer to "Environmental Risk Management - Ongoing and Recently Passed Environmental Legislation" for more information.
Alberta
Since Jan. 1, 1996, new generating capacity initiatives in Alberta have been undertaken by independent power producers ("IPP") and have been subject to market forces, rather than rate regulation. Power from commercial generation is cleared through a wholesale electricity market. Power is dispatched in accordance with an economic merit order administered by the AESO, based upon offers by generators to sell power. Our merchant Alberta fleet operates under this framework and we internally manage our offers to sell power. The Market Surveillance Administrator for the Province of Alberta is an independent entity responsible for monitoring and investigating the market behaviour of market participants, including the AESO and the Balancing Pool, and enforcing compliance with all applicable legislation, regulations, AESO and AUC rules. The AUC oversees electricity industry matters, including new power plant and transmission facilities and the distribution and sale of electricity and retail natural gas. The AUC is also responsible for approving the AESO's rules and for determining penalties and sanctions on any participant found to have contravened market rules.
On July 24, 2019, the Government of Alberta announced that it will not transition to a capacity market and will continue with an energy-only market design. This decision stopped all work on the capacity market design work, which had been underway through the AESO since 2017. The Government’s announcement followed a stakeholder consultation and review that found stakeholder support for maintaining the energy-only market based upon its proven track record for providing a reliable supply and affordable electricity for Albertans. The removal of legislative changes to enable the capacity market received royal assent on Oct. 31, 2019.
The Minister of Energy further directed Alberta Energy to conduct a policy review on market power and market power mitigation in the energy-only and ancillary services market and directed the AESO to conduct analysis and make recommendations on whether changes are needed to the price floor/ceiling and shortage pricing by July 31, 2020. The AESO's review concluded that no changes were necessary to the pricing or market power mitigation framework in the energy-only market. On Aug. 28, 2020, the Associate Minister announced that the government accepts the AESO's recommendation and no changes will be made to Alberta's energy-only wholesale market design.
Ontario
Ontario's electricity market is a hybrid market that includes a wholesale spot electricity market, as well as regulated prices for certain electricity consumers and long-term contracts for the purchase of power by the IESO from power producers. The IESO is the successor organization resulting from the merger of the former IESO and Ontario Power Authority in 2015. The Ontario Ministry of Energy, Northern Development and Mines supports the IESO in defining the electricity mix to be procured by the IESO. The IESO has the mandate to undertake long-term planning of the electric power system, procure the electricity generation in that plan and manage contracts for privately owned generation. The IESO is responsible for managing the Ontario wholesale market and for ensuring the reliability of the electricity system in Ontario. The electricity sector is regulated by the Ontario Energy Board.
The IESO began a market renewal consultation that includes proposed fundamental changes to the electricity market. These include modifying the energy market, adding a capacity market and improving operability and reliability. The IESO ran its first capacity auction in December 2020. The IESO has also begun developing a resource adequacy framework that it intends to develop in 2021. The IESO is continuing to consult on changes to the energy market that are expected to be implemented in early 2023.
British Columbia
British Columbia's electricity market is dominated by BC Hydro, a vertically integrated Crown corporation. The other provincial utility, FortisBC, has a small service territory in the interior of the province. Electricity is traded with other markets through BC Hydro's trading arm and wholly-owned subsidiary, Powerex. All electricity utilities are regulated by the British Columbia Utilities Commission ("BCUC").
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Under government direction in the late 1990s and early 2000s, BC Hydro established a private power market through several competitive calls for power from IPPs. In recent years, BC Hydro stopped its competitive power calls and contracting with IPPs and also suspended its smaller Standing Offer Program for small projects below 15 MW.
BC Hydro is delaying discussions related to recontracting assets until it has completed it new Integrated Resource Plan ("IRP"). In 2020, BC Hydro started its Clean Power 2040 consultation process to feed into the development of IRP . The purpose of the Clean Power 2040 is to develop a long-term electricity system view to meet the climate change and supply objectives related to provincial policy and legislation. The first round of discussions were completed in late 2020. In early Spring 2021, a second round of consultations will take place on the draft IRP that was developed based on the findings of the round one discussions. BC Hydro expects to submit its final IRP to the BCUC in September 2021. The BCUC will hold a public review process on the IRP prior to providing a decision on the IRP.
Current Clean Power 2040 initial results indicate BC Hydro continues to find a need to renew Energy Purchase Agreements with existing independent power producers, which could include TransAlta's Pingston Hydro project.
Québec
The Régie de l'énergie is Québec's regulatory authority with primary jurisdiction over the economic regulation of the electricity sector. Québec is served principally by Hydro-Québec, a government-owned entity with highly-competitive hydroelectric resources. It has an almost exclusive right to distribute electricity throughout the Province of Québec. Most of Hydro-Québec's generation stations are located substantial distances from consumer centres. As a result, Québec's transmission system is one of the most extensive and comprehensive in North America, comprising more than 33,000 kilometres of lines. In all cases, an agreement with Hydro-Québec on the price of the electricity produced is required before a project can obtain governmental approval. Overall, Hydro-Québec's structure makes new projects difficult but existing projects, such as Le Nordais, that have contracts in place are generally unaffected and are able to re-contract.
New Brunswick
In 2004, New Brunswick enacted the Electricity Act (New Brunswick), under which the province's electricity market changed to enable the creation of a competitive environment for eligible wholesale, industrial and municipal utility customers. The legislation provides that, as generating assets are retired or as additional supply is required, standard service suppliers (i.e. the distribution companies) will procure new supply through the competitive market. This means that any new resources required by New Brunswick Power will be acquired through procurement processes open to both IPPs, as well as the New Brunswick Power.
US Wholesale Power Market
The Federal Power Act gives the Federal Energy Regulatory Commission ("FERC") rate-making jurisdiction over public utilities engaged in wholesale sales of electricity and the transmission of electricity in interstate commerce. The Federal Power Act also provides FERC with the authority to certify and oversee an electric reliability organization that promulgates and enforces mandatory reliability standards applicable to all users, owners and operators of the bulk-power system. FERC has certified the North American Electric Reliability Corporation ("NERC") as the electric reliability organization. NERC has promulgated mandatory reliability standards, and, in conjunction with the regional reliability organizations that operate under FERC's and NERC's authority and oversight, enforces those mandatory reliability standards.
Minnesota (MISO)
Lakeswind in Minnesota is connected to the Midwest Independent System Operator (MISO) and falls under FERC jurisdiction. FERC-approved MISO tariffs dictate market and operational requirement for facilities. MISO has both an energy market and a voluntary capacity market. Under the long-term contract, all power is delivered at the plant-gate, ensuring market changes should have an immaterial impact on revenues.
Massachusetts (NE-ISO)
The Mass Solar facility is connected to the distribution grid so its generated electricity flows directly to the utility and is not offered into the integrated market. All revenues associated with this project flow from the State's net metering and Renewable Energy Portfolio Standard programs. Market changes are not expected to have a material impact on net metering revenues.
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New Hampshire (NE-ISO)
Antrim in New Hampshire is connected to the New England Independent System Operator (NE-ISO) and falls under FERC jurisdiction. FERC-approved NE-ISO tariffs dictate market and operational requirements for facilities. The NE-ISO has both an energy and a mandatory-participation capacity market. Antrim's electricity is offered into the market and transferred to the buyers. Antrim has a long-term capacity supply obligation so it is not impacted by near term changes to the capacity market auction process. As Antrim and most other intermittent wind projects must take part in the NE-ISO's Do Not Exceed Dispatch, market changes are not expected to have a material impact on revenues.
Pennsylvania (PJM)
Big Level in Pennsylvania is connected to the PJM ISO and falls under FERC jurisdiction. FERC-approved PJM tariffs dictate market and operational requirements for facilities. PJM has both an energy and a mandatory participation capacity market. Big Level's attributes including energy, capacity, and environmental credits have been transferred to the buyer. As a result, market changes are not expected to have a material impact on revenues during the contract term.
Washington
The Washington Transportation and Utilities Commission has the power to regulate and supervise every "public utility," which includes investor-owned electric utilities. For regulated electric utilities, the commission approves regulated rates, reviews integrated resource plans, approves mergers and acquisitions and grants certificates of public convenience and necessity for large facilities (i.e. power plants and transmission lines). Centralia and the Skookumchuck wind facility are not regulated by the Commission as they only sell wholesale electricity and do not sell retail electricity in the state. Only FERC and NERC requirements apply to the facility. As a result, the Corporation does not expect any material impacts on revenue streams from any commission decisions.
Wyoming
The Wyoming Public Service Commission has the power to regulate and supervise every "public utility," which includes the four investor-owned electric utilities in Wyoming, as well as certain natural gas, electric, telecommunications, water and pipeline services. For regulated electric utilities, the commission approves regulated rates, reviews integrated resource plans, approves mergers and acquisitions and grants certificates of public convenience and necessity for large facilities (i.e., power plants and transmission lines). Wyoming wind facility is not regulated by the commission as it only sells wholesale electricity and does not sell retail electricity in the state. Only FERC and NERC requirements apply to the facility. As a result, the Corporation does not expect any material impact on revenue streams from any commission decisions.
Australia
Australia has two separate major electricity markets, the NEM encompassing all the major population centres on the Eastern seaboard, and the WEM covering the southwest of Western Australia including its capital city, Perth. A number of smaller, standalone electricity grids serve regional population centres including the North West Interconnected System ("NWIS") in the Pilbara region of Western Australia and the Darwin-Katherine System in the Northern Territory.
The Australian Energy Market Operator is the market operator for both the WEM and the NEM. The two markets are completely independent of each other having different market rules and no physical interconnection between them. The WEM includes both a market for generation capacity and a gross pool to trade energy with a single reference node for wholesale prices. The NEM is a pure energy-only market with five regional reference nodes for wholesale prices corresponding to each of the participating states of Queensland, New South Wales, Victoria, Tasmania and South Australia.
The Public Utilities Office of Western Australia ("PUO") in its capacity as advisor to the Minister for Energy is currently working with Australian Energy Market Operator and the wider electricity industry to implement further reforms to the WEM including introducing constrained network access and required consequential amendments to the wholesale market rules to allow for security constrained dispatch. A comprehensive program of works is currently underway with a goal of implementing reforms on Oct. 1, 2022.
The PUO is also working with participants in the NWIS to introduce some elements of a more formal electricity market, including providing third-party access to the Horizon Power-owned part of the NWIS and providing centralized coordination of dispatch and ancillary services.
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Competitive Strengths
We believe that we are well positioned to achieve our business strategy due to our competitive strengths, which include the following:
Operating Strength
We continually benchmark ourselves against previous year performance in order to drive operating costs lower year over year, while also maintaining strong levels of generation performance. We have implemented a program to drive incremental value from our fleet by developing initiatives to improve generating equipment efficiencies, refining processes and procedures, and optimizing cost structures. Our Sarnia cogeneration facility has demonstrated industry best practices through several operations and maintenance processes, including the work management process and Environmental, Health & Safety scorecard. We believe the continued maturity of these programs will continue to drive further value in the operations of our facilities.
Stable Cash Flow Base
Through the use of long-term contracts, approximately 47 per cent of our capacity is contracted in 2021 and 2022. The net revenue received under these contractual arrangements helps to minimize short-term revenue fluctuations due to the variable price of electricity. The Corporation also regularly hedges portions of its uncontracted merchant positions to further stabilize cash flows from market volatility.
Portfolio Diversity
The diversity of our fuel sources used for the generation of electricity underscores our desire to be Canada's leading clean electricity supplier. Our portfolio mix consists of wind, hydro, solar, energy storage, and natural gas. In 2020, we successfully commissioned Alberta's first utility-scale battery storage project that is powered by the Summerview 2 wind facility.
We continue to use coal as a source of fuel during our transition at a number of our facilities and we optimize this fuel through co-firing with natural gas to produce cleaner and lower cost electricity. We will continue to optimize this strategy until we fully complete the transition off coal to natural gas at our Alberta Thermal facilities by the end of 2021.
We believe we have reduced the potential impact of external events that affects one fuel source or one geographic region on our performance given the location of our operations across Canada, the United States and Australia, as well as our diverse fuel mix.
Management Team and Employee Experience
Our management team has substantial industry, international, investment and market experience. The experience and acumen of our employees further enhances our capital value creation. Our business has been operating for more than 109 years, and many of our employees have been with us for more than 30 years.
Energy Marketing Expertise
We believe that our Energy Marketing segment has enhanced returns from our existing generation base and has allowed us to obtain more favourable pricing for uncommitted electricity, secure fuel supply on a cost-effective basis and fulfill electricity delivery obligations in the event of an outage.
Wind Generation
Through our ownership interest in TransAlta Renewables, we are one of the largest owners and operators of wind generation in Canada. Our management team has developed key relationships with customers, suppliers and policy makers that provide a competitive advantage in the development, operations and marketing of wind generation.
Environmental, Social and Governance
We are a recognized leader in sustainable development and we have taken early preventive action on a number of environmental fronts in advance of regulation. We have a long history of adopting leading sustainability practices, including 25 years of sustainability reporting and voluntarily integrating our sustainability report into our annual report. We have been issuing an integrated annual report since 2015. We test our practices and our reporting against standards set by CDP (formerly the Carbon Disclosure Project), the Task Force on Climate-related Financial Disclosures and the Canadian Council for Aboriginal Business. TransAlta has been operating hydroelectric facilities for more than 109 years and was an early adopter of wind power generation, acquiring its first wind assets in 2002. Today we are the leading producer of wind power in Canada. Through our ongoing transformational efforts and largely through our coal transition, we are on track to reduce our total GHG emissions by approximately 70 per cent from 2005 levels by the end of 2022.
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Environmental Risk Management
We are subject to federal, provincial, state and local environmental laws, regulations and guidelines concerning the generation and transmission of electrical and thermal energy and surface mining. We are committed to complying with legislative and regulatory requirements and to minimizing the environmental impact of our operations. We work with governments and the public to develop appropriate frameworks to protect the environment and to promote sustainable development.
Ongoing and Recently Passed Environmental Legislation
Changes in current environmental legislation do have, and will continue to have, an impact on our operations and business. For further details, see below and "Risk Factors."
Climate-Related Financial Disclosure
TransAlta has prepared an assessment of climate-related risks and opportunities to conform with the recommendations of the Task Force on Climate-related Financial Disclosure describing our climate change strategy, governance, risk management approach, GHG metrics and targets. This document can be accessed on our website at www.transalta.com/sustainability/reporting-our-sustainable-value.
Canadian Federal Government
Federal Carbon Pricing on GHG
On June 21, 2018, the Canadian federal Greenhouse Gas Pollution Pricing Act ("GGPPA") came into force. Under the GGPPA, the Canadian federal government implemented a national price on GHG emissions. The price began at $20 per tonne of CO2e emissions in 2019, and rises by $10 per year until reaching $50 per tonne in 2022. In 2022, there will be a review of the Output-Based Pricing Standard ("OBPS") and other aspects of the GGPPA.
The OBPS regulates large emitters' carbon intensity by setting a sectoral performance standard (benchmark) of GHG emissions per unit of production. Emitters exceeding the benchmark generate carbon obligations and those emitters that perform below the benchmark generate EPCs. Emitters can meet their obligations by reducing their emission intensity, buying carbon credits from others (offsets or EPCs) or making compliance payments to the government.
On Jan. 1, 2019, the GGPPA's backstop mechanisms came into force in provinces and territories that did not have an independent carbon pricing program or where the existing program was not deemed equivalent to the federal system. The backstop mechanism has two components: the federal pollution pricing fuel charge ("Carbon Tax") and the regulation for large emitters, OBPS. The Carbon Tax sets a carbon price per tonne of GHG emissions related to transportation fuels, heating fuels and other small emission sources. As noted below, Ontario is the only jurisdiction where TransAlta operates assets covered by the OBPS and this will change as the province initiates its own emissions regulation for large emitters. Alberta and Ontario are subject to the federal Carbon Tax.
Other jurisdictions that were compliant with the GGPPA did not have the backstop mechanism imposed in 2020. These jurisdictions must file and have their carbon pricing programs approved annually by the federal government. Over future annual compliance periods, if parts or all of a province's GHG regulations fall out of compliance with the GGPPA, the federal government will impose its backstop mechanisms.
In Reference re Greenhouse Gas Pollution Pricing Act, the Court of Appeal of Alberta held that Parts 1 and 2 of the GGPPA are unconstitutional in their entirety. This decision is the first time that a court has found the GGPPA to be unconstitutional. In split decisions released last year, both the Court of Appeal for Ontario and the Court of Appeal for Saskatchewan concluded that the GGPPA is constitutional. The Supreme Court of Canada is set to determine the matter in 2021.
On Dec. 11, 2020, the Government of Canada released its “A Healthy Environment and a Healthy Economy” climate plan that outlines how the federal government intends to use policies, regulations, and funding to achieve Canada’s Paris Agreement emissions reduction target of a 30 per cent reduction from 2005 GHG emission levels. The three major aspects of the plan include increased carbon prices and obligations, increased funding for clean technology and the implementation of the Clean Fuel Regulation (“CFR”). The government stated that it will consult with provinces and industry regarding many elements of the plan so significant uncertainty remains regarding final form of the regulations and other initiatives.
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The following are key proposed elements of the federal plan:
•The carbon price for the carbon tax and the larger emitters program will rise $15 per tonne CO2e per year from 2023 until reaching $170 per tonne CO2e by 2030;
•Carbon obligations will rise as benchmark under large emitter regulations tighten;
•Over $10 billion of funding will be available for everything from electric vehicles and clean energy development, to battery storage and improved grid technology; and
•The CFR will apply to liquid fuels but not to gaseous and solid fuels.
TransAlta will continue to engage with governments to mitigate risks and identify opportunities within the new federal plan.
Gas Regulation
On Dec. 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. Under the regulations, new and significantly modified natural-gas fired electricity facilities with a capacity greater than 150 MW must meet a standard of 0.420 tonnes of CO2e/MWh to operate. For units with a capacity between 25 MW and 150 MW , their standard was set at 0.550 tCO2e/MWh. For units of 25 MW or less, there is no standard.
Under the regulations, conversion to gas will also eventually have to meet a standard of 0.420 tonnes of CO2e/MWh. If the first -year performance test after conversion meets certain emission standards it will not have to meet the 0.420 tonnes of CO2e/MWh standard for several additional years past the end of its useful life.
Under the Healthy Environment and a Healthy Economy plan, the federal government signaled consideration of a new electricity emissions standard. TransAlta is engaging the federal government to understand the proposal.
Coal Regulation
On Dec. 12, 2018, amendments to the Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity Regulations came into force under the Canadian Environmental Protection Act, 1999. Under the amended regulations, coal units must meet an emission level of 0.420 tonnes of CO2e/MWh by the earlier of end-of-life or Dec. 31, 2029.
Clean Fuel Regulation
In 2016, the Canadian federal government announced plans to consult on the development of a CFR to reduce Canada’s GHG emissions through the increased use of lower carbon fuels, energy sources and technologies. The objective of the regulation is to achieve 30 million metric tonnes of annual reductions in GHG emissions by 2030.
On Dec. 19, 2020, the Canadian federal government published its draft version of the CFR with the accompanying supporting documents. As a result of gaseous fuels no longer being regulated by the CFR, the CFR will have a limited impact on the electricity sector. Consultation on the regulation will conclude on March 4, 2021. The CFR is scheduled to be finalized in December 2021 and come into force on Dec. 1, 2022.
Alberta
Large Emitter Greenhouse Gas Regulations
On Jan. 1, 2020, the Government of Alberta replaced the previous Carbon Competitiveness Incentive Regulation (CCIR) with a new regulation called the Technology Innovation and Emissions Reduction (TIER) regulation. For the electricity sector, there were negligible changes between CCIR and TIER with renewable facilities continuing to receive crediting. The carbon price for TIER in 2021 is $40 per tonne of CO2e aligned with the GGPPA requirements. The performance standard benchmark remained at 0.370 tonnes of CO2e/MWh. A review of TIER is not expected until 2023.
Facilities with emissions above the set benchmark comply with TIER by: a) paying into the TIER Fund (a government-controlled fund that invests in emissions reduction in the province) at the current carbon price; b) making reductions at their facility;c) remitting emission performance credits from other facilities; or iv) remitting emission offset credits.
As required by the GGPPA, the Alberta government files annual reports on TIER program details with the federal government. The federal government reviewed TIER and found it compliant with the GGPPA for 2021. The Company will continue to receive offsets and EPC for its renewable facilities under TIER ensuring expected revenues are realized.
British Columbia
Beginning April 1, 2018, the British Columbia government increased its carbon tax price to $35 per tonne of CO2e and committed to raise the price $5 per year until it reaches $50 per tonne in 2021. Upon review, the government has determined that the carbon tax rate will remain at its current level of $40 per tonne of CO2e until April 2021, when it
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will increase from $40 to $45 per tonne of CO2e. The carbon tax will increase to $50 per tonne of CO2e in April 2022. The tax has a negligible cost impact for the Company as the tax applies primarily to our transportation fuel use which is negligible in B.C.
Ontario
Large Emitter Greenhouse Gas Regulations
On July 4, 2019, the Government of Ontario released its own final regulations for the provincial Greenhouse Gas Emissions Performance Standards (EPS). On Sep. 21, 2020, the federal government accepted the Ontario government's EPS as meeting the requirements of the GGPPA. In Dec. 2020, the Ontario government published amendments to align the EPS with the GGPPA requirements. The Ontario government also announced its intention to transition from the OBPS to the EPS starting on Jan. 1, 2021. This mean Ontario's large emitters will have been covered by the OBPS for 2019 and 2020 compliance years and, in the future, will be covered by the EPS.
This requires TransAlta's Ontario natural gas fired assets to track and make compliance filings annually and to meet the carbon emission obligations of the applicable government. There are minor differences between the EPS and OBPS. Compliance requirements will be met through payments and alternative compliance units under the OBPS and EPS. However, change of law provisions in the contracts with Sarnia, Windsor and Ottawa allow TransAlta to flow carbon regulation-related costs to customers, resulting in negligible cost increases to the Company.
Massachusetts
The Solar Renewable Electricity Credit I (SREC I) program carved out from Massachusetts’ Renewable Portfolio Standard (RPS) an initial quantity of 400 MW from small solar facilities of 10 MW or less. The initial SREC I program size was expanded then replaced by a lower valued SREC II program. In 2018, the solar incentive program evolved into the current Solar Massachusetts Renewable Target program that further reduced the incentive levels.
The initial SREC I program’s volume target was achieved, and qualified projects under SREC I continue to generate SREC I credits for their first 10 years following their commercial operations date. SREC I facilities then generate Class 1 RECs under the Massachusetts RPS for the remainder of their operational life.
Under Massachusetts' net metering program, qualified facilities connect with the local utility and generate net metering credits. Net metering credits offset the delivery, supply and customer charges and can be sold to customers from remote or on-site qualifying facilities. In 2016, the net metering program was updated to reduce the value of the net metering credits by reducing the offset to only energy costs. New projects are impacted once the net metering program volume reaches 1,600 MW. Existing facilities were grandfathered and continue to receive the full, original cost offset treatment for a period of 25 years from initial commercial operations date.
Le Nordais receives value from the sale of RECs into the New England RPS markets. Massachusetts has proposed a lower compliance cost ceiling on its RPS standard that would effectively cap the value of RECs. This could have a negative impact on Le Nordais' REC sales price. The change in regulation is still being considered and has not yet been put into force.
Minnesota (MISO)
Minnesota has a Renewable Portfolio Standard ("RPS") and allows Michigan RECs to be used by utilities and non-utilities to meet the requirement. The RECs generated by the Lakeswind wind facility have been sold to the customer as part of their long-term contract.
New Hampshire (ISO-NE)
The New Hampshire market has an RPS, is part of the New England REC market and is also a partner in the Regional Greenhouse Gas Initiative - a carbon cap and trade program. The Antrim wind facility has long-term contracts in place for its energy and environmental attributes plus long-term capacity commitments. As a result, state and regional environmental and market regulations and policy will have an immaterial impact on revenues.
Pennsylvania (PJM)
Pennsylvania has an RPS and is linked to the New England REC markets. In December 2019, FERC released an order directing PJM, the electric grid operator covering 13 states plus the District of Columbia, to significantly expand its minimum offer price rule (MOPR) to mitigate the impacts of state-subsidized resources on the capacity market. Under these new rules, PJM must establish resource-specific MOPRs for new and existing resources that receive (or are eligible to receive) state subsidies, including renewable energy credits used to promote renewable energy and zero-emission credit. The Big Level wind facility is exempt from the MOPR rule because its interconnection construction agreement was filed prior to Dec. 19, 2019.
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Washington
In 2010, the Washington Governor's office and department of Ecology negotiated agreements with TransAlta related to the operation of Centralia’s two coal power electricity generating units. TransAlta agreed to retire its two Centralia coal units: one in 2020 and the other in 2025. This agreement is formally part of the state’s climate change program. We currently believe that there will be no additional GHG regulatory burden on Centralia given these commitments. The related TransAlta Energy Transition Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation in the State of Washington.
If the state implements a carbon pricing regulation, the Transition Bill requires the state to exempt Centralia from any related costs.
Wyoming
Wyoming has no RPS or carbon-related market. No recent actions have been taken to reconsider a wind tax in the state. The Wyoming wind facility has long-term contracts for its power and environmental attributes and the Corporation expects state environmental and market regulations and policy will not have a material impact on revenues.
Australia
On Dec. 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the "ERF"). The AU$2.55-billion ERF is the centrepiece of the Australian government's policy and provides a policy framework to cut emissions by five per cent below 2000 levels by 2020 and 26 to 28 per cent below 2005 emissions by 2030. The ERF's safeguard mechanism, commenced on July 1, 2016, is designed to ensure emissions reductions purchased by the Australian government through the ERF are not displaced by significant increases in emissions elsewhere in the economy. The ERF and its safeguard mechanism provide incentives to reduce emissions across the Australian economy.
In addition, on June 23, 2015, the federal Australian government also reformed the Renewable Energy Target ("RET") scheme. The RET is designed to add at least 33,000 GWh per year of renewable sources by 2020. The Australian government has advised there are now sufficient projects approved to meet and exceed the 2020 target of 33,000 GWh/year of additional renewable electricity. The annual target will remain at 33,000 gigawatt hours until the scheme ends in 2030. This would result in approximately 23.5 per cent of Australia's electricity generation being sourced from renewable projects.
The ERF is not expected to have a material impact on our Australian assets. In Australia, electricity has a single sectoral baseline applied to all electricity generators' emissions for units connected to one of Australia's five main electricity grids. The electricity sector baseline has been set at 198 million tonnes CO2e per year. In the most recent high emission years 2015-2016, the total emissions were 179 million tonnes of CO2e per year.
If the baseline is exceeded, then all large emitter generation facilities will need to comply with individual facility baselines. The electricity sector should never exceed the sectoral emission target as no new coal generation is to be built and older coal facilities are retiring. The Company's gas facilities will not be subject to carbon costs under current regulations unless changes are made.
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TransAlta Activities
Reducing the environmental impact of our activities has a benefit not only to our operations and financial results, but to the communities in which we operate. We expect that increased scrutiny will continue to be placed on environmental emissions and compliance. We, therefore, take a proactive approach to minimizing risks to our results. Our Board provides oversight to our environmental management programs and emission reduction initiatives in order to ensure continued compliance with environmental regulations.
Our environmental management programs include the elements summarized below:
Environmental Management Systems
All our facilities have Environmental Management Systems (“EMS”) in place, the majority of which closely align with the internationally recognized ISO 14001 EMS standard. We have operated our facilities in line with ISO 14001 for over 20 years, and our systems and knowledge of management systems are therefore mature. Only two facilities do not have ISO 14001 aligned EMS in place, although these facilities do have a comparable EMS in place. This is due to commercial arrangements (TransAlta is not the operator of those two sites). Aligning with ISO 14001 provides assurance that our systems are designed to continuously improve performance.
Renewable Power
We continue to invest in and build renewable power resources. In 2020, we completed the purchase of a 49 per cent stake in the Skookumchuck wind facility in Washington State, which has a capacity of 137 MW. We also completed the development of an innovative 10 MW utility-scale battery storage project in Alberta, WindCharger, with support from Emissions Reduction Alberta. The battery storage project is the first of its kind in Alberta and is located at our Summerview 2 wind facility in southern Alberta.
In 2019, we brought into service two wind facilities located in the US totalling 119 MW. We are presently constructing an additional 207 MW of wind generation in Alberta. See "General Development of the Business – Three-Year History - Generation and Business Development."
We believe that a larger renewable portfolio provides increased flexibility in generation and creates incremental environmental value through environmental attributes (RECs or through emission offsets). In addition, we have developed policies and procedures to comply with regulatory guidance and to lessen any environmental disruption caused by our renewable power resources, which includes monitoring noise and the avian impacts at our wind generation facilities
Environmental Controls and Efficiency
We continue to make operational improvements and investments to our existing generating facilities to reduce the environmental impact of generating electricity. In 2020, we retired our Sundance 3 coal unit, which significantly reduces the environmental impacts associated with its generation. We have also converted our Sundance 6 coal unit to gas generation. We also announced our plan to discontinue coal-mining operations in Canada by Dec. 31, 2021. Effective Jan. 1, 2022, we will also discontinue firing coal in Canada with our operated assets. The combination will significantly reduce environmental impacts from air emissions, GHG emissions, water usage and land disturbance. Our planned conversions to gas and Sundance 5 repowering will reduce energy usage, GHG emissions and air emissions at the respective facilities. In addition, we acquired a 30 per cent interest in EMG International LLC. EMG has developed an innovative proprietary wastewater treatment system that provides breakthrough technological improvement in biological wastewater treatment.
Offsets Portfolio
TransAlta maintains a GHG emissions offset portfolio with a variety of instruments that can be used for compliance purposes or otherwise banked or sold. We continue to examine additional emission offset opportunities that also allow us to meet emission targets at a competitive cost. We ensure that any investments in offsets will meet certification criteria in the market in which they are to be used.
Environmental Regulations
Recent or future changes to environmental laws or regulations may materially adversely affect us. As indicated under "Risk Factors" in this AIF and within the "Governance and Risk Management" section of the Annual MD&A, many of our activities and properties are subject to environmental requirements, as well as changes in our liabilities and obligations under these requirements, which may have a material adverse effect upon our consolidated financial results, operations or performance.
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Risk Factors
Readers should consider carefully the risk factors set forth below as well as the other information contained and incorporated by reference in this AIF. For a further discussion of risk factors affecting TransAlta, please refer to "Governance and Risk Management" in the Annual MD&A, which is incorporated by reference herein.
A reference herein to a material adverse effect on the Corporation means such an effect on the Corporation or its business, financial condition, results of operations, or cash flows, as the context requires.
The operation and maintenance of our facilities involves risks that may materially and adversely affect our business.
The operation, maintenance, refurbishment, construction and expansion of power generation facilities involve risks, including breakdown or failure of equipment or processes, fuel interruption and performance below expected levels of output or efficiency. Some of our generation facilities, particularly in Alberta, were constructed many years ago and may require significant capital expenditures to maintain peak efficiency or to maintain operations. There can be no assurance that our maintenance program will be able to detect potential failures in our facilities before they occur or eliminate all adverse consequences in the event of failure. In addition, weather-related interference, work stoppages and other unforeseen problems may disrupt the operation and maintenance of our facilities and may materially adversely affect us.
We have entered into ongoing maintenance and service agreements with the manufacturers of certain critical equipment. If a manufacturer is unable or unwilling to provide satisfactory maintenance or warranty support, we may have to enter into alternative arrangements with other providers if they cannot perform the maintenance themselves. These arrangements could be more expensive to us than our current arrangements and this increased expense could have a material adverse effect on our business. If we are unable to enter into satisfactory alternative arrangements, our inability to access technical expertise or parts could have a material adverse effect on us.
While we maintain an inventory of, or otherwise make arrangements to obtain, spare parts to replace critical equipment and maintain insurance for property damage to protect against certain operating risks, these protections may not be adequate to cover lost revenues or increased expenses and penalties that could result if we were unable to operate our generation facilities at a level necessary to comply with sales contracts.
We may be subject to the risk that it is necessary to operate a facility at a capacity level beyond that which we have contracted for power in order to provide steam in fulfillment of such a contract. In such circumstances, the costs to produce the steam being sold may exceed the revenues derived therefrom.
Unexpected changes in the cost of maintenance or in the cost and durability of components for the Corporation's facilities may adversely affect its results of operations.
Unexpected increases in the Corporation's cost structure that are beyond the control of the Corporation could materially adversely impact its financial performance. Examples of such costs include, but are not limited to, unexpected increases in the cost of procuring materials and services required for maintenance activities, and unexpected replacement or repair costs associated with equipment underperformance or lower-than-anticipated durability.
Equipment failure may cause us to suffer a material adverse effect.
There is a risk of equipment failure material to our operations due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on our business. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our facilities are exposed to operational risks such as failures due to cyclic, thermal and corrosion damage in boilers, generators and turbines, and other issues that can lead to outages and increased production risk. An extended outage could have a material adverse effect on our business, financial condition or cash flow from operations.
There can be no assurance that any applicable insurance coverage would be adequate to protect our business from material adverse effect. In addition, there can be no assurance that we will be able to restore equipment or assets that have reached the end of their useful life.
The impact of COVID-19 could have an adverse impact on the Corporation's construction projects and the operation and maintenance of our assets.
The impact of COVID-19 and the associated general economic downturn on the Corporation will largely depend on the overall severity and duration of such events, which cannot currently be predicted, and that present risks including, but not limited to: more restrictive directives of government and public health authorities; reduced labour availability
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impacting our ability to continue to staff the Corporation’s operations and facilities; impacts on the Corporation’s ability to realize its growth goals; decreases in short-term and/or long-term electricity demand and lower power pricing; increased costs resulting from the Corporation’s efforts to mitigate the impact of COVID-19; deterioration of worldwide credit and financial markets that could limit the Corporation’s ability to obtain external financing to fund its operations and growth expenditures; a higher rate of losses on accounts receivables due to credit defaults; disruptions to the Corporation’s supply chain; impairments and/or writedowns of assets; and adverse impacts on the Corporation’s information technology systems and the Corporation’s internal control systems as a result of the need to increase remote work arrangements, including increased cybersecurity threats.

Responses to the COVID-19 pandemic throughout North America have driven a reduction in demand for electricity as municipal, provincial and state authorities implemented social distancing policies, and stay-at-home and/or “shelter-in-place” directives. In turn, this put downward pressure on forward electricity prices. There is currently no certainty as to when the pandemic will be brought fully under control, but public expectations generally indicate that these impacts could continue well into 2021.
Our facilities, construction projects and operations are exposed to effects of natural disasters, public health crises and other catastrophic events beyond our control and such events could result in a material adverse effect.
Our facilities, construction projects and operations are exposed to potential interruption and damage, partial or full loss, resulting from environmental disasters (e.g. floods, high winds, fires, ice storms, earthquakes and public health crises, such as pandemics and epidemics), other seismic activity, equipment failures and the like. Climate change can increase the frequency and severity of these extreme weather events. There can be no assurance that in the event of an earthquake, hurricane, tornado, tsunami, typhoon, terrorist attack, act of war or other natural, man-made or technical catastrophe, all or some parts of our generation facilities and infrastructure systems will not be disrupted. The occurrence of a significant event that disrupts the ability of our power generation assets to produce or sell power for an extended period, including events that preclude existing customers under PPAs from purchasing electricity, could have a material negative impact on our business. Our facilities, construction projects and operations could be exposed to effects of severe weather conditions, natural and man-made disasters and potentially other catastrophic events. The occurrence of such an event may not release us from performing our obligations pursuant to PPAs or other agreements with third parties. In addition, many of our generation facilities are located in remote areas which make access for repair of damage difficult. Catastrophic events, including public health crises, could result in volatility and disruption to global supply chains, disruption to global financial markets, trade and market sentiment, risks to employee health and safety, a slowdown or temporary suspension of operations in impacted locations, postponements in the initiation and/or completion of the Corporation's development or construction projects, and delays in the completion of services, any of that may result in the Corporation incurring penalties under contracts, additional costs, or the cancellation of contracts.
We could suffer lost revenues or increased expenses and penalties if we are unable to operate our generation facilities at a level necessary to comply with our PPAs.
The ability of our facilities to generate the maximum amount of power that can be sold under PPAs is an important determinant of our revenues. Under certain PPAs, if the facility is not capable of generating electricity for the required availability in a given contract year, penalty payments may be payable to the relevant purchaser by us. The payment of any such penalties could adversely affect our revenues and profitability.
We are dependent on access to parts and equipment from certain key suppliers and we may be adversely affected if these relationships are not maintained.
Our ability to compete and expand will be dependent on having access, at a reasonable cost, to equipment, parts and components that are technologically and economically competitive with those used by our competitors. Although we have individual framework agreements with various suppliers, there can be no assurance that these relationships with suppliers will be maintained. If they are not maintained, our ability to compete may be impaired due to lack of access to these sources of equipment, parts or components.
We depend on certain joint venture, strategic and other partners that may have interests or objectives which conflict with our objectives and such differences could have a negative
impact on us.
We have entered into various arrangements with communities or joint venture, strategic or other partners in connection with the operation of our facilities and assets. Certain of these partners may have or develop interests or objectives that are different from, or in conflict with, our objectives. Any such differences could have a negative impact
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on the Corporation's ability to realize upon the anticipated benefits of, or the anticipated increase in the value of facilities or assets subject to, these arrangements. We are sometimes required through the permitting and approval process to notify and consult with various stakeholder groups, including landowners, First Nations and municipalities. Any unforeseen delays in this process may negatively impact our ability to complete any given facility on time or at all and could result in write-offs or give rise to reputational harm.
Dam and dyke failures may result in lost generating capacity, increased maintenance and repair costs and other liabilities.
A natural or man-made disaster, and certain other events, including natural or induced seismic activity, could potentially cause dam failures at our hydroelectric facilities. The occurrence of dam or dyke failures at any of our hydroelectric or coal facilities could result in a loss of generating capacity, damage to the environment or damages and harm to third parties or the public, and such failures could require us to incur significant expenditures of capital and other resources or expose us to significant liabilities for damages. There can be no assurance that our dam safety program will be able to detect potential dam failures prior to occurrence or eliminate all adverse consequences in the event of failure. Other safety regulations could change from time to time, potentially impacting our costs and operations. Reinforcing all dams or dykes to enable them to withstand more severe events could require us to incur significant expenditures of capital and other resources. The consequences of dam or dyke failures could have a material adverse effect on us.
The power generation industry has certain inherent risks related to worker health and safety and the environment that could cause us to suffer unanticipated expenditures or to incur fines, penalties or other consequences material to its business and operations.
The ownership and operation of our power generation assets carry an inherent risk of liability related to worker health and safety and the environment, including the risk of government-imposed orders to remedy unsafe conditions and/or to remediate or otherwise address environmental contamination, potential penalties for contravention of health, safety and environmental laws, licenses, permits and other approvals, and potential civil liability. Compliance with (and any future changes to) health, safety and environmental laws and the requirements of licenses, permits and other approvals are expected to remain material to our business. The occurrence of any of these events or any changes, additions to, or more rigorous enforcement of, health, safety and environmental laws, licenses, permits or other approvals could have a significant impact on our operations and/or result in additional material expenditures. As a consequence, no assurances can be given that additional environmental and workers' health and safety issues relating to presently known or unknown matters will not require unanticipated expenditures, or result in fines, penalties or other consequences (including changes to operations) material to our business and operations.
Climate change and other variations in weather can affect demand for electricity and our ability to generate electricity.
Due to the nature of our business, our earnings are sensitive to weather variations from period to period. Variations in winter weather affect the demand for electrical heating requirements. Variations in summer weather affect the demand for electrical cooling requirements. These variations in demand translate into spot market price volatility. Variations in precipitation also affect water supplies, which in turn affect our hydroelectric assets. Also, variations in sunlight conditions can have an effect on energy production levels from our solar facility. Variations in weather may be impacted by climate change resulting in sustained higher temperatures and rising sea levels that could have an impact on our generating assets. In Western Australia and other operating locations, temperatures could periodically exceed certain operating and safety thresholds, which could make it difficult for the Corporation to continue to generate electricity for such periods, and such circumstances could pose threats to the Corporation's equipment and personnel.
Ice can accumulate on wind turbine blades in the winter months. The accumulation of ice on wind turbine blades depends on a number of factors, including temperature, and ambient humidity. The accumulation of ice on wind turbine blades can have a significant impact on energy yields, and could result in the wind turbine experiencing more down time. Extreme cold temperatures can also impact the ability of wind turbines to operate effectively and this could result in more downtime and reduced production.
In addition, climate change could result in increased variability to our water and wind resources.
Many of our activities and properties are subject to environmental requirements and changes in, or liabilities under these requirements, may materially adversely affect our business.
Our operations are subject to federal, provincial, state and local environmental laws, regulations and guidelines, relating to the generation and transmission of electrical and thermal energy and surface mining, pertaining to pollution and protection of the environment, health and safety, and governing, among other things, air emissions, water usage and discharges, storage, treatment and disposal of waste and other materials and remediation of sites and land use
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responsibility (collectively, "environmental regulations"). These laws can impose liability and obligations for costs to investigate and remediate contamination without regard to fault and under certain circumstances liability may be joint and several, resulting in one responsible party being held responsible for the entire obligation. Environmental regulation can also impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transport, treatment and disposal of hazardous substances and waste and can impose clean-up, disclosure or other responsibilities with respect to spills, releases and emissions of various substances to the environment. Environmental regulation can also require that facilities and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, there is an increasing level of environmental regulation regarding the use, treatment and discharge of water and we anticipate the adoption of new or additional emission regulations at a national level in Canada, the US and Australia, which may impose different compliance requirements or standards on our business. These various compliance standards may result in additional costs for our business or may impact our ability to operate our facilities.
To comply with environmental regulations, we must incur material capital and operating expenditures relating to environmental monitoring, emissions and effluent control equipment and processes; emissions measurement, verification and reporting; emissions fees; and other compliance activities or obligations. We expect to continue to have environmental expenditures in the future. Stricter standards, new or greater regulation, increased enforcement by regulatory authorities, more extensive permitting requirements, an increase in the number and types of assets operated by the Corporation subject to environmental regulation and the implementation of provincial, state and national GHG emissions, mercury emissions or other air emissions regulation that in themselves may not be aligned and may impose varying obligations on us in the jurisdictions in which we operate and which could increase the amount of our expenditures. To the extent these expenditures cannot be passed through to our customers under our PPAs or otherwise, our costs could be material. In addition, compliance with environmental regulation might result in restrictions on some of our operations. If we do not comply with environmental regulation, regulatory agencies could seek to impose statutory, administrative and/or criminal liabilities on us, curtail our operations, or require significant expenditures on compliance, new equipment or technology, reporting obligations and research and development.
In addition to environmental regulations, we could also face civil liability in the event that private parties seek to impose liability on us for property damage, personal injury or other costs and losses. We cannot guarantee that lawsuits or administrative or investigative actions will not be commenced against us and otherwise affect our operations and assets. If an action is filed against us or may otherwise affect our operations and assets, we could be required to make substantial expenditures to defend against or evidence our activities or to bring our Corporation, our operations and assets into compliance, which could have a material adverse effect on our business.
A number of recent federal, provincial, state and local regulatory efforts continue to focus on potential climate change or GHG emissions regulation, and mandatory GHG reporting requirements are in effect in both Canada and the US. Mandatory GHG emissions reductions requirements are expected to impose increased costs on our business, as is expected to be the case generally for thermal power producers in North America. We are subject to other air quality regulations, including mercury regulations. To the extent new or additional GHG, mercury or other air emission regulations may require us to incur costs that cannot be passed through to our customers under our PPA, the costs could be material and have a material adverse effect on our business. In terms of TransAlta's existing gas-fired facilities, we currently have change-in-law provisions allowing flow-through of carbon tax-related costs, and we expect that any new contracts will contain similar provisions.
Our surface mining operations are subject to laws and regulations establishing mining, environmental protection and reclamation standards for all aspects of surface mining. The estimated reclamation costs applicable to the Corporation's operations may be inaccurate and could require greater financial resources than currently anticipated. As a mine owner or operator, we must obtain permits from the applicable regulatory body providing for the authorization of certain mining operations that result in a disturbance of the surface. These requirements seek to limit the adverse impacts of coal mining and more restrictive requirements may be adopted from time to time. As a mine owner or operator, we may also be required to submit a bond or otherwise secure payment of certain long-term obligations including mine closure or reclamation costs. Surety bond costs have increased in recent years and the market terms of such bonds have generally become more unfavourable. In addition, the number of companies willing to issue surety bonds has decreased. We could be required to self-fund these obligations should we be unable to renew or secure the required surety bonds for our mining operations or if it becomes more economical to do so.
The laws and regulations in the various markets in which we operate are subject to change, which may materially adversely affect us.
Most of the markets in which we operate and intend to operate are subject to significant regulatory oversight and control. We are not able to predict whether there will be any further changes in the regulatory environment, including potential carbon and other environmental regulations, changes in market structure or market design, or changes in other laws and regulations. Existing market rules, regulations and reliability standards are often dynamic and may be
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revised or re-interpreted and new laws and regulations may be adopted or become applicable to us or our facilities, which could have a material adverse effect on us.
We manage these risks systematically through a regulatory and compliance program designed to reduce any potential negative impact on us. However, we cannot guarantee that we will be able to adapt our business in a timely manner in response to any changes in the regulatory regimes in which we operate, and such failure to adapt could have a material adverse effect on our business.
Regulatory authorities may also from time to time audit or investigate our activities in the markets in which we operate or pursue trading. Such audits or investigations may result in sanctions or penalties that may materially affect our future activities, reputation or financial status.
Our facilities are also subject to various licensing and permitting requirements in the jurisdictions in which we operate. Many of these licenses and permits need to be renewed from time to time. If we are unsuccessful in obtaining or renewing such licenses or permits, or the terms of such licenses or permits are changed in a manner that is adverse to our business, we could be materially adversely affected.
Any changes in the rules and regulations of provincial or state public utility commissions or other regulatory bodies in the other markets in which we compete, or may compete in the future, may materially adversely affect us.
We may be adversely affected if our supply of water is materially reduced.
Hydroelectric, natural gas and coal-fired facilities require continuous water flow for their operation. Shifts in weather or climate patterns, seasonable precipitation, the timing and rate of melting, run-off, and other factors beyond our control, may reduce the water flow to our facilities. Any material reduction in the water flow to our facilities would limit our ability to produce and market electricity from these facilities and could have a material adverse effect on us. There is an increasing level of regulation respecting the use, treatment and discharge of water, and respecting the licensing of water rights in jurisdictions where we operate. Any such change in regulations could have a material adverse effect on us.
Variation in wind levels may negatively impact the amount of electricity generated at our wind facilities.
Given that wind is naturally variable, the level of electricity produced from our wind facilities is also variable. In addition, the strength and consistency of the wind resource at our wind facilities may vary from what we anticipate due to a number of factors, including the extent to which our site-specific historic wind data and wind forecasts accurately reflect actual long-term wind speeds, strength and consistency, the potential impact of climatic factors, the accuracy of our assumptions relating to, among other things, weather, icing, degradation, site access, wake and wind shear line losses and wind shear, and the potential impact of topographical variations.
A reduced amount of wind at the location of one or more of our wind facilities over an extended period may reduce the production from such facilities, as well as any environmental attributes that accrue to us related to that production and reduce our revenues and profitability.
Availability or disruption of fuel supply to our thermal plants could have an adverse impact on the operation of our facilities and our financial condition.
Our thermal facilities are reliant on having adequate natural gas and coal available to run the facilities reliably and at full capacity. As a result, we face the risk of not having adequate fuel supplies available due to insufficient natural gas transportation service, disruptions in fuel supplies due to weather, strikes, lock-outs, or breakdowns of equipment, or timing of receiving regulatory approvals. As well, the coal used to fuel the Centralia Thermal facility is sourced from the Powder River Basin in Montana and Wyoming through contracts to purchase and transport such coal to our Centralia Thermal facility. The loss of our suppliers or inability to receive coal at Centralia under our existing coal contracts at sufficient quantities, or at all, could also significantly affect our ability to serve our customers and have an adverse impact on our financial condition and results of operations. We could face the risk of adequate supply service due to our reliance on the Pioneer Pipeline as a significant provider of natural gas for our Sundance and Keephills units.
Our facilities rely on national and regional transmission systems and related facilities that are owned and operated by third parties and have both regulatory and physical constraints that could impede access to electricity markets.
Our power generation facilities depend on electric transmission systems and related facilities owned and operated primarily by third parties to deliver the electricity that we generate to delivery points where ownership changes and we are paid. These grids operate with both regulatory and physical constraints that in certain circumstances may impede access to electricity markets. There may be instances in system emergencies in which our power generation facilities are
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physically disconnected from the power grid, or our production curtailed for periods of time. Most of our electricity sales contracts do not provide for payments to be made if electricity is not delivered.
Our power generation facilities may also be subject to changes in regulations governing the cost and characteristics of use of the transmission and distribution systems to which our power generation facilities are connected. Our power generation facilities in the future may not be able to secure access to this interconnection or transmission capacity at reasonable prices, in a timely fashion or at all, which could then cause delays and additional costs in attempting to negotiate or renegotiate PPAs or to construct new projects. In addition, we may not benefit from preferential arrangements in the future. Any such increased costs and delays could delay the commercial operation dates of any new projects and negatively impact our revenues and financial condition.
Cyberattacks may cause disruptions to our operations and could have a material adverse effect on our business.
We rely on our information technology to process, transmit and store electronic information and data used for the safe operation of our assets. In today's continuously evolving cybersecurity threat landscape, any attacks or breaches of network or information systems may cause disruptions to our business operations or compromise proprietary, confidential or personal information of the Corporation, its customers, partners or others with whom the Corporation has dealings. Cyberattackers may use a range of techniques, from exploiting vulnerabilities within our user-base (social engineering attacks), to using sophisticated malicious code on a single or distributed basis to try to breach our network security controls. Attackers may also use a combination of techniques in their attempt to evade safeguards such as firewalls, intrusion prevention systems and antivirus software that exist on our network infrastructure systems. A successful cyberattack may allow for the unauthorized interception, destruction, use or dissemination of proprietary, confidential or personal information and may cause disruptions to our operations.
We continuously take measures to secure our infrastructure against potential cyberattacks that may damage our infrastructure, systems and data. Our cybersecurity program aligns with industry best practices to ensure that a holistic approach to security is maintained. We have implemented security controls to help secure our data and business operations including access control measures, intrusion detection and prevention systems, logging and monitoring of network activities, and implementing policies and procedures to ensure the secure operations of the business. We also purchase a cyber insurance policy and have established security awareness programs to help educate our users on cybersecurity risks and their responsibilities in helping protect the business.
While we have cyber insurance, as well as, systems, policies, procedures, practices, hardware, software applications, and data backups designed to prevent or limit the effect of security breaches of our network and infrastructure, there can be no assurance that these measures will be sufficient and that such security breaches will not occur or, if they do occur, that they will always be adequately addressed in a timely manner.
Our communications and monitoring technology and operating systems may experience interruptions or breaches in security which could subject us to increased operating costs and other liabilities.
We rely on technology, mainly on computer, telephone, satellite, cellular and related networks and infrastructure, to conduct our business and monitor the production of our generation facilities. These systems and infrastructure could be vulnerable to unforeseen problems including, but not limited to, cyberattacks, breaches, vandalism and theft. Our operations are dependent upon our ability to protect our information and operating technology against damage from fire, power loss, telecommunications failure or a similar catastrophic event. While we have dedicated resources for maintaining appropriate levels of cybersecurity and we use third-party technology to help protect us against security breaches and cyber incidents, our measures may not be effective and our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such security breaches and cyber incidents or other disruptions could jeopardize the security of information stored in and transmitted through our systems and network infrastructure, and could result in significant setbacks and potential liabilities, and deter future customers. Additionally, we must be able to protect our generation facility infrastructure against physical damage and service disruption from any of a variety of causes.
Any damage or failure that causes an interruption in operations could have an adverse effect on our customers. While we have systems, policies, hardware, practices and procedures designed to prevent or limit the effect of failure or interruptions of our generation facilities and infrastructure, there can be no assurance that these measures will be sufficient and that any such failures or interruptions will not occur or, if they do occur, that they will be adequately addressed in a timely manner.
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We operate in a highly competitive environment and may not be able to compete successfully.
We operate in a number of Canadian provinces, as well as in the United States and Australia. These areas of operation are affected by competition ranging from large utilities to small independent power producers, as well as private equity, international conglomerates, traditional energy companies and technology firms. In addition, potential customers may look to deploy their own capital to self-supply their own electricity needs. Some competitors have significantly greater financial and other resources than we do. Such competition could have a material adverse effect on our business. Emerging technology affecting the demand, generation, distribution or storage of electricity may also significantly impact our business and ability to compete.
Changes in the price of electricity and availability of fuel supplies required to generate electricity may materially adversely affect our business.
A significant portion of our revenues are tied, either directly or indirectly, to the market price for electricity in the markets in which we operate. Market electricity prices are impacted by a number of factors, including the strength of the economy, the available transmission capacity, the price of fuel that is used to generate electricity (and, accordingly, certain of the factors that affect the price of fuel described below); the management of generation and the amount of excess generating capacity relative to load in a particular market, the cost of controlling emissions of pollution, including potentially the cost of carbon, the structure of the particular market, increased adoption of energy-efficiency and conservation initiatives, and weather conditions that impact electrical load. As a result, we cannot accurately predict future electricity prices and electricity price volatility could have a material adverse effect on us.
We buy natural gas and a portion of our coal to supply the fuel needed to generate electricity. We could be materially adversely affected if the cost of fuel that we must buy to generate electricity increases to a greater degree than the price that we can obtain for the electricity that we sell. Several factors affect the price of fuel, many of which are beyond our control, including:
▪prevailing market prices for fuel;
▪global demand for energy products;
▪the cost of carbon and other environmental concerns;
▪weather-related disruptions affecting the ability to deliver fuels or near term demand for fuels;
▪increases in the supply of energy products in the wholesale power markets;
▪the extent of fuel transportation capacity or cost of fuel transportation service into our markets; and
▪the cost of mining or extraction that, in turn, depends on various factors such as labour market pressures, equipment replacement costs and permitting.
Changes in any of these factors may increase our cost of producing power or decrease the amount of revenue received from the sale of power, which could have a material adverse effect on us.
Changes in general economic and market conditions may have a material adverse effect on us.
Adverse changes in general economic and market conditions and, more specifically, in the markets in which we operate, could negatively impact demand for electricity, revenue, operating costs, timing and extent of capital expenditures, the net recoverable value of plant, property and equipment, results of financing efforts, or credit risk and counterparty risk, which could cause us to suffer a material adverse effect.
We may be unsuccessful in legal actions.
We are occasionally named as a defendant in claims and legal actions and as a party in commercial disputes that are resolved by arbitration or other legal proceedings. We may also bring legal actions against third parties as part of a commercial dispute through an arbitration or other legal proceeding. There can be no assurance that we will be successful in any such claim or defense or that any claim or legal action that is decided adverse to us will not materially and adversely affect us. See "Legal Proceedings and Regulatory Actions."
Risks relating to TransAlta's development and growth projects and acquisitions may materially and adversely affect us.
Development and growth projects and acquisitions that we undertake may be subject to execution and capital cost risks, including, but not limited to, risks relating to regulatory approvals, third-party opposition, cost escalations, construction delays, shortages of raw materials or skilled labour and capital constraints. The occurrences of these risks could have a material and adverse impact on us, our financial condition, results of operations and cash flows.
Expansion of our business through development projects and acquisitions may place increased demands on our management, operating systems, internal controls and financial and physical resources. In addition, the process of integrating acquired businesses or development projects may involve unforeseen difficulties. Failure to successfully
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manage or integrate any acquired businesses or development projects could have a material adverse impact on us, our financial condition, results of operations and cash flows. Further, we cannot make assurances that we will be successful in integrating any acquisition or that the commercial opportunities or operational synergies of any acquisition will be realized as expected.
We may pursue acquisitions in new markets that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide for the same type of legal certainty and rights, in connection with our contractual relationships in such countries, as are afforded to us currently, which may adversely affect our ability to receive revenues or enforce our rights in connection with any such foreign operations. In addition, the laws and regulations of some countries may limit our ability to hold a majority interest in some of the projects that we may acquire, thus limiting our ability to control the operation of such projects. Any existing or new operations may also be subject to significant political, economic and financial risks, which vary by country, and may include: (a) changes in government policies or personnel; (b) changes in general economic conditions; (c) restrictions on currency transfer or convertibility; (d) changes in labour relations; (e) political instability and civil unrest; (f) regulatory or other changes in the local electricity market; and (g) breach or repudiation of important contractual undertakings by governmental entities and expropriation and confiscation of assets and facilities for less than fair market value.
With respect to acquisitions, we cannot make assurances that we will identify suitable transactions or that we will have access to sufficient resources, through our credit facilities, the capital markets or otherwise, to pursue and complete any identified acquisition opportunities on a timely basis and at a reasonable cost. Any acquisition that we propose or complete would be subject to normal commercial risks that the transaction may not be completed on the terms negotiated, on time, or at all. An unavoidable level of risk remains regarding potential undisclosed or unknown liabilities relating to any acquisition. The existence of such undisclosed liabilities may have a material adverse impact on our business, financial condition, results of operations and cash flows.
We may have difficulty raising needed capital in the future, which could significantly harm
our business.
To the extent that our sources of cash and cash flow from operations are insufficient to fund our activities, we may need to raise additional funds. Additional financing may not be available when needed, and if such financing is available, it may not be available on terms that are favourable to our business.
Recovery of the capital investment in power projects generally occurs over a long period of time. As a result, we must obtain funds from equity or debt financings, including tax equity transactions, or from government grants, to help finance the acquisition of projects and to help pay the general and administrative costs of operating our business. Our ability to arrange financing, either at the corporate level or at the subsidiary level (including non-recourse project debt), and the costs of such capital are dependent on numerous factors, including: (a) general economic and capital market conditions; (b) credit availability from banks and other financial institutions; (c) investor confidence and the markets in which we conduct operations; (d) our financial performance and/or the expected financial performance of certain assets; (e) our level of indebtedness and compliance with covenants in our debt agreements; and (f) our cash flow.
An increase in interest rates or a reduction in the availability of project debt financing could reduce the number of projects that we are able to finance. If we are unable to raise additional funds when needed, we could be required to delay acquisition and construction of growth projects (including the conversion to gas), reduce the scope of projects, abandon or sell some or all of our projects or generation facilities, or default on our contractual commitments in the future, any of which could adversely affect our business, financial condition and results of operations.
TransAlta Corporation's debt securities will be structurally subordinated to any debt of our subsidiaries that are currently outstanding or may be incurred in the future.
We operate our business through, and a majority of our assets are held by, our subsidiaries, including partnerships. Our results of operations and ability to service indebtedness are dependent upon the results of operations of our subsidiaries, including TransAlta Renewables, and the payment of funds by these subsidiaries to TransAlta in the form of loans, dividends or otherwise. Our subsidiaries may be restricted in their ability to pay amounts due, or make any funds available for payment of, debt securities issued by TransAlta, whether by dividends, interests, loans, advances or other payments. In addition, the payment of dividends and the making of loans, advances and other payments to us by our subsidiaries may be subject to statutory or contractual restrictions.
In the event of the liquidation of any subsidiary, the assets of the subsidiary would be used first to repay the indebtedness of the subsidiary, including trade payables or obligations under any guarantees,before being used to pay TransAlta's indebtedness, including any debt securities issued by TransAlta. Such indebtedness and any other future indebtedness of such subsidiaries would be structurally senior for such subsidiary to any debt securities issued by TransAlta.
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Our subsidiaries have financed some investments using non-recourse project financing. Each non-recourse project loan is structured to be repaid out of cash flow provided by the investment. In the event of a default under a financing agreement that is not cured, the lenders would generally have rights to the related assets. In the event of foreclosure after a default, our subsidiary may lose its equity in the asset or may not be entitled to any cash that the asset may generate. Although a default under a project loan will not cause a default with respect to any debt securities issued by TransAlta, it may materially affect our ability to service our outstanding indebtedness.
A downgrade of our credit ratings could materially and adversely affect us.
Rating agencies regularly evaluate us, basing their ratings of our long-term and short-term debt, along with our issuer rating on a number of factors. There can be no assurance that one or more of our credit ratings and the corresponding outlook will not be changed. Our borrowing costs and ability to raise funds are directly impacted by our credit ratings. Credit ratings may be important to suppliers or counterparties when they seek to engage in certain transactions with us. A credit rating downgrade could potentially impair our ability to enter into arrangements with suppliers or counterparties, to engage in certain transactions, and could limit our access to private and public credit markets and increase the costs of borrowing under our existing credit facilities. For further information on posting collateral, please see Note 16(F) of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Changes in opinions of our Corporation from external parties may have a material adverse effect on us.
Reputation risk relates to the risk associated with our business because of changes in opinion from the general public, private stakeholders, governments, financiers and other entities. Our reputation is one of our most valued assets. The potential for harming our reputation exists in every business decision and all risks can have an impact on reputation, which in turn can negatively impact our business and securities. Reputational risk cannot be managed in isolation from other forms of risk. Negative impacts from a compromised reputation could include revenue loss, reduction in customer base, and decreased value of our securities.
We may fail to meet financial expectations.
Our quarterly revenue, earnings, cash flows and results of operations are difficult to predict and fluctuate from quarter to quarter. Our quarterly results of operations are influenced by a number of factors, including the risks described in this AIF, many of which are outside of our control, which may cause such results to fall below market expectations. Although we base our planned operating expenses in part on our expectations of future revenue, a significant portion of our expenses are relatively fixed in the short-term. If revenue for a particular quarter is lower than expected, we likely will be unable to proportionately reduce our operating expenses for that quarter, which will adversely affect our results of operations for that quarter.
Our cash dividend payments are not guaranteed.
The payment of dividends is not guaranteed and could fluctuate. The Board has the discretion to determine the amount and timing of any dividends to be declared and paid to our shareholders. In addition, the payment of dividends on common shares is, in all cases, subject to prior satisfaction of preferential dividends applicable to each series of our first preferred shares. We may alter our dividend policy at any time.The Board's determination to declare dividends will depend on, among other things, results of operations; financial condition; current and expected future levels of earnings; operating cash flow; liquidity requirements; market opportunities; income taxes; maintenance and growth capital expenditures; debt repayments; legal, regulatory and contractual constraints; working capital requirements; tax laws and other relevant factors. Our short- and long-term borrowings may prohibit us from paying dividends at any time at which a default or event of default would exist under such debt, or if a default or event of default would exist as a result of paying the dividend.
Over time, our capital and other cash needs may change significantly from our current needs, which could affect whether we pay dividends and the amount of any dividends we may pay in the future. If we continue to pay dividends at the current level, we may not retain a sufficient amount of cash to finance growth opportunities, meet any large unanticipated liquidity requirements or fund our operations in the event of a significant business downturn. The Board, subject to the requirements of our bylaws and other governance documents, may amend, revoke or suspend our dividend policy at any time. A decline in the market price or liquidity, or both, of our common shares could result if the Board establishes large reserves that reduce the amount of quarterly dividends paid or if we reduce or eliminate the payment of dividends.
We are dependent on the operations of our facilities for our cash availability. The actual amount of cash available for dividends to holders of our common shares will depend upon numerous factors relating to each of our generation facilities including: operating performance of our generation facilities, profitability, changes in gross margin, fluctuations
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in working capital, capital expenditure levels, applicable laws, compliance with contracts and contractual restrictions contained in the instruments governing any indebtedness. Any reduction in the amount of cash available for distribution from our generation facilities will reduce the amount of cash available to pay dividends to holders of our common shares.
The market price for our common shares may be volatile.
The market price for our common shares may be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond our control, including: (a) actual or anticipated fluctuations in our results of operations; (b) recommendations by securities research analysts; (c) changes in the economic performance or market valuations of other companies that investors deem comparable; (d) the loss or resignation of executive officers and other key personnel; (e) sales or perceived sales of additional common shares; (f) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by or involving us or our competitors; and (g) trends, concerns, technological or competitive developments, regulatory changes and other related issues in the power generation industry or our target markets.
Financial markets have experienced significant price and volume fluctuations in recent years that have particularly affected the market prices of equity securities of companies and such fluctuations have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of our common shares may decline even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values that may result in impairment losses. Certain institutional investors may base their investment decisions on consideration of our environmental, governance and social practices and performance against such institutions' respective investment guidelines and criteria, and failure to meet such criteria may result in a limited or no investment in our common shares by those institutions, which could adversely affect the trading price of our common shares.
Our revenues may be reduced upon expiration or termination of PPAs.
We sell power under PPAs that expire at various times. In addition, these PPAs may be subject to termination in certain circumstances, including default by the facility or plant owner or operator. When a PPA expires or is terminated, it could result in us having less stable cash flows and it is possible that the price received by the relevant facility or plant for power under subsequent selling arrangements may be reduced significantly. It is also possible that to the extent a PPA is negotiated after the initial PPAs have run their course, the new contract may not be available at prices that permit the continued operation of the affected facility or plant on a profitable basis. If this occurs, the affected facility or plant may be forced to permanently cease operations.
If Mangrove is successful in its claim to set aside the Brookfield Investment, it could have a material adverse effect on our business.
If Mangrove is successful in its claim against the Corporation to have the Brookfield transaction set aside, this could have a material adverse effect on the Corporation, including its ability to continue to return capital through share buybacks, meet certain financial obligations, continue to advance its conversion to gas strategy and execute on other growth opportunities and strategic plans. The Corporation would likely need to raise additional cash or working capital through the public or private sale of debt or equity securities, sale of assets, funding from joint-venture or strategic partners, debt financing or short-term loans, and the terms of such transactions may be unduly expensive or burdensome to the Corporation relative to the terms of the Brookfield Investment and disadvantageous to our existing shareholders. There can be no assurance that the Corporation would be successful in securing alternative sources of capital.
Trading risks may have a material adverse effect on our business.
Our trading and marketing business frequently involves establishing trading positions in the wholesale energy markets on both a medium-term and short-term basis and on both an asset and proprietary basis. To the extent that we have long positions in the energy markets, a downturn in market prices will result in losses from a decline in the value of such long positions. Conversely, to the extent that we enter into forward sales contracts to deliver energy that we do not own, or take short positions in the energy markets, an upturn in market prices will expose us to losses as we attempt to cover any short positions by acquiring energy in a rising market.
In addition, from time to time, we may have a trading strategy consisting of simultaneously holding a long position and a short position, from which we expect to earn a profit based on changes in the relative value of the two positions. If, however, the relative value of the two positions changes in a direction or manner that we did not anticipate, we would realize losses from such a paired position.
If the strategy that we use to hedge our exposures to these various risks is not effective, we could incur significant losses. Our trading positions can be impacted by volatility in the energy markets that, in turn, depend on various factors,
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including weather in various geographical areas and short-term supply and demand imbalances, which cannot be predicted with any certainty. A shift in the energy markets could adversely affect our positions, which could also have a material adverse effect on our business.
We use a number of risk management controls conducted by our independent Risk Management group in order to limit our exposure to risks arising from our trading activities. These controls include risk capital limits, Value at Risk, Gross Margin at Risk, tail risk scenarios, position limits, concentration limits, credit limits, and approved product controls. We cannot guarantee that losses will not occur and such losses may be outside the parameters of our risk controls.
Certain of the contracts to which we are a party require that we provide collateral against our obligations.
We are exposed to risk under certain financial derivative contracts and electricity and natural gas purchase and sale contracts entered into for the purposes of hedging and proprietary trading. The terms and conditions of these contracts require us to provide collateral when the fair value of these contracts is in excess of any credit limits granted by our counterparties and the contract obliges that we provide the collateral. The change in fair value of these contracts occurs due to changes in commodity prices. These contracts include: (a) financial derivative contracts when forward commodity prices are more or less than contracted prices, depending on the transactions; (b) purchase agreements, when forward commodity prices are less than contracted prices; and (c) sales agreements, when forward commodity prices exceed contracted prices. Downgrades in our creditworthiness by certain credit rating agencies may decrease the credit limits granted by our counterparties and, accordingly, increase the amount of collateral that we may have to provide, which could materially adversely affect us.
If counterparties to our contracts are unable to meet their obligations, we may be materially and adversely affected.
If purchasers of our electricity and steam or other contractual counterparties default on their obligations, we may be materially and adversely affected. While we have procedures and controls in place to manage our counterparty credit risk before entering into contracts, all contracts inherently contain default risk. Moreover, while we seek to monitor trading activities to ensure that the credit limits for counterparties are not exceeded, we cannot guarantee that a party will not default. If counterparties to our contracts are unable to meet their obligations, we could suffer a reduction in revenue that could have a material adverse effect on our business.
Because of our multinational operations, we are subject to currency rate risk and regulatory and political risk.
We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the cash flows from those operations, the acquisition of equipment and services from foreign suppliers, and our US-dollar denominated debt. Our exposures are primarily to the US and Australian currencies, and changes in the values of these currencies relative to the Canadian dollar could negatively impact our operating cash flows or the value of our foreign investments. While we attempt to manage this risk by using hedging instruments, including cross-currency interest rate swaps, forward exchange contracts and matching revenues and expenses by currency at the Corporate level, there can be no assurance that these risk management efforts will be effective, and fluctuations in these exchange rates may have a material adverse effect on our business.
In addition to currency rate risk, our foreign operations may be subject to regulatory and political risk. Any change to the regulations governing power generation or the political climate in the countries where we have operations could impose additional costs and have a material adverse effect on us.
We are not able to insure against all potential risks and may become subject to higher insurance premiums.
Our business is exposed to the risks inherent in the construction and operation of electricity generation facilities, such as breakdowns, manufacturing defects, natural disasters, injury, damage to third parties, theft, terrorist attacks and sabotage. We are also exposed to environmental risks. We maintain insurance policies, covering usual and customary risks associated with our business, with creditworthy insurance carriers. Our insurance policies, however, may not cover losses, or may be subject to limitations in coverage as a result of force majeure, natural disasters, terrorist or cyberattacks or sabotage, among other perils. In addition, we generally do not maintain insurance for certain environmental risks, such as environmental contamination. Our insurance policies are subject to annual review by the respective insurers and may not be renewed at all or on similar or favourable terms. A significant uninsured loss or a loss significantly exceeding the limits of our insurance policies or the failure to renew such insurance policies on similar or favourable terms could have a material adverse effect on our business, financial condition and results of operations.
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Our insurance coverage may not be available in the future on commercially reasonable terms or adequate insurance limits may not be available in the market. In addition, the insurance proceeds received for any loss or damage to any of our generation facilities may not be sufficient to permit us to continue to make payments on our debt.
Provision for income taxes may not be sufficient.
Our operations are complex, and the computation of the provision for income taxes involves tax interpretations, regulations, and legislation that are continually changing. In addition, our tax filings are subject to audit by taxation authorities. While we believe that our tax filings have been made in material compliance with all applicable tax interpretations, regulations, and legislation, we cannot guarantee that we will not have disagreements with taxation authorities with respect to our tax filings that could have a material adverse effect on our business.
The Corporation and its subsidiaries are subject to changing tax laws, treaties and regulations in and between countries. Various tax proposals in the countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of multinational corporations. A change in tax laws, treaties or regulations, or in the interpretation thereof, could result in a materially higher income or non-income tax expense that could have a material adverse impact on us.
We are subject to uncertainties regarding when we will become cash taxable.
Our anticipated cash tax horizon is subject to risks, uncertainties and other factors that could cause the cash tax horizon to occur sooner than currently projected. In particular, our anticipated cash tax horizon is subject to risks pertaining to changes in our operations, asset base, corporate structure or changes to tax legislation, regulations or interpretations.  In the event we become cash taxable sooner than projected, our cash available for distribution and our dividend could decrease, which could in turn have a material adverse impact on the value of our shares.
If we fail to attract and retain key personnel, we could be materially adversely affected.
The loss of any of our key personnel or our inability to attract, train, retain and motivate additional qualified management and other personnel could have a material adverse effect on our business. Competition for these personnel is intense and there can be no assurance that we will be successful in this regard.
If we are unable to successfully negotiate new collective bargaining agreements with our unionized workforce, as required from time to time, we will be adversely affected.
While we believe we have a satisfactory relationship with our unionized employees, we cannot guarantee that we will be able to successfully negotiate or renegotiate our collective bargaining agreements on terms agreeable to TransAlta.  In 2020, we successfully renegotiated two collective bargaining agreements. We expect to renegotiate three collective bargaining agreements in 2021 and expect to renegotiate four collective bargaining agreements in 2022.  Any problems in negotiating these collective bargaining agreements could lead to higher employee costs and a work stoppage or strike, which could have a material adverse effect on us.
Employees
The Corporation is required to develop and retain a skilled workforce for its operations. Many of the employees of the Corporation possess specialized skills and training and the Corporation must compete in the marketplace for these workers. As at Dec. 31, 2020, we had 1,476 active employees, which includes full-time, part-time and temporary employees, of which 486 were employed in our Alberta Thermal segment (including our SunHills Mining operation), 187 were employed in our Centralia segment, 197 were employed in our North American Gas segment, 83 were employed in our Wind and Solar business, 83 were employed in our Hydro business, 76 were employed in our Energy Marketing business and the remaining 364 employees were employed in our Corporate segment. Approximately 46 per cent of our employees are represented by labour unions. We are currently a party to 12 different collective bargaining agreements. We expect to renegotiate three collective bargaining agreements in 2021 and expect to renegotiate four collective bargaining agreements in 2022.
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Capital and Loan Structure
Our authorized share capital consists of an unlimited number of common shares and an unlimited number of first preferred shares, issuable in series. As at March 2, 2021, there were 269,883,087 common shares outstanding and 10,175,380 Series A Shares, 1,824,620 Series B Shares, 11,000,000 Series C Shares, 9,000,000 Series E Shares, 6,600,000 Series G Shares and 400,000 Series I Shares outstanding (as defined below). The Corporation does not have any escrowed securities.
Common Shares
Each common share of TransAlta Corporation entitles the holder thereof to one vote for each common share held at all meetings of shareholders of the Corporation, except meetings at which only holders of another specified class or series of shares are entitled to vote, to receive dividends if, as and when declared by the Board, subject to prior satisfaction of preferential dividends applicable to any first preferred shares, and to participate rateably in any distribution of our assets upon a liquidation, dissolution or winding up and subject to prior rights and privileges attaching to first preferred shares. The common shares are not convertible and are not entitled to any preemptive rights. The common shares are not entitled to cumulative voting.
Normal Course Issuer Bid
On May 26, 2020, the TSX accepted our notice filed to implement an NCIB for a portion of its common shares. The Board has authorized repurchases of up to a maximum of 14,000,000 common shares, representing approximately seven per cent of TransAlta's public float. Purchases under the NCIB are expected to be made through open market transactions on the TSX and any alternative Canadian trading platforms, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.
The period during which TransAlta is authorized to make purchases under the NCIB began on May 29, 2020, and ends on May 28, 2021, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Corporation’s election.
Under TSX rules, not more than 228,157 common shares (being 25 per cent of the average daily trading volume on the TSX of 912,630 common shares for the six months ended April 30, 2020) can be purchased on the TSX on any single trading day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar week.
In connection with the investment by Brookfield, the Corporation has indicated that it intends to return up to $250 million of capital to shareholders through share repurchases within three years of receiving the first tranche of the investment (which occurred on May 1, 2019).
During the year ended Dec. 31, 2020, the Corporation purchased and cancelled 7,352,600 common shares at an average price of $8.33 per common share, for a total cost of $61 million. For further information please see Note 27 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
First Preferred Shares
We are authorized to issue an unlimited number of first preferred shares, issuable in series and, with respect to each series, the Board is authorized to fix the number of shares comprising the series and determine the designation, rights, privileges, restrictions and conditions attaching to such shares, subject to certain limitations.
The first preferred shares of all series rank senior to all other shares of TransAlta Corporation with respect to priority in payment of dividends and with respect to distribution of assets in the event of liquidation, dissolution or winding up of the Corporation, or a reduction of stated capital. Holders of first preferred shares are entitled to receive cumulative quarterly dividends on the subscription price thereof as and when declared by the Board at the rate established by the Board at the time of issue of shares of a series. No dividends may be declared or paid on any other shares of TransAlta Corporation unless all cumulative dividends accrued upon all outstanding first preferred shares have been paid or declared and set apart. In the event of the liquidation, dissolution or winding up of the Corporation, or a reduction of stated capital, no sum shall be paid or assets distributed to holders of other shares of TransAlta Corporation until the holders of first preferred shares shall have been paid the subscription price of the shares, plus a sum equal to the premium payable on a redemption, plus a sum equal to the arrears of dividends accumulated on the first preferred shares to the date of such liquidation, dissolution, winding up or reduction of stated capital, as applicable. After payment of such amount, the holders of first preferred shares shall not be entitled to share further in the distribution of our assets.
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The Board may include, in the share conditions attaching to a particular series of first preferred shares, certain voting rights effective upon our failing to make payment of six quarterly dividend payments, whether or not consecutive. These voting rights continue for so long as any dividends remain in arrears. These voting rights are the right to one vote for each $25.00 of subscription price on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of TransAlta if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Subject to the share conditions attaching to any particular series providing to the contrary, we may redeem the first preferred shares of a series, in whole or from time to time in part, at the redemption price applicable to each series and we have the right to acquire any of the first preferred shares of one or more series by purchase for cancellation in the open market or by invitation for tenders at a price not to exceed the redemption price applicable to the series.
Series A Shares
Twelve million Series A Shares were issued on Dec. 10, 2010, with a coupon of 4.60 per cent, for gross proceeds of $300 million. On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares. Certain provisions of the Series A Shares are discussed below.
Dividends on Series A Shares
The holders of Series A Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series A Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares and the Series B Shares described below, and will remain unchanged over the life of the Series A Shares.
Redemption of Series A Shares
The Series A Shares were redeemable by TransAlta, at its option, in whole or in part, on March 31, 2016, and will be redeemable on March 31 in every fifth year thereafter 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 to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).
If we give notice to the holders of the Series A Shares of the redemption of all of the Series A Shares, the right of a holder of Series A Shares to convert such Series A Shares shall terminate and we shall not be required to give notice to the registered holders of the Series A Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series A Shares.
Conversion of Series A Shares into Series B Shares
The holders of the Series A Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series B of TransAlta (the "Series B Shares"), subject to certain conditions, on March 31, 2016, and will again have the right to convert on March 31 in every fifth year thereafter. The holders of the Series B Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate (which means, the average yield expressed as an annual rate on the 90-day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) on the applicable date and 2.03 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the
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dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 2.03 per cent.
The Series A Shares and Series B Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series A Shares and Series B Shares are identical in all material respects.
On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis.
Voting Rights
The holders of the Series A Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series A Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series A Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series A Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation
Modification
The provisions attaching to the Series A Shares as a class may be amended with the written approval of all the holders of Series A 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.
Series B Shares
1,824,620 Series B Shares were issued on March 31, 2016. Certain provisions of the Series B Shares are discussed below.
Dividends on Series B Shares
The holders of Series B Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, floating rate cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after conversion, the holders of Series B Shares shall be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest, (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate (which means, the average yield expressed as an annual rate on the 90-day Government of Canada treasury bill, as reported by the Bank of Canada, for the most recent treasury bills auction preceding the applicable Floating Rate Calculation Date) on the applicable date and 2.03 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 2.03 per cent. This spread will apply to both the Series A Shares described above and the Series B Shares and will remain unchanged over the life of the Series B Shares.
Redemption of Series B Shares
The Series B Shares are redeemable by TransAlta, at its option, in whole or in part, on March 31, 2021, and on March 31 in every fifth year thereafter 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 to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).
If we give notice to the holders of the Series B Shares of the redemption of all of the Series B Shares, the right of a holder of Series B Shares to convert such Series B Shares shall terminate and we shall not be required to give notice to the
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registered holders of the Series B Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series B Shares.
Conversion of Series B Shares into Series A Shares
The holders of the Series B Shares have the right to convert all or any of their shares into cumulative redeemable fixed rate first preferred shares, Series A Shares, subject to certain conditions, on March 31, 2021, and on March 31 in every fifth year thereafter. The holders of the Series A Shares will be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends payable on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 2.03 per cent.
The Series A Shares and Series B Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series A Shares and Series B Shares are identical in all material respects.
Voting Rights
The holders of the Series B Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series B Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series B Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series B Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series B Shares as a class may be amended with the written approval of all the holders of Series B 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.
Series C Shares
Eleven million cumulative redeemable rate reset first preferred shares, Series C (the "Series C Shares") were issued on Nov. 30, 2011, with a coupon of 4.60 per cent, for gross proceeds of $275 million. Certain provisions of the Series C Shares are discussed below.
Dividends on Series C Shares
The holders of Series C Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series C Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one-quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.10 per cent. This spread will apply to both the Series C Shares and the Series D Shares described below, and will remain unchanged over the life of the Series C Shares.
Redemption of Series C Shares
The Series C Shares were redeemable by TransAlta, at its option, in whole or in part, on June 30, 2017, and will be redeemable on June 30 in every fifth year thereafter by the payment of an amount in cash for each share to be
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redeemed equal to $25.00 plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold). On June 30, 2017, none of the Series C Shares were redeemed.
If we give notice to the holders of the Series C Shares of the redemption of all of the Series C Shares, the right of a holder of Series C Shares to convert such Series C Shares shall terminate and we shall not be required to give notice to the registered holders of the Series C Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series C Shares.
Conversion of Series C Shares into Series D Shares
The holders of the Series C Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series D Shares, subject to certain conditions, on June 30, 2017, and will again have the right to convert on June 30 in every fifth year thereafter. The holders of the Series D Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September, and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.10 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.10 per cent.
The Series C Shares and Series D Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series C Shares and Series D Shares are identical in all material respects.
On June 15, 2017, 827,628 Series C Shares were tendered for conversion into Series D Shares which is less than the one million shares required to give effect to conversions into Series D Shares. As a result, none of the Series C Shares were converted into Series D Shares on June 30, 2017.
Voting Rights
The holders of the Series C Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series C Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series C Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series C Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series C Shares as a class may be amended with the written approval of all the holders of Series C 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.
Series E Shares
Nine million cumulative redeemable rate reset first preferred shares, Series E Shares were issued on Aug. 10, 2012, for gross proceeds of $225 million. Certain provisions of the Series E Shares are discussed below.
Dividends on Series E Shares
The holders of Series E Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September, and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series E Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash
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dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta Corporation on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.65 per cent. This spread will apply to both the Series E Shares and the Series F Shares described below, and will remain unchanged over the life of the Series E Shares.
Redemption of Series E Shares
The Series E Shares were redeemable by TransAlta Corporation, at its option, in whole or in part, on Sep. 30, 2017, and will be redeemable on September 30 in every fifth year thereafter by the payment of an amount of $25.00 in cash for each share to be redeemed plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold). On Sep. 30, 2017, none of the Class E Shares were redeemed.
If we give notice to the holders of the Series E Shares of the redemption of all of the Series E Shares, the right of a holder of Series E Shares to convert such Series E Shares shall terminate and we shall not be required to give notice to the registered holders of the Series E Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series E Shares.
Conversion of Series E Shares into Series F Shares
The holders of the Series E Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series F Shares"), subject to certain conditions, on Sep. 30, 2017, and will again have the right to convert on September 30 in every fifth year thereafter. The holders of the Series F Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September, and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred-thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.65 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.65 per cent.
The Series E Shares and Series F Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series E Shares and Series F Shares are identical in all material respects.
On Sep. 15, 2017, 133,969 Series E Shares were tendered for conversion into Series F Shares which is less than the one million shares required to give effect to conversions into Series F Shares. As a result, none of the Series E Shares were converted into Series F Shares on Sep. 30, 2017.
Voting Rights
The holders of the Series E Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series E Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series E Shares will be entitled to receive notice of and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series E Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series E Shares as a class may be amended with the written approval of all the holders of Series E 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.
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Series G Shares
6.6 million cumulative redeemable rate reset first preferred shares, Series G Shares, were issued on Aug. 15, 2014, for gross proceeds of $165 million. Certain provisions of the Series G Shares are discussed below.
Dividends on Series G Shares
The holders of Series G Shares are entitled to receive, as and when declared by the Board out of moneys of TransAlta properly applicable to the payment of dividends, fixed cumulative preferential cash dividends payable quarterly on the last day of March, June, September and December in each year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day.
For each five-year period after the Initial Fixed Rate Period (each a "Subsequent Fixed Rate Period"), the holders of Series G Shares shall be entitled to receive, as and when declared by the Board, fixed cumulative preferential cash dividends, payable quarterly on the last day of March, June, September and December in each year, in the amount per share determined by multiplying one quarter of the Annual Fixed Dividend Rate for such Subsequent Fixed Rate Period by $25.00 (less any tax that we are required to deduct and withhold). The Annual Fixed Dividend Rate for the ensuing Subsequent Fixed Rate Period will be determined by TransAlta Corporation on the Fixed Rate Calculation Date (30th day prior to the first day of such Subsequent Fixed Rate Period) and will be equal to the sum of the Government of Canada Yield (yield to maturity of a Government of Canada non-callable five-year bond) on the Fixed Rate Calculation Date plus a spread of 3.80 per cent. This spread will apply to both the Series G Shares and the Series H Shares described below, and will remain unchanged over the life of the Series G Shares.
Redemption of Series G Shares
The Series G Shares were redeemable by TransAlta Corporation, at its option, in whole or in part, on Sep. 30, 2019, and will be redeemable on September 30 in every fifth year thereafter by the payment of an amount of $25.00 in cash for each share to be redeemed plus all accrued and unpaid dividends thereon to but excluding the date fixed for redemption (less any tax that we are required to deduct and withhold).
If we give notice to the holders of the Series G Shares of the redemption of all of the Series G Shares, the right of a holder of Series G Shares to convert such Series G Shares shall terminate and we shall not be required to give notice to the registered holders of the Series G Shares of an Annual Fixed Dividend Rate, a Floating Quarterly Dividend Rate or the conversion right of holders of Series G Shares.
Conversion of Series G Shares into Series H Shares
The holders of the Series G Shares had the right to convert all or any of their shares into cumulative redeemable floating rate first preferred shares, Series H Shares, subject to certain conditions, on Sep. 30, 2019, and will again have the right to convert on September 30 in every fifth year thereafter. The holders of the Series H Shares will be entitled to receive, as and when declared by the Board, quarterly floating rate cumulative preferential cash dividends payable on the last day of March, June, September, and December in each year (each such quarterly dividend period is referred to as a "Quarterly Floating Rate Period"), in the amount per share determined by multiplying the "Floating Quarterly Dividend Rate" (which means, for any Quarterly Floating Rate Period, the annual rate of interest (expressed as a percentage and rounded to the nearest one hundred thousandth of one per cent), equal to the sum of the T-Bill Rate on the applicable date and 3.80 per cent) for such Quarterly Floating Rate Period by $25.00 and multiplying that product by a fraction, the numerator of which is the actual number of days in such Quarterly Floating Rate Period and the denominator of which is 365 or 366, depending upon the actual number of days in the applicable year (less any tax that we are required to deduct and withhold). If any such date is not a business day, the dividend will be paid on the next succeeding business day. The Floating Quarterly Dividend Rate will be the annual rate of interest equal to the sum of the T-Bill Rate on the applicable Floating Rate Calculation Date plus a spread of 3.80 per cent.
The Series G Shares and Series H Shares are series of shares in the same class. The conversion right entitles holders to elect periodically which of the two series they wish to hold and does not entitle holders to receive a different class or type of securities. Other than the different dividend rights and redemption rights attached thereto, the Series G Shares and Series H Shares are identical in all material respects.
On Sep. 17, 2019, 140,730 Series G Shares were tendered for conversion into Series H Shares which is less than the one million shares required to give effect to conversions into Series H Shares. As a result, none of the Series G Shares were converted into Series H Shares on Sep. 30, 2019.
Voting Rights
The holders of Series G Shares are not entitled to any voting rights or to receive notice of or to attend shareholders' meetings unless dividends on the Series G Shares are in arrears to the extent of six quarterly dividends, whether or not consecutive. Until all arrears of dividends have been paid, holders of Series G Shares will be entitled to receive notice of
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and to attend all shareholders' meetings at which directors are to be elected (other than separate meetings of holders of another class or series of shares) and to one vote in respect of each Series G Share held on all matters in respect of which shareholders vote, and additionally, the right of all series of first preferred shares, voting as a combined class, to elect two directors of the Corporation if the Board then consists of less than 16 directors, or three directors if the Board consists of 16 or more directors. Otherwise, except as required by law, the holders of first preferred shares shall not be entitled to vote or to receive notice of or attend any meeting of the shareholders of the Corporation.
Modification
The provisions attaching to the Series G Shares as a class may be amended with the written approval of all the holders of Series G 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.
Series I Shares
The Series I Shares have a perpetual term and will rank pari passu to all existing series of first preferred shares of the Company with respect to dividends and liquidation preferences. The Series I Shares are entitled to a 7% cumulative dividend payable quarterly in cash.
Under the Investment Agreement with Brookfield, redemption of the Series I Shares will be satisfied through the Hydro Equity Interest (as defined below), or in some cases cash, based on their redemption price. The redemption price payable is equal to the subscription price paid by Brookfield together with all accrued but unpaid dividends thereon (the “Redemption Price”). Upon the occurrence of an Optional Redemption, as defined and described below, or a Cash Acceleration Event, as defined and described below, the Corporation will pay the Redemption Price in cash (the “Cash Redemption Amount”).
Except in the case of an Optional Redemption by the Corporation or a Cash Acceleration Event, as described below, the Series I Shares will be exchangeable into interests (the “Hydro Equity Interest”) in the equity (the “Hydro Equity”) of TA Alberta Hydro LP (the “Hydro Assets Owner”), a special purpose vehicle formed by the Corporation . At any time after Dec. 31, 2024, Brookfield will be entitled to exchange all, but not less than all, of the Series I Shares requiring the Corporation to redeem or exchange all of the Series I Shares held by Brookfield (minus the number of Series I Shares that have been redeemed pursuant to an Optional Redemption) (the “Exchange Right”).
Prior to any Optional Redemption by the Corporation, the exercise of the Exchange Right or the occurrence of an Equity Acceleration Event, as defined and described below, will entitle Brookfield to receive that percentage of a Hydro Equity Interest that is equal to the aggregate Redemption Price for all Series I Shares issued to Brookfield divided by the tax affected equity value of the Hydro Assets Owner, as further described in the Investment Agreement (the “Equity Redemption Amount”). The maximum Hydro Equity Interest issuable to Brookfield upon the exercise of the Exchange Right is 49% of the total Hydro Equity. The balance of the Redemption Price will be paid by the Corporation in cash.
If, at the time the Exchange Right is exercised, the Equity Redemption Amount is insufficient to permit Brookfield to acquire 49% of the Hydro Equity, Brookfield has a one-time top-up option, exercisable until Dec. 31, 2028, to acquire an additional amount of Hydro Equity. As long as Brookfield holds at least 8.5% of the issued and outstanding common shares, Brookfield may purchase: (a) if the 20- day volume weighted average price (“VWAP”) of the Common Shares is not less than $14, up to an additional 10% of Hydro Equity, to a maximum interest of 49% of the Hydro Equity; or (b) if the 20-day VWAP of the common shares is not less than $17, the additional percentage required that would bring Brookfield’s ownership level up to but not exceeding 49% of the Hydro Equity. If the Exchange Right is exercised and the Equity Redemption Amount is insufficient to permit Brookfield to acquire at least 25% of the Hydro Equity, Brookfield will have an option to acquire that additional percentage of Hydro Equity that would result in Brookfield having 25% of the Hydro Equity upon payment in cash. If Brookfield exercises its top-up option, the cash amount payable by Brookfield is calculated as the same price as in the case of an exchange for the Hydro Equity Interest, however, in such a case, the price is based on the equity value of the Hydro Assets Owner without any reduction for the tax deficiency value associated with certain tax pools. Exercise of this top-up option triggers a lock-up obligation of Brookfield for a further period of 18 months following its exercise.
At any time after Dec. 31, 2028, the Corporation may redeem the Series I Shares and the related debentures, in whole or in part, at the Redemption Price (the “Optional Redemption”) provided that the minimum proceeds to Brookfield for each such redemption (other than the final redemption) may not be less than $100,000,000 and further provided that all Series I Shares and related debentures must be redeemed by the Company within 36 months of the date of the first Optional Redemption.
The Investment Agreement also provides for certain acceleration events (the “Acceleration Events”). In the event of bankruptcy or a breach of a certain material covenants by the Corporation (each, an “Equity Acceleration Event”), Brookfield will be entitled to give notice and will be entitled to the Equity Redemption Amount. If an Equity Acceleration Event occurs before Dec. 31, 2024, a true-up payment will be made by Brookfield to the Corporation or by the
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Corporation to Brookfield to account for the difference between $1.95 billion and the tax-effected value of the Hydro Equity Interest calculated as of a date (to be determined by Brookfield) within the period commencing Jan. 1, 2025 and ending Dec. 31, 2027. Any difference in favour of Brookfield between the true-up value and the value of the Hydro Equity Interest issued to Brookfield is to be satisfied by delivery of additional Hydro Equity. If the Company does not obtain the requisite regulatory approvals for the exchange for Hydro Equity contemplated by the Exchange Right or the Equity Redemption Amount or a final order is made which enjoins the completion of the Exchange Right (the “Cash Acceleration Event”), then Brookfield will be entitled to the Cash Redemption Amount.
Related-Party Articles Provisions
The articles of the Corporation contain provisions restricting the ability of the Corporation to enter into a "Specified Transaction" with a "Major Shareholder." A Specified Transaction requires the approval of a majority of the votes cast by holders of voting shares of the Corporation, as well as the approval of a majority of the votes cast by holders of such voting shares, excluding any Major Shareholder. A Major Shareholder generally means the beneficial owner of more than 20 per cent of the outstanding voting shares of the Corporation. The articles contain a broad definition of beneficial ownership, and in particular, a person is considered to beneficially own shares owned by its associates and affiliates, as those terms are defined in the articles. Transactions that are considered to be Specified Transactions include the following: a merger or amalgamation of the Corporation with a Major Shareholder; the furnishing of financial assistance by the Corporation to a Major Shareholder; certain sales of assets or provision of services by the Corporation to a Major Shareholder or vice versa; certain issuances of securities by the Corporation that increase the proportionate voting interest of a Major Shareholder; a reorganization or recapitalization of the Corporation that increases the proportionate voting interest of a Major Shareholder; and the creation of a class or series of non-voting shares of the Corporation that has a residual right to participate in earnings of the Corporation and assets of the Corporation upon dissolution or winding up.
Shareholder Rights Plan
The Corporation implemented a shareholder rights plan (the "Rights Plan") pursuant to a Shareholder Rights Plan Agreement (the "Rights Plan Agreement") dated as of Oct. 13, 1992, as amended and restated as of April 26, 2019, between the Corporation and AST Trust Company (Canada) (the successor to CST Trust Company). The Shareholder Rights Plan was last confirmed at our annual and special meeting of shareholders on April 26, 2019, and will expire at the close of business on the date of our 2022 Annual Meeting of Shareholders, unless ratified and extended by a further vote of the shareholders. The Rights Plan Agreement was assigned by AST Trust Company (Canada) to Computershare Trust Company of Canada effective Nov. 22, 2019. For further particulars, reference should be made to the Rights Plan Agreement, as amended and restated. A copy of the Rights Plan Agreement may be obtained by contacting the Corporate Secretary, TransAlta Corporation, 110 - 12th Avenue S.W., Calgary, Alberta T2R 0G7; telephone: (403) 267-7110; or by email: corporate_secretary@transalta.com. A copy of the Rights Plan Agreement is also available electronically on SEDAR under our profile, which can be accessed at www.sedar.com, and on the SEC's EDGAR system at www.sec.gov.
Credit Facilities
In 2019, we renewed our syndicated credit agreement giving us access to a $1.25 billion committed credit facility. The agreement is fully committed, expiring in 2023. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. This credit facility has been made available for general corporate purposes including financing ongoing working capital requirements, providing financing for construction capital, growth opportunities and for repaying outstanding borrowings.
On July 24, 2017, TransAlta Renewables entered into a syndicated credit agreement giving it access to a $500-million committed credit facility. The credit agreement is fully committed, and in the second quarter of 2019 was amended from $500 million to $700 million and extended to 2023. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. For further information please see Note 23 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Long-Term Debt
The long-term debt of the Corporation consists of $251 million face value of debentures outstanding, which bear interest at fixed rates ranging from 6.9 per cent to 7.3 per cent and have maturity dates ranging from 2029 to 2030. In addition, we have US$700 million face value in senior notes outstanding that bear interest at fixed rates ranging from 4.5 per cent to 6.5 per cent and have maturity dates ranging from 2022 to 2040. For further information please see Note 23 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
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Exchangeable Securities
On March 22, 2019, the Corporation entered into a definitive Investment Agreement, whereby Brookfield agreed to invest $750 million in the Corporation through the purchase of Exchangeable Securities, which are exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Hydro Assets’ future-adjusted EBITDA, as described above. The Exchangeable Securities were issued in two tranches, with the first having occurred on May 1, 2019 consisting of $350 million of 7 per cent unsecured subordinated debentures due May 1, 2039 and on Oct. 30, 2020 the second and final close consisting of $400 million of a new series of redeemable, retractable first preferred shares. The Investment Agreement, together with an Exchange and Option Agreement (the "E&O Agreement") entered into by the parties concurrently with the closing of the first tranche of the investment, gives Brookfield the Exchange Right of the outstanding exchangeable securities into up to a maximum 49 per cent equity ownership interest in TransAlta’s Alberta Hydro Assets after Dec. 31, 2024. The Investment Agreement and the E&O Agreement also give TransAlta the right to redeem the Exchangeable Securities at any time after Dec. 31, 2028, subject to certain terms and conditions, if Brookfield chooses not to exercise its Option to Exchange. See "—Investment Agreement and E&O Agreement" below.
Investment Agreement and E&O Agreement
The following description of certain provisions of the Investment Agreement and the E&O is a summary only, is not comprehensive and is qualified in its entirety by reference to the full text of each of the Investment Agreement and E&O Agreement, copies of which can be found on SEDAR under our profile at www.sedar.com and on EDGAR under our profile at www.sec.gov.
In connection with the Investment Agreement, Brookfield has committed to purchase common shares of the Corporation on the open market over a period of 24 months following the Initial Funding Date, being May 1, 2019, to its total share ownership to not less than 9 per cent, subject to certain exceptions and provided that the Brookfield is not obliged to purchase common shares at a price greater than $10 per share. This increase in shareholdings further aligns the interests of Brookfield and TransAlta. Pursuant to the Investment Agreement, Brookfield is entitled to nominate two individuals on its slate of directors for election at the Corporation’s Annual meetings of shareholders.
The Investment Agreement contains certain lock-up provisions that restrict Brookfield or its affiliates’ ability to transfer their TransAlta common shares during a period that commenced on May 1, 2019, and terminates on Dec. 31, 2023 (the “Lock-Up”). The Lock-Up contains customary exceptions, including an exception for transfers of common shares by investment funds managed by or affiliated with Brookfield undertaken in accordance with the investment funds’ fund requirements.
The Investment Agreement contemplates that the Exchangeable Securities will be a long-term investment and therefore may not be transferred except by Brookfield to one of its affiliates. Brookfield has agreed to be the sole representative of all of its permitted transferees for the purpose of the Investment Agreement.
The Investment Agreement includes certain standstill commitments by the Brookfield (the “Standstill”), with customary exceptions, which will be in effect for three years starting from May 1, 2019 (the “Standstill Period”). Among other things, the Standstill prohibits the Brookfield from acquiring an ownership interest in the Corporation above 19.9 per cent of the common shares. During the Standstill Period, Brookfield has also agreed that it will: (a) vote in favour of each director nominated by the Board; (b) vote against any shareholder nomination for directors that is not approved by the Board; (c) vote against any proposal or resolution to remove any Board member; and (d) vote in accordance with any recommendations by the Board on all other proposals. Certain Standstill provisions extend beyond the Standstill Period so long as Brookfield has nominees on the Board.
In accordance with the terms of the Investment Agreement, TransAlta has formed a Hydro Assets Operating Committee consisting of two representatives from Brookfield and two representatives from TransAlta to provide advice and recommendations in connection with the operation, and maximizing the value, of the Alberta Hydro Assets. In connection with this, the Corporation has committed to pay Brookfield an annual hydro fee of $1.5 million for six years commencing on May 1, 2019.
Registration Rights Agreement
The following description of certain provisions of the registration rights agreement entered into between Eagle Hydro II (an affiliate of Brookfield) and the Corporation on May 1, 2019 (the “Registration Rights Agreement”) is a summary only, is not comprehensive and is qualified in its entirety by reference to the full text of the Registration Rights Agreement, a copy of which can be found on SEDAR under our profile at www.sedar.com.
The Registration Rights Agreement provides that Eagle Hydro II and any affiliate of Brookfield that becomes party to the Registration Rights Agreement (each a “Holder”) may, at any time and from time to time, make a written request (a “Demand Registration”) to the Corporation to file a Prospectus Supplement with the securities commissions or similar




authorities in each of the provinces of Canada in respect of the distribution of all or part of the Common Shares then held by the Holder (“Registrable Securities”), subject to certain restrictions set forth in the Registration Rights Agreement. Upon receipt by the Corporation of a Demand Registration, the Corporation will promptly file a Prospectus Supplement in order to permit the offer and sale or other disposition or distribution in Canada of all or any portion of the Registrable Securities held, directly or indirectly, by the Holder (a “Demand Offering”). The Corporation will not be obligated to effect: (a) more than three Demand Offerings in total during the term of the Registration Rights Agreement; or (b) a Demand Offering if the Registrable Securities have an aggregate market price of less than $50 million.
If at any time the Corporation proposes to file a prospectus supplement with respect to the distribution of any TransAlta common shares to the public, then the Corporation will give notice of the proposed distribution to each Holder not less than five business days in advance of the anticipated filing date of the prospectus supplement (or, in the case of a “bought deal” or another public offering that is not expected to include a road show, such notice as is practicable under the circumstances), which notice will offer each Holder the opportunity to qualify for distribution such number of Registrable Securities as such Holder may request. The Corporation will use commercially reasonable efforts to include in such Prospectus Supplement such Registrable Securities (a “Piggy Back Offering”), unless the Corporation’s managing underwriter or underwriters determines, in good faith, that including such Registrable Securities in the distribution would, in their opinion, adversely affect the Corporation’s distribution or sales price of the securities being offered by the Corporation.
The Demand Offerings and Piggy Back Offerings are subject to various conditions and limitations. The Corporation is entitled to defer any Demand Offering in certain circumstances, including during a regular annual and quarterly blackout period in respect of the release of its financial results.
The Registration Rights Agreement includes provisions providing for each of the Corporation and the Holders to indemnify each other for losses or claims caused by the applicable party’s inclusion of a misrepresentation in disclosure included in any prospectus and for breaches of applicable securities laws.
In the case of a prospectus supplement filed in connection with a Demand Offering or Piggy Back Offering, the Corporation will pay all applicable fees and expenses incident to the Corporation’s performance of, or compliance with, the terms of such offering, provided that in the event any Registrable Securities are freely tradeable at the time that the Corporation receives the offering request, the Corporation and the Holders will be jointly and severally responsible for the proportionate share of registration fees and expenses of any Holders based on the total offering price of the freely tradeable securities sold by the Holders to the total offering price of all the Securities sold by the Corporation in such offering. The Corporation and the Holders will be jointly and severally responsible for paying all selling expenses (including fees or commissions payable to an underwriter, investment banker, manager or agent and any transfer taxes attributable to the sale of Registrable Securities) with respect to Registrable Securities sold by the Holders and the Corporation will pay all selling expenses with respect to any Securities sold for the account of the Corporation. The Corporation and the Holders will be solely responsible on a joint and several basis for all out-of-pocket expenses incurred by any Holders in connection with a Demand Offering or Piggy Back Offering.
If a Holder ceases to be affiliated with the Corporation, the Holder will cease to have any rights or obligations under the Registration Rights Agreement. The Registration Rights Agreement will terminate when Brookfield together with its affiliates beneficially own in the aggregate less than three per cent of the issued and outstanding common shares.
Additional details about the Brookfield Investment can be found in our material change report dated March 26, 2019, available electronically on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. Copies of the Investment Agreement, together with copies of the exchangeable debenture, the E&O Agreement and the Registration Rights Agreement are also available on SEDAR and on EDGAR. Shareholders are encouraged to read these documents in their entirety.
Non-Recourse Debt
The Corporation has non-recourse debt outstanding in an amount equal to approximately $1,858 million face value, which is represented by bonds and debentures that bear interest at rates ranging from 2.95 per cent to 4.51 per cent and have maturity dates ranging from 2028 to 2042. For further information please see Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Tax Equity
In December 2019, coinciding with Big Level and Antrim wind projects achieving commercial operation, TransAlta received funding of approximately US$126 million from a tax equity partner. In December 2020, coinciding with the commercial operation of the Skookumchuck wind facility, a total of approximately US$121 million was raised from a tax equity partner in respect of the Skookumchuck project entity, which had the effect of lowering the cost of TransAlta's 49% investment in the Skookumchuck wind facility from approximately US$125 million to approximately US$66 million.



The Corporation also assumed US$24 million in tax equity financing as part of the acquisition of the Lakeswind wind facility in 2015. Under International Financial Reporting Standards tax equity financings are included as debt in our consolidated financial statements. For further information on tax equity please see Note 23 of our audited consolidated financial statements for the year ended Dec. 31, 2020, which financial statements are incorporated by reference herein. Please also see "Documents Incorporated by Reference" in this AIF.
Restrictions on Debt
The syndicated credit facilities include a number of customary covenants and restrictions in order to maintain access to the funding commitments. Non-recourse bonds are subject to customary financing conditions and covenants that may restrict the Corporation's ability to access funds generated by the facilities' operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution.
Credit Ratings
Credit ratings provide information relating to our financing costs, liquidity and operations and affect our ability to obtain short-term and long-term financing and/or the cost of such financing. Maintaining a strong balance sheet also allows our commercial team to contract the Corporation’s portfolio with a variety of counterparties on terms and prices that are favourable to our financial results and provides us with better access to capital markets through commodity and credit cycles. We remain focused on strengthening our financial position and cash flow coverage ratios to ensure a strong balance sheet is maintained and sufficient financial capital is available. Our credit ratings as of Dec. 31, 2020, are as follows:

DBRS Moody's S&P
Issuer Rating BBB (low) Not Applicable BB+
Corporate Family Rating Not Applicable Ba1 Not Applicable
Preferred Shares
Pfd-3 (low)(1)
Not Applicable
P-4(High)
Unsecured Debt/MTNs BBB (low) Ba1/LGD4 BB+
Rating Outlook Stable Stable Stable
Note:
(1) The outstanding Preferred Shares all have the same rating.
In 2020, Moody’s reaffirmed its issuer rating of Ba1 and revised its rating outlook to stable from positive. During 2020, DBRS Limited reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred Shares rating of Pfd-3 (low) and Issuer Rating of BBB (low) with a stable outlook. Standard and Poor’s reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating to BB+ with a stable outlook. In 2019, we decided not to renew our rating services with Fitch and the active rating from Fitch expired on Jan. 31, 2020.
DBRS
DBRS Corporate rating analysis begins with an evaluation of the fundamental creditworthiness of the issuer, which is reflected in an "issuer rating." Issuer ratings address the overall credit strength of the issuer. Unlike ratings on individual securities or classes of securities, issuer ratings are based on the entity itself and do not include consideration for security or ranking. Ratings that apply to actual securities (secured or unsecured) may be higher, lower or equal to the issuer rating for a given entity. As of Dec. 31, 2020, our issuer rating was BBB (low) (stable) from DBRS. A BBB rating is the fourth highest out of 10 categories.
The DBRS preferred share rating scale is used in the Canadian securities market and is meant to give an indication of the risk that a borrower will not fulfil its full obligations in a timely manner, with respect to both dividend and principal commitments. Every DBRS rating is based on quantitative and qualitative considerations relevant to the borrowing entity. Each rating category is denoted by the subcategories "high" and "low." The absence of either a "high" or "low" designation indicates the rating is in the middle of the category. Preferred shares rated Pfd-3 are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. Each of the Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares have been rated Pfd-3 (low) (stable) by DBRS. The Pfd-3 rating is the third highest out of six categories.
The DBRS long-term rating scale provides an opinion on the risk of default, which is the risk that an issuer will fail to satisfy its financial obligations in accordance with the terms under which an obligation has been issued. Ratings are based on quantitative and qualitative considerations relevant to the issuer, and the relative ranking of claims. All rating
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categories other than AAA and D also contain subcategories "(high)" and "(low)". The absence of either a "(high)" or "(low)" designation indicates the rating is in the middle of the category. Debt securities rated BBB are of adequate credit quality. The capacity for the payment of financial obligations is considered acceptable, but may be vulnerable to future events. As of Dec. 31, 2020, our senior unsecured long-term debt is rated BBB (low) (stable) by DBRS. The BBB rating category is the fourth highest of 10 categories for long-term obligations.
Moody's
Moody's Corporate Family Ratings (CFRs) are long-term ratings that reflect the relative likelihood of a default on a corporate family's debt and debt-like obligations and the expected financial loss suffered in the event of default. A CFR is assigned to a corporate family as if it had a single class of debt and a single consolidated legal entity structure. A CFR does not reference an obligation or class of debt and thus does not reflect priority of claim. As at Dec. 31, 2020, our Corporate Family Rating was Ba1 with a stable outlook. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk. Moody's appends the numerical modifiers 1, 2, and 3 to each generic 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 the modifier 3 indicates a ranking in the lower end of that generic rating category. The Ba rating category is the fifth highest rating out of nine rating categories.
Moody's long-term ratings are assigned to issuers or obligations with an original maturity of one year or more and reflect both on the likelihood of a default on contractually promised payments and the expected financial loss suffered in the event of default. As of Dec. 31, 2020, our senior unsecured long-term debt is rated Ba1 / LGD4 by Moody's. The Ba rating category is the fifth-highest rating out of nine rating categories. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk.
Moody's Loss Given Default (LGD) assessments are opinions about expected loss given default expressed as a per cent of principal and accrued interest at the resolution of the default. One of the six LGD assessments are assigned to individual loan, bond, and preferred stock issues. The firm-wide or enterprise expected LGD rate generally approximates a weighted average of the expected LGD rates on the firm's liabilities (excluding preferred stock), where the weights equal each obligation's expected share of the total liabilities at default. As of Dec. 31, 2020, our LGD assessment from Moody's was LGD4 which represents a loss range of greater than or equal to 50 per cent and less than 70 per cent. LGD4 is the fourth-highest assessment category out six categories.
Standard & Poor's
A Standard & Poor's issuer credit rating is a forward-looking opinion about an obligor's overall creditworthiness. This opinion focuses on the obligor's capacity and willingness to meet its financial commitments as they come due. It does not apply to any specific financial obligation, as it does not take into account the nature of and provisions of the obligation, its standing in bankruptcy or liquidation, statutory preferences, or the legality and enforceability of the obligation. As at Dec. 31, 2020, our issuer credit rating was BB+ with a stable outlook with S&P. This is the fifth highest of 11 ratings categories. Although less vulnerable than other speculative issuers, an obligor rated BB is regarded as having a degree of speculative characteristics. When faced with uncertainties or challenges in the business, financial, or economic environment, entities rated ‘BB’ may in-turn face challenges meeting their financial commitments. The ratings from 'AA' to 'CCC' may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.
A Standard & Poor's issue credit rating is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific financial obligation, a specific class of financial obligations, or a specific financial program (including ratings on medium-term note programs and commercial paper programs). It takes into consideration the creditworthiness of guarantors, insurers, or other forms of credit enhancement on the obligation and takes into account the currency in which the obligation is denominated. The opinion reflects Standard & Poor's view of the obligor's capacity and willingness to meet its financial commitments as they come due, and may assess terms, such as collateral security and subordination, which could affect ultimate payment in the event of default. This is the fifth highest of 11 ratings categories. The ratings from AA to CCC may be modified by the addition of a plus (+) or minus (-) sign to show relative standing within the major rating categories.
The Standard & Poor's Canadian preferred share rating scale serves issuers, investors, and intermediaries in the Canadian financial markets by expressing preferred share ratings (determined in accordance with global rating criteria) in terms of rating symbols that have been actively used in the Canadian market over a number of years. A Standard & Poor's preferred share rating on the Canadian scale is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific preferred share obligation issued in the Canadian market, relative to preferred shares issued by other issuers in the Canadian market. There is a direct correspondence between the specific ratings assigned on the Canadian preferred share scale and the various rating levels on the global debt rating scale of Standard & Poor's.  Each of our outstanding Preferred Shares Series have been rated P-4(High) by S&P. The P-4(High) rating is the fourth highest of eight categories. A P-4(High) rating corresponds to a B+ rating on the global preferred share rating scale.
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Obligors rated BB, B, CCC, and CC are regarded as having significant speculative characteristics, of which BB indicates the least degree of speculation and CC the highest. While such obligors will likely have some quality and protective characteristics, these may be outweighed by large uncertainties or major exposures to adverse conditions. An obligor rated 'B' is less vulnerable in the near term than other lower-rated obligors. However, it faces major ongoing uncertainties and exposure to adverse business, financial, or economic conditions which could lead to the obligor's inadequate capacity to meet its financial commitments.
We are focused on maintaining a strong financial position and cash flow coverage ratios to support our business. Our available credit facilities, funds from operations and debt financing options provide us with financial flexibility. As a result, we can be selective as to if and when we go to the capital markets for funding.
Note Regarding Credit Ratings
Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. The credit ratings accorded to our outstanding securities by DBRS, Moody's and Standard & Poor's as applicable, are not recommendations to purchase, hold or sell such securities. There is no assurance that the ratings will remain in effect for any given period or that a rating will not be revised or withdrawn entirely by DBRS, Moody's or Standard & Poor's in the future if, in its judgement, circumstances so warrant.
We have paid fees for rating services to DBRS, Moody's, Standard & Poor's and Fitch during the last two years. We have also paid fees to S&P, DBRS and Kroll Bond Rating Agency for certain other services provided to the Corporation during the last two years.
Dividends
Common Shares
Dividends on our common shares are paid at the discretion of the Board. In determining the payment and level of future dividends, the Board considers our financial performance, results of operations, cash flow and needs, with respect to financing our ongoing operations and growth, balanced against returning capital to shareholders. The Board continues to focus on building sustainable earnings and cash flow growth.
TransAlta has declared and paid the following dividends per share on its outstanding common shares for the past three years:
Period Dividend per Common Share
2018 First Quarter
Second Quarter
Third Quarter
Fourth Quarter 		$0.04
$0.04
$0.04
$0.04
2019 First Quarter
Second Quarter
Third Quarter
Fourth Quarter 		$0.04
$0.04
$0.04
$0.04
2020 First Quarter
Second Quarter
Third Quarter
Fourth Quarter 		$0.04
$0.0425
$0.0425
$0.0425
2021 First Quarter $0.045

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Preferred Shares
TransAlta has declared and paid the following dividends per share on its outstanding preferred shares for the past three years:
Series A Shares
Period Dividend per
Series A Share
2018 First Quarter $0.16931
Second Quarter $0.16931
Third Quarter $0.16931
Fourth Quarter $0.16931
2019 First Quarter $0.16931
Second Quarter $0.16931
Third Quarter $0.16931
Fourth Quarter $0.16931
2020 First Quarter $0.16931
Second Quarter $0.16931
Third Quarter $0.16931
Fourth Quarter $0.16931
2021 First Quarter $0.16931
Series B Shares
Period Dividend per
Series B Share
2018 First Quarter $0.15651
Second Quarter $0.15645
Third Quarter $0.16125
Fourth Quarter $0.17467
2019 First Quarter $0.17889
Second Quarter $0.19951
Third Quarter $0.20984
Fourth Quarter $0.22301
2020 First Quarter $0.22949
Second Quarter $0.22800
Third Quarter $0.14359
Fourth Quarter $0.13693
2021 First Quarter $0.13186
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Series C Shares
Period Dividend per
Series C Share
2018 First Quarter $0.2875
Second Quarter $0.2875
Third Quarter $0.25169
Fourth Quarter $0.25169
2019 First Quarter $0.25169
Second Quarter $0.25169
Third Quarter $0.25169
Fourth Quarter $0.25169
2020 First Quarter $0.25169
Second Quarter $0.25169
Third Quarter $0.25169
Fourth Quarter $0.25169
2021 First Quarter $0.25169

Series E Shares
Period Dividend per
Series E Share
2018 First Quarter $0.3125
Second Quarter $0.3125
Third Quarter $0.3125
Fourth Quarter
$0.32463
2019 First Quarter $0.32463
Second Quarter $0.32463
Third Quarter $0.32463
Fourth Quarter
$0.32463
2020 First Quarter $0.32463
Second Quarter $0.32463
Third Quarter $0.32463
Fourth Quarter
$0.32463
2021 First Quarter $0.32463
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Series G Shares
Period Dividend per
Series G Share
2018 First Quarter $0.33125
Second Quarter $0.33125
Third Quarter $0.33125
Fourth Quarter
$0.33125
2019 First Quarter $0.33125
Second Quarter $0.33125
Third Quarter $0.33125
Fourth Quarter $0.31175
2020 First Quarter $0.31175
Second Quarter $0.31175
Third Quarter $0.31175
Fourth Quarter $0.31175
2021 First Quarter $0.31175

Series I Shares
TransAlta also declared an aggregate cash dividend of $4,743,169.40 in respect of the issued and outstanding Series I Shares for the period starting from and including Oct. 30, 2020 up to but excluding Dec. 31, 2020, which was paid on March 1, 2021.
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Market for Securities
Common Shares
Our common shares are listed on the TSX under the symbol "TA" and the New York Stock Exchange (the "NYSE") under the symbol "TAC." The following table sets forth the reported high and low trading prices and trading volumes of our common shares as reported by the TSX for the periods indicated:
Price ($)
Month High Low Volume
2020
March 10.74 5.32 45,631,306
April 8.58 6.86 17,856,819
May 8.55 7.37 15,568,382
June 9.00 7.73 13,284,705
July 8.87 7.93 8,080,666
August 8.91 8.32 10,913,070
September 8.49 7.67 15,566,902
October 8.74 7.85 10,519,344
November 9.09 7.96 13,998,923
December 9.77 8.75 13,100,333
2021
January 11.57 9.57 6,986,031
February 12.34 10.97 15,152,046
March 1 11.30 11.12 813,152

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Preferred Shares
Series A Shares
Our Series A Shares are listed on the TSX under the symbol "TA.PR.D".
Date of Issuance
Number of Securities (2)
Issue Price per Security Description of Transaction
Dec. 10, 2010(1)
12,000,000 Series A Shares $25.00 Public Offering
Notes:
(1)Series A Shares were issued pursuant to a public offering by way of a prospectus supplement dated Dec. 3, 2010, to a short form base shelf prospectus dated Oct. 19, 2009.
(2)On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis. On March 1, 2021, we announced that we will not redeem any of our Series A Shares. As a result, holders of the Series A Shares will have until March 16, 2021 in order to exercise their right to convert all or any portion of the Series A Shares into Series B Shares, subject to the share terms

Price ($)
Month High Low Volume
2020
March 10.51 6.48 501,198
April 7.98 8.15 380,878
May 8.21 7.80 159,953
June 8.89 7.78 218,448
July 9.32 8.20 67,513
August 9.35 8.80 69,279
September 9.33 8.75 168,784
October 9.06 8.55 159,637
November 10.29 8.61 211,603
December 10.99 9.83 233,317
2021
January 12.40 10.47 316,112
February 11.91 10.20 470,997
March 1 10.46 10.21  8,256

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Series B Shares
Our Series B Shares are listed on the TSX under the symbol "TA.PR.E".
Date of Issuance Number of Securities Issue Price per Security Description of Transaction
March 31, 2016(1)
1,824,620 Series B Shares N/A Conversion of Series A Shares
Note:
(1)On March 31, 2016, 1,824,620 of the Series A Shares were converted into Series B Shares on a one-for-one basis. On March 1, 2021, we announced that we will not redeem any of our Series B Shares. As a result, holders of the Series B Shares will have until March 16, 2021 in order to exercise their right to convert all or any portion of the Series B Shares into Series A Shares, subject to the share terms.

Price ($)
Month High Low Volume
2020
March 11.10 7.22 63,886
April 9.25 7.70 132,206
May 8.70 8.00 71,932
June 8.70 7.90 71,216
July 8.90 8.13 83,830
August 9.26 8.60 30,000
September 9.25 8.53 114,250
October 9.00 8.51 25,852
November 10.11 8.70 45,236
December 10.75 9.81 45,766
2021
January 12.35 10.27 82,249
February 12.35 9.57 40,391
March 1 11.10 11.10 100
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Series C Shares
Our Series C Shares are listed on the TSX under the symbol "TA.PR.F".
Date of Issuance Number of Securities Issue Price per Security Description of Transaction
Nov. 30, 2011(1)
11,000,000 Series C Shares $25.00 Public Offering
Note:
(1) Series C Shares were issued pursuant to a public offering by way of a prospectus supplement dated Nov. 23, 2011 to a short form base shelf prospectus dated Nov. 15, 2011.

Price ($)
Month High Low Volume
2020
March 13.70 8.51 253,494
April 10.81 9.56 493,216
May 10.87 10.34 192,767
June 12.18 10.40 184,950
July 11.97 10.92 163,722
August 12.82 11.65 102,358
September 12.94 12.30 143,238
October 12.76 12.21 183,505
November 14.20 12.31 142,357
December 15.03 13.71 131,024
2021
January 16.01 14.99 261,542
February 15.19 13.51 105,334
March 1 13.70 13.35 16,500

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Series E Shares
Our Series E Shares are listed on the TSX under the symbol "TA.PR.H".
Date of Issuance Number of Securities Issue Price per Security Description of Transaction
Aug. 10, 2012(1)
9,000,000 Series E Shares $25.00 Public Offering
Note:
(1) Series E Shares were issued pursuant to a public offering by way of a prospectus supplement dated Aug. 3, 2012 to a short form base shelf prospectus dated Nov. 15, 2011.

Price ($)
Month High Low Volume
2020
March 16.16 9.90 410,060
April 13.13 11.70 385,601
May 13.14 12.59 110,397
June 14.25 12.64 252,694
July 14.18 13.22 137,272
August 14.95 13.87 106,456
September 15.42 14.60 131,659
October 15.02 14.43 115,584
November 17.01 14.51 119,557
December 17.99 16.45 291,326
2021
January 18.93 17.88 339,587
February 17.45 15.72 162,972
March 1 16.16 15.85 12,600
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Series G Shares
Our Series G Shares are listed on the TSX under the symbol "TA.PR.J".
Date of Issuance Number of Securities Issue Price per Security Description of Transaction
Aug. 15, 2014(1)
6,600,000 Series G Shares $25.00 Public Offering
Note:
(1) Series G Shares were issued pursuant to a public offering by way of a prospectus supplement dated Aug. 8, 2014 to a short form base shelf prospectus dated Dec. 9, 2013.
Price ($)
Month High Low Volume
2020
March 16.65 10.70 201,696
April 14.77 12.05 252,234
May 14.58 14.10 59,889
June 15.45 14.01 89,643
July 15.25 13.96 162,358
August 16.50 15.30 38,207
September 16.29 15.50 75,321
October 16.00 15.51 104,703
November 17.85 15.61 84,339
December 18.99 17.38 90,111
2021
January 20.00 18.93 98,474
February 18.10 16.26 141,552
March 1 16.52 16.35 1,600

Series I Shares
On Oct. 30, 2020, the Corporation issued 400,000 redeemable first preferred shares, Series I ("Series I Shares"), at a price of $1,000 per Series I Share, for aggregate proceeds of $400,000,000. The Series I Shares were issued to Brookfield under the Investment Agreement and are not listed or quoted on a marketplace.
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Directors and Officers
The name, province or state and country of residence of each of our directors as at Dec. 31, 2020, their respective position and office and their respective principal occupation during the five preceding years, are set out below. The year in which each director was appointed to serve on the Board is also set out below. Each director is appointed to serve until the next annual meeting of TransAlta or until his or her successor is elected or appointed.
Name, Province (State) and Country of Residence Year First Became Director Principal Occupation
Rona H. Ambrose
Alberta, Canada
2017 The Honourable Rona Ambrose is Chair of the Governance, Safety and Sustainability Committee. She is a national leader, former Leader of Canada's Official Opposition in the House of Commons and former leader of the Conservative Party of Canada. As a key member of the federal cabinet for a decade, Ms. Ambrose solved problems as a minister of the Crown across nine government departments, including serving as Vice Chair of the Treasury Board for several years and Chair of the cabinet committee for public safety, justice and Aboriginal issues. As the former environment minister responsible for the GHG regulatory regime in place across several industrial sectors, she understands the challenges facing the fossil fuel industry. Ms. Ambrose was personally responsible for the development of several federal policies, ranging from industrial strategies in military procurement to health innovation to improvements to sexual assault laws. Ms. Ambrose is a passionate advocate for women in Canada and around the world and led the global movement to create the "International Day of the Girl" at the United Nations. She was also responsible for ensuring that Aboriginal women in Canada were finally granted equal matrimonial rights. She successfully fought for the creation of a Canadian refugee program to bring Yazidi women and girls who have been sexually enslaved by ISIS to safety in Canada. Ms. Ambrose is the Deputy Chairwoman of TD Securities. She is a Global Fellow at the Wilson Centre Canada Institute in Washington, DC and serves on the advisory board of the Canadian Global Affairs Institute. Ms. Ambrose is also a director of Manulife Financial Corporation, Coril Holdings Ltd. and Andlauer Healthcare Group. She has a BA from the University of Victoria and an MA from the University of Alberta. She is also a graduate of the Harvard Kennedy School of Government Senior Leaders Program. Ms. Ambrose has an extensive track record of strong leadership acquired through a wide range of experience at the most senior levels of the Canadian government.

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John P. Dielwart
Alberta, Canada
2014 Mr. Dielwart is the Chair of the Board. Mr. Dielwart was formerly Chief Executive Officer of ARC Resources Ltd., which owns and operates oil and gas properties in Western Canada. He oversaw the growth of ARC Resources Ltd. from start-up in 1996 to a company with a total capitalization of approximately $10 billion at the time of his retirement. After his retirement from ARC Resources Ltd. on Jan. 1, 2013, Mr. Dielwart re-joined ARC Financial Corp. as Vice-Chairman and Partner. ARC Financial is Canada's leading energy-focused private equity manager. In 2020, Mr. Dielwart resigned from the board but remained as Partner and member of ARC Financial's Investment and Governance committees, and currently represents ARC Financial on the board of Aspenleaf Energy Limited. Mr. Dielwart has a Bachelor of Science with distinction (civil engineering) degree from the University of Calgary. He is a member of the Association of Professional Engineers and Geoscientists of Alberta and is a past Chairman of the Board of Governors of the Canadian Association of Petroleum Engineers . In 2015, Mr. Dielwart was inducted into the Calgary Business Hall of Fame and in 2018 he received the Oil and Gas Council's Canadian Lifetime Achievement Award. He is also a director of Crescent Point Energy Corp.
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Name, Province (State) and Country of Residence Year First Became Director Principal Occupation
Dawn L. Farrell
Alberta, Canada
2012 Mrs. Farrell became President and Chief Executive Officer of TransAlta Corporation on Jan. 2, 2012. Prior to her appointment, she served as Chief Operating Officer from 2009 to 2011. Mrs. Farrell has over 35 years of experience in the electricity industry, with roles at TransAlta and BC Hydro. She has served as Executive Vice-President, Commercial Operations and Development; Executive Vice-President, Corporate Development; Executive Vice-President, Independent Power Projects; and Vice-President, Energy Marketing and IPP Development at TransAlta Corporation. From 2003 to 2006, Mrs. Farrell served as Executive Vice-President, Generation at BC Hydro. From 2006 to 2007, she served as BC Hydro’s Executive Vice-President Engineering, Aboriginal Relations and Generation. Mrs. Farrell sits on the board of directors of The Chemours Company, an NYSE-listed chemical company, and the Business Council of Alberta. She is also a member of the Trilateral Commission and the Business Council of Canada, and is Chancellor of Mount Royal University. Her past board appointments include The Conference Board of Canada, the Business Council of Canada, the Calgary Stampede, the Mount Royal College Board of Governors, Fording Coal Income Fund, New Relationship Trust Fund, and Mount Royal College Foundation. Mrs. Farrell holds a Bachelor of Commerce with a major in finance and a Master's degree in economics from the University of Calgary. She has also attended the Advanced Management Program at Harvard University. Mrs. Farrell will retire as President and Chief Executive Officer and as a member of the Board of Directors on March 31, 2021.

Alan J. Fohrer
California, U.S.A.
2013
Mr. Fohrer was Chairman and Chief Executive Officer of Southern California Edison Company ("SCE"), a subsidiary of Edison International ("Edison") and one of the largest electric utilities in the United States. He was elected Chief Executive Officer in 2002 and Chairman in 2007. In 2000, Mr. Fohrer was elected as President and Chief Executive Officer of Edison Mission Energy ("EME"), a subsidiary of Edison that owns and operates independent power facilities. During his tenure at EME, Mr. Fohrer restructured a number of the international projects, which enhanced the value of the assets sold in subsequent years. Mr. Fohrer also served as Executive Vice-President, Treasurer and Chief Financial Officer of both Edison and SCE from 1995 to 1999. After 37 years with Edison, Mr. Fohrer retired in December 2010. He currently sits on the boards of PNM Resources, Inc., a publicly-held energy holding company, and Blue Shield of California, a non-profit health insurance provider. Mr. Fohrer has served on boards of directors of the Institute of Nuclear Power Operations, the California Chamber of Commerce, Duratek, Inc., and Osmose Utilities Services, Inc., MWH, Inc. and Synagro, a private waste management company. He is also a member of the Viterbi School of Engineering Board of Councilors for the University of Southern California and Chair of the California Science Center Foundation. Mr. Fohrer holds a Master of Science in civil engineering from the University of Southern California, Los Angeles, as well as a Master of Business Administration from California State University in Los Angeles.
Harry Goldgut
Ontario, Canada
2019
Mr. Goldgut is Vice Chair of Brookfield Asset Management's Renewable Group and Brookfield's Infrastructure Group and provides strategic advice related to Brookfield's open-end Infrastructure Fund. Mr. Goldgut was the CEO or Co-CEO and Chairman of Brookfield Renewable Power Inc., from 2000 to 2008, and thereafter, until 2015, he was Chairman of Brookfield's Power and Utilities Group. From 2015 to 2018, he served as Executive Chairman of Brookfield's Infrastructure and Power Groups. Mr. Goldgut joined Brookfield in 1997 and led the expansion of Brookfield's renewable power and utilities operations. He has had primary responsibility for strategic initiatives, acquisitions and senior regulatory relationships. He was responsible for the acquisition of the majority of Brookfield's renewable power assets. Mr. Goldgut also played a role in the restructuring of the electricity industry in Ontario as a member of several governmental committees, including the Electricity Market Design Committee, the Minister of Energy's Advisory Committee, the Clean Energy Task Force, the Ontario Energy Board Chair's Advisory Roundtable and the Ontario Independent Electricity Operator CEO Roundtable on Market Renewal. Mr. Goldgut also serves on the Boards of Directors of Isagen S.A. ESP, the third- largest power generation company in Colombia; and the Princess Margaret Cancer Foundation. Mr. Goldgut attended the University of Toronto and holds an LL.B from York University's Osgoode Hall Law School.
Richard Legault
Quebec, Canada
2019 Mr. Legault is Vice Chair of Brookfield's Renewable Group. Prior to his current role, Mr. Legault served as Chief Executive Officer of Brookfield Renewable Partners from 1999 to August 2015, during which time he led the growth of Brookfield's renewable power operations globally, helping to make Brookfield Renewable one of the world's largest publicly traded, pure-play renewable power portfolios. From 2015 to 2018, he served as Executive Chairman of the Brookfield Renewable Group. Mr. Legault was Chief Financial Officer of Brookfield Asset Management from 2000 to 2001, prior to which he held several senior positions in operations, finance, and corporate development with Brookfield's forest products operations. Serving at Brookfield for over 31 years, Mr. Legault has been described as instrumental in developing Brookfield's renewable business, which is well-established in North America, South America and Europe. Mr. Legault also serves on the Board of Directors of Westinghouse Electric Corporation, one of the largest nuclear technology and services companies globally, and serves as chair of its Risk Committee. Mr. Legault received a Bachelor of Accounting from the Université du Québec in Hull and is a member of the Chartered Professional Accountants of Canada (CPA, CA).
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Name, Province (State) and Country of Residence Year First Became Director Principal Occupation
Yakout Mansour
California, U.S.A.
2011 Mr. Mansour is Chair of the Investment Performance Committee. Mr. Mansour has over 40 years of experience as both a professional engineer and executive in the electric utility business in Canada, the United States, and abroad. He retired as President and Chief Executive Officer of the California Independent System Operator Corporation ("CAISO") in 2011, a position he had held since 2005. CAISO is responsible for operating and controlling 80 per cent of the California electric grid, designing and operating the California electricity market, and for settlements of over $8 billion annually. Under Mr. Mansour's leadership, the California market structure was completely redesigned, and CAISO established the market and technical foundation to accommodate one of the most aggressive renewable portfolio standards in the world. Prior to that, Mr. Mansour served in senior executive roles at BC Hydro and the British Columbia Transmission Corporation where he was responsible for operation, asset management, and inter-utility affairs of the electric grid. In 2009, Mr. Mansour was named to the U.S. Department of Energy Electricity Advisory Committee as a vice chair. He also served on the various committees of the North American Electric Reliability Corporation and its predecessor organization, CEGRE, the Transmission Council of the Canadian Electricity Association, and the Board of Directors of the Electric Power Research Institute. A retired professional engineer and a Fellow of the Institute of Electrical and Electronics Engineers, Mr. Mansour has authored and co-authored numerous publications. He is recognized internationally in the field of power engineering and received several distinguished awards for his contributions to the industry. Mr. Mansour holds a Bachelor of Science in electrical engineering from the University of Alexandria (Egypt) and a Master of Science from the University of Calgary.. Mr. Mansour brings to the Corporation and the Board decades of experience in our industry in generation, transmission and energy competitive markets in both a regulated and deregulated market environment. His technical and operational expertise provide an important diversity of thought and perspective to the Board.
Georgia R. Nelson
Washington, U.S.A.
2014 Ms. Nelson was President and Chief Executive Officer of PTI Resources, LLC, an independent consulting firm, from 2005 to 2019. Ms. Nelson had a 35-year career in the power generation industry, serving in various senior executive capacities for Edison International and its subsidiaries between 1971 and 2005. She was President of Midwest Generation Edison Mission Energy (EME), an independent power producer, from 1999 to her retirement in 2005 and General Manager of EME Americas, from 2002 to 2005. Ms. Nelson has extensive experience in electric and renewable energy operations, international business negotiations, environmental policy matters and human resources. Ms. Nelson is currently a director of Cummins Inc., Ball Corporation, and Sims Metal Management Ltd. She was a director of CH2MHILL Corporation, a privately-held company, until December 2017. Ms. Nelson is a past director of Nicor, Inc.  Ms. Nelson was a member of the executive committee of the National Coal Council from 2000 to 2015, and served as Chair from 2006 to 2008. She serves on the advisory committee of the Center for Executive Women at Northwestern University. Ms. Nelson was named to the 2012 National Association of Corporate Directors ("NACO") Directorship 100. She is an NACO Board Fellow. Ms. Nelson holds a Bachelor of Science from Pepperdine University and a Master of Business Administration from the University of Southern California.

Beverlee F. Park
British Columbia, Canada
2015 Ms. Park is the Chair of the Audit, Finance and Risk Committee of the Board as of April 19, 2018. She is also a director of SSR Mining Inc., a publicly-listed mining company, focused on the operation, development, exploration and acquisition of precious metals projects. Ms. Park was previously a member of the Board of Directors of Teekay LNG Partners, InTransit BC and BC Transmission Corp., where she had chaired the audit committees. Ms. Park has served on a wide range of not-for-profit boards over her career, including the University of British Columbia Board of Governors. Ms. Park was an executive of TimberWest Forest Corp. until her retirement in 2013. While at TimberWest she held several roles including Interim CEO, COO, President of the real estate division and Executive Vice President and CFO. Prior to being at TimberWest, Ms. Park was at BC Hydro and KPMG. Ms. Park holds a Bachelor of Commerce from McGill University, an MBA from Simon Fraser University Executive program and is a Fellow of the Chartered Professional Accountants of British Columbia (FCPA/FCA).
Bryan D. Pinney
Alberta, Canada
2018 Mr. Pinney is Chair of the Human Resources Committee. He is currently the lead director for North American Construction Group Ltd., and a director of Sundial Growers Inc., a NASDAQ-listed company. Mr. Pinney was also the recent chair of the Board of Governors of Mount Royal University and has previously served on a number of non-profit boards. He is also a director of one private company. He is a Fellow of the Institute of Chartered Accountants, a Chartered Business Valuator and is a graduate of the Ivey Business School at the University of Western Ontario with an honours degree in Business Administration. He is also a graduate of the Canadian Institute of Corporate Directors. Mr. Pinney has over 30 years of experience serving many of Canada's largest corporations, primarily in energy and resources and construction. Mr. Pinney was a partner with Deloitte LLP between 2002 and 2015. Mr. Pinney served as Calgary Managing Partner of Deloitte LLP from 2002 through 2007 and as National Managing Partner of Audit & Assurance from 2007 to 2011 and Vice-Chair until June 2015. Mr. Pinney was a past member of Deloitte LLP's Board of Directors and chair of the Finance and Audit Committee. Prior to joining Deloitte LLP, Mr. Pinney was a partner with Andersen LLP and served as Calgary Managing Partner from 1991 through May of 2002.
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Name, Province (State) and Country of Residence Year First Became Director Principal Occupation
Sandra R. Sharman
Ontario, Canada
2020
Ms. Sandra Sharman leads the Human Resources, Communications, Marketing and Enterprise Real Estate teams at CIBC, supporting execution of business strategy, transforming to a purpose-driven bank and enabling a world-class culture. Ms. Sharman and her team are responsible for developing and delivering the Global Human Capital Strategy designed to challenge conventional thinking, drive business solutions and shape the culture of the bank. Her key areas of accountabilities also include workplace transformation, compensation and benefits, employee relations, policy and governance, talent management, marketing, corporate real estate, including the bank’s new global headquarters, CIBC Square and all aspects of internal and external communications and public affairs, including government relations and awards. A proven business leader with over 30 years of human resources and financial services experience in both Canada and the U.S., Ms. Sharman has played a lead role in shaping an inclusive and collaborative culture at CIBC, focused on empowering and enabling employees to reach their full potential. Ms. Sharman assumed the leadership of Human Resources at CIBC in 2014 and added accountability for communications and public affairs in 2017. Since then, her portfolio has expanded to encompass purpose, brand, marketing and most recently corporate real estate. Ms. Sharman earned her Masters of Business Administration at Dalhousie University.

Officers
The name, province or state and country of residence of each of our executive officers as at March 2, 2021, their respective position and office and their respective principal occupation are set out below.
Name Principal Occupation Residence
Dawn L. Farrell
President and Chief Executive Officer Alberta, Canada
Jane N. Fedoretz
Executive Vice President, People, Talent & Transformation Alberta, Canada
Brett M. Gellner
Chief Development Officer Alberta, Canada
John H. Kousinioris
Chief Operating Officer Alberta, Canada
Michael J. Novelli Executive Vice-President, Generation Alberta, Canada
Blain van Melle Executive Vice-President, Alberta Business Alberta, Canada
Kerry O'Reilly Wilks
Executive Vice President, Legal, Commercial & External Affairs Alberta, Canada
Todd J. Stack
Executive Vice President, Finance & Chief Financial Officer Alberta, Canada
Aron Willis Executive Vice-President, Growth Alberta, Canada
All of the executive officers of TransAlta have held their present principal occupation or position for the past five years, except for the following:
•On Feb. 4, 2021, the Corporation announced that Mrs. Farrell intends to retire as President and Chief Executive Officer effective March 31, 2021.
•Prior to August 2019, Mr. Gellner was Chief Investment and Strategy Officer of TransAlta. Prior to November 2018, Mr. Gellner was Interim Chief Financial Officer and Chief Strategy and Investment Officer of the Corporation. Prior to July 2018, Mr. Gellner was Chief Investment Officer of the Corporation. Prior to August 2013, Mr. Gellner was Chief Financial Officer of the Corporation. Mr .Gellner will retire as an officer of the Corporation on May 1, 2021. Mr. Gellner is expected to continue to serve as a non-independent director of TransAlta Renewables.
•Prior to February 2021, Ms. Fedoretz was Chief Talent & Transformation Officer of TransAlta. Prior to November 2018, Ms. Fedoretz was Counsel, Energy Group at Blake, Cassels & Graydon LLP.
•On Feb 4, 2021, the Corporation announced that Mr. Kousinioris will be appointed President and Chief Executive Officer on Apr. 1, 2021. Prior to August 2019, Mr. Kousinioris was Chief Growth Officer of TransAlta. Prior to July 2018, Mr. Kousinioris was Chief Legal and Compliance Officer and Corporate Secretary of the Corporation. Prior to October 2015, Mr. Kousinioris was Chief Legal and Compliance Officer of TransAlta. Prior to December 2012, Mr. Kousinioris was a Partner and co-head of the Corporate Commercial Group at Bennett Jones LLP, Barristers and Solicitors.
•Prior to February 2021, Ms. O'Reilly Wilks was Chief Officer, Legal, Regulatory & External Affairs of TransAlta. Prior to August 2019, Ms. O'Reilly Wilks was Chief Legal & Compliance Officer of TransAlta. Prior to November 2018, Ms. O'Reilly Wilks was Head of Legal, North Atlantic & UK, for Vale S.A. (Base Metal Business).
•Prior to February 2021, Mr. Stack was Chief Financial Officer of TransAlta. Prior to May 2019, Mr. Stack was Managing Director and Corporate Controller of TransAlta. Prior to February 2017, Mr. Stack was Managing
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Director and Treasurer of TransAlta. Prior to October 2015, Mr. Stack was Vice-President and Treasurer of TransAlta. Prior to November 2012, Mr. Stack was Treasurer of TransAlta.
•Prior to May 2020, Mr. Novelli was Chief Operating Officer of InterGen, a global independent power generation and energy development company. Prior to 2016, Mr. Novelli was Vice President and General Manager of InterGen. Prior to 2015, Mr. Novelli was Vice President, Global Operations and Engineering of InterGen.
As of March 3, 2021, the directors and executive officers of TransAlta, as a group, beneficially owned, directly or indirectly, or exercised control or direction over less than one per cent of our outstanding common shares.
Interests of Management and Others in Material Transactions
No director or executive officer of TransAlta, no person or company that is the direct or indirect beneficial owner of, or who exercises control or direction over more than 10 per cent of our common shares, and no associate or affiliate of any of them, has or has had any material interest, direct or indirect, in any transaction involving TransAlta within the three most recently completed financial years or to date in 2021 or in any proposed transactions that has materially affected or will materially affect us.
In connection with the Brookfield Investment, Mr. Richard Legault and Mr. Harry Goldgut were nominated by Brookfield and elected to the Board on April 26, 2019. See "Directors and Officers." Brookfield is also entitled to receive certain funding fees, management fees and interest and dividends on its $750-million investment. See "General Development of the Business – Three- Year History – Generation and Business Development – 2019 – Strategic Investment by Brookfield Renewable Partners", and "Capital and Loan Structure – Investment Agreement and E&O Agreement."
Indebtedness of Directors, Executive Officers and Senior Officers
Since Jan. 1, 2020, there has been no indebtedness outstanding to TransAlta from any of our directors, executive officers, senior officers or associates of any such directors, nominees or senior officers.
Corporate Cease Trade Orders, Bankruptcies or Sanctions
Corporate Cease Trade Orders and Bankruptcies
No director, executive officer or controlling security holder of TransAlta Corporation is, as at the date of this Annual Information Form, or has been, within the past 10 years before the date hereof, a director or executive officer of any other issuer that, while that person was acting in that capacity:
•was the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or
•was subject to an event that resulted, after the person ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation for a period of more than 30 consecutive days; or
•within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets.
Personal Bankruptcies
No director, executive officer or controlling security holder of TransAlta Corporation has, within the 10 years before the date hereof, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or became subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold such person's assets.
Penalties or Sanctions
No director, executive officer or controlling security holder of TransAlta Corporation has:
•been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority, other than penalties for late filing of insider reports; or
•been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.
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Material Contracts
Other than contracts entered into in the ordinary course of business, the Corporation believes that the following are material contracts, the particulars of which are disclosed elsewhere in this AIF, to which the Corporation or its subsidiaries are a party:
•Investment Agreement - See "Capital and Loan Structure - Investment Agreement and E&O Agreement"
•E&O Agreement - See "Capital and Loan Structure - Investment Agreement and E&O Agreement"
•Registration Rights Agreement - See "Capital Structure - Registration Rights Agreement"
•Off-Coal Agreement - See "Business of TransAlta - Alberta Thermal Business Segment - Off-Coal Agreement"
Conflicts of Interest
Circumstances may arise where members of the Board serve as directors or officers of corporations which are in competition to the interests of TransAlta. No assurances can be given that opportunities identified by such member of the Board will be provided to us. However, our policies provide that each director and executive officer must comply with the disclosure requirements of the CBCA regarding any material interest. If a declaration of material interest is made, the declaring director shall not vote on the matter if put to a vote of the Board. In addition, the declaring director and executive officer may be requested to recuse himself or herself from the meeting when such matter is being discussed.
Legal Proceedings and Regulatory Actions
TransAlta is occasionally named as a party in claims and legal proceedings that arise during the normal course of its business. We review each of these claims, including the nature of the claim, the amount in dispute or claimed and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in our favour or that such claim may not have a material adverse effect on TransAlta. For further information, please refer to Note 35 of our audited consolidated financial statements for the year ended Dec. 31, 2019, which financial statements are incorporated by reference herein. See "Documents Incorporated by Reference."
FMG Disputes
The Corporation is currently engaged in a dispute with FMG as a result of FMG’s purported termination of the South Hedland PPA. TransAlta sued FMG, seeking payments of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated. This matter has been rescheduled to proceed to trial beginning May 3, 2021, instead of June 15, 2020.
The Corporation had a second dispute involving FMG's claims against TransAlta related to the transfer of the Solomon facility to FMG. FMG claimed certain amounts relating to the condition of the facility while TransAlta claimed certain costs should be reimbursed. The dispute was settled and discontinued in the Supreme Court of Western Australia on Sept. 9, 2020.
Mangrove Complaint
On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice, naming TransAlta Corporation, the incumbent members of the Board of Directors of TransAlta Corporation on such date, and Brookfield BRP Holdings (Canada), as defendants. Mangrove is seeking to set aside the Brookfield Investment. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter has been rescheduled and the three-week trial will begin on April 19, 2021.

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Keephills 1 Stator Force Majeure Appeal
The Balancing Pool and ENMAX Energy Corporation ("ENMAX") are seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench ("ABQB") dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX, however, sought leave to appeal the ABQB’s decision at the Court of Appeal, which was granted on Feb. 13, 2020. The appeal is scheduled to be heard on April 8, 2021. TransAlta believes that the Court of Appeal will affirm the ABQB decision that the arbitration proceeding was fair.
Keephills 1 Superheater Force Majeure
Keephills Unit 1 was taken offline from March 17, 2015 to May 17, 2015, as a result of a large leak in the secondary superheater. TransAlta Generation Partnership claimed force majeure under the Keephills PPA. ENMAX, the PPA buyer under the PPA at the time, did not dispute the force majeure but the Balancing Pool did, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The Balancing Pool argued and won in the Courts that it has a right under the PPA to commence an arbitration, independent of the PPA buyer, ENMAX. An arbitration for this dispute has commenced and is set to be heard for seven days starting Dec. 6, 2021.
Hydro Power Purchase Arrangement ("Hydro PPA") Emission Performance Credits
The Balancing Pool claims to be entitled to emissions performance credits ("EPCs"), valued at approximately $17 million per year, earned by the hydro facilities under the Carbon Competitiveness Incentive Regulation from 2018-2020. The dispute is based on the ownership of the EPCs as a result of a change-in-law provision under the Hydro PPA and that TransAlta is benefiting from the purported change in law. TransAlta has not received any benefit from the EPCs and has not recognized any benefit from the EPCs within its financial statements. TransAlta believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and will be likely set down for a hearing sometime in early 2022.
Sundance A Decommissioning
TransAlta filed an application with the AUC seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and the Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. Due to various factors, including the COVID-19 pandemic and significant information requests from the Balancing Pool, the application has been delayed. While a hearing date has not been set, the application will likely be heard in late 2021 or early 2022. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain.
Direct Assigned Capital Deferral Account (“DACDA”) Application
AltaLink Management Ltd. ("AltaLink") filed an application before the AUC to recover its 2016-2018 DACDA costs (the "Proceeding") incurred for the 240 kV line upgrades project in the Edmonton region (the “Upgrades Project”). TransAlta is a secondary applicant in the Proceeding because it owns a portion of the 1043L Line located on Enoch Cree Nation Reserve that was a part of the Upgrades Project. AltaLink and TransAlta sought to have their costs ($91 million for AltaLink, and $22 million for TransAlta) approved by the AUC as reasonable and prudent. The Enoch Cree Nation and the Consumers Coalition of Alberta are registered participants in the Proceeding. The AUC rendered its decision in the Proceeding on Dec. 10, 2020 and disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta believes that the AUC made errors by disallowing 15 percent of its costs and therefore filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC. The court will be adjourned until the review and variance process is completed.
Line Loss Rule Proceeding
The Corporation has been participating in a line loss rule proceeding before the AUC. The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed AESO to recalculate loss factors for 2006 to 2016 and issue a single invoice charging or crediting market participants for the difference in loss charges. The AESO submitted a review and variance application of this decision to implement a “pay-as-you-go” invoicing scheme rather than issue a single invoice. The AUC ruled on AESO’s request and approved a three-period invoice process (2006-2009, 2010-2013, and 2014-2016). The total liability for the loss charges was $25 million; however, due to payments made (and received) for the first two invoices, only $8 million of the total liability remains outstanding. The AESO issued the first invoice on Oct. 22, 2020 for $6 million which was paid prior to Dec. 30, 2020. The second invoice was issued on Dec. 21, 2020 for $11 million. The third invoice is expected in March 2021.

In November 2020, AESO sought direction from the AUC with respect to interest payments on the loss charges, and the AUC ruled in January 2021 that simple interest (rather than compound interest) would apply to the loss charges.
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Transfer Agent and Registrar
The transfer agent and registrar for our common shares and Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares is Computershare Investor Services Inc. Common shares are transferable in Vancouver, Calgary, Toronto, Montréal and Halifax. Series A Shares, Series B Shares, Series C Shares, Series E Shares and Series G Shares are transferable in Calgary and Toronto. The transfer agent and registrar for our common shares in the United States is Computershare Trust Company at its principal office in Jersey City, New Jersey.
Interests of Experts
The Corporation's auditors are Ernst & Young LLP, Chartered Professional Accountants, 2200, 215 – 2nd Street, S.W., Calgary, Alberta, T2P 1M4.
Our auditors, Ernst & Young LLP, are independent with respect to TransAlta Corporation in the context of the Rules of Professional Conduct of the Institute of Chartered Professional Accountants of Alberta and in compliance with Rule 3520 of the Public Company Accounting Oversight Board.
Additional Information
Additional information in relation to TransAlta may be found under TransAlta's profile on SEDAR at www.sedar.com and EDGAR at www.sec.gov.    
Additional information including directors' and officers' remuneration and indebtedness, principal holders of our securities and securities authorized for issuance under equity compensation plans (all where applicable) is contained in our Management Proxy Circular for the most recent annual meeting of shareholders that involved the election of directors and can be obtained upon request from our Investor Relations department, or as filed on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
Additional financial information is provided in our audited consolidated financial statements as at and for the year ended Dec. 31, 2020, and in the related Annual MD&A, each of which is incorporated by reference in this AIF. See "Documents Incorporated by Reference."
Audit, Finance and Risk Committee
General
The members of TransAlta's Audit, Finance and Risk Committee ("AFRC") satisfy the requirements for independence under the provisions of Canadian Securities Regulators, National Instrument 52-110 Audit Committees, Section 303A of the NYSE Rules and Rule 10A-3 under the U.S. Securities and Exchange Act of 1934. The AFRC's Charter requires that it be made up of a minimum of three independent directors. The AFRC is currently comprised of four independent members: Beverlee F. Park (Chair), Alan J. Fohrer, Georgia R. Nelson and Bryan D. Pinney.
All members of the committee are financially literate pursuant to both Canadian and US securities requirements and Ms. Park and Mr. Pinney have each been determined by the Board to be an "audit committee financial expert," within the meaning of Section 407 of the United States Sarbanes Oxley Act of 2002 .
Mandate of the Audit, Finance and Risk Committee
The AFRC provides assistance to the Board in fulfilling its oversight responsibilities with respect to:
•the integrity of the Corporation's financial statements and financial reporting process,
•the systems of internal financial controls and disclosure controls established by management,
•the risk identification and assessment process conducted by management including the programs established by management to respond to such risks,
•the internal audit function,
•compliance with financial, legal and regulatory requirements and
•the external auditors' qualifications, independence and performance.
In so doing, it is the AFRC's responsibility to maintain an open avenue of communication between it and the external auditors, the internal auditors and management of the Corporation.
The function of the AFRC is oversight. Management is responsible for the preparation, presentation and integrity of the interim and annual financial statements and related disclosure documents. Management of the Corporation is also responsible for maintaining appropriate accounting and financial reporting policies and systems of internal controls and
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disclosure controls and procedures to comply with accounting standards, applicable laws and regulations that provide reasonable assurance that the assets of the Corporation are safeguarded and transactions are authorized, executed, recorded and properly reported.
While the AFRC has the responsibilities and powers set forth herein, it is not the duty of the AFRC to plan or conduct audits or to determine that the Corporation's financial statements are complete and accurate and in accordance with generally accepted accounting principles. This is the responsibility of management and the external auditors.
The AFRC must also designate at least one member as an "audit committee financial expert." The designation of a member or members as an "audit committee financial expert" is based on that individual's education and experience, which the individual will bring to bear in carrying out his or her duties on the AFRC. Designation as an "audit committee financial expert" does not impose on such person any duties, obligations and liability that are greater than the duties, obligations and liability imposed on another member of the AFRC and Board in the absence of such designation.
Management is also responsible for the identification and management of the Corporation's risks and the development and implementation of policies and procedures to mitigate such risks. The AFRC's role is to provide oversight in order to ensure that the Corporation's assets are protected and safeguarded within reasonable business limits. The AFRC reports to the Board on its risk oversight responsibilities.
Audit, Finance and Risk Committee Charter
The Charter of the AFRC is attached as Appendix "A".
Relevant Education and Experience of Audit, Finance and Risk Committee Members
The following is a brief summary of the education or experience of each member of the AFRC that is relevant to the performance of his or her responsibilities as a member of the AFRC, including any education or experience that has provided the member with an understanding of the accounting principles that we use to prepare our annual and interim financial statements.
Name of AFRC Member Relevant Education and Experience
Georgia R. Nelson Mrs. Nelson holds a Master of Business Administration from the University of Southern California. She is the former Principal Officer and President of Midwest Generation and has more than 10 years of audit committee service on other public company boards.
Alan J. Fohrer Prior to his retirement in December 2010, Mr. Fohrer was Chairman and CEO of SCE, a subsidiary of Edison and one of the largest electric utilities in the United States. Prior to that, Mr. Fohrer served as Executive Vice-President, Treasurer and Chief Financial Officer of both Edison and SCE. Mr. Fohrer also serves on the audit committee of PNM Resources Inc., a public company.
Beverlee . F. Park (Chair) Ms. Park has executive experience in a range of industries, including forest products, shipping, mining, transportation, real estate, and electricity transmission. Ms. Park spent 17 years of her career with TimberWest Forest Corp. where she was most recently Chief Operations Officer. Over that time, she also held the roles of Interim Chief Executive Officer, President of the real estate division (Couverdon Real Estate) and Executive Vice President and Chief Financial Officer. Ms. Park is currently a director of SSR Mining Inc. where she chairs the Audit Committee. She was formerly a director of Teekay LNG Partners, InTransit BC and BC Transmission Corp. where she chaired the audit committees of all these boards. Ms. Park holds a Bachelor of Commerce with distinction from McGill University, a Master of Business Administration from the Simon Fraser University Executive program and is a Chartered Accountant. She is named a Fellow of the Chartered Professional Accountants of British Columbia in 2011.
Bryan D. Pinney Mr. Pinney has more than 30 years of experience in financial auditing, valuation and advising companies in energy and natural resources. He has been an independent director of North American Construction Group Ltd. since 2015 and its lead director since Oct. 31, 2017. He is also a director of Sundial Growers Inc., a NASDAQ-listed company, where he also serves as Chair of the Audit & Risk Committee. He served as member of Deloitte’s Board of Directors and chair of the Finance and Audit Committee. He was the recent Chair of the Board of Governors and member of the Board of Governors of Mount Royal University and has previously served on a number of non-profit boards. He has been an independent non-executive director at Persta Resources Inc., a Hong Kong listed oil and gas exploration company. He has been a Chartered Accountant since December 1978, a Fellow of the Chartered Professional Accountants of Alberta since January 2009 and a Chartered Business Valuator of Canada since December 1990. Mr. Pinney obtained a Bachelor of Arts in business administration from the University of Western Ontario in 1975 and also completed the Directors Education Program offered by the Institute of Corporate Directors in Canada in 2012.
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Other Board Committees
In addition to the AFRC, TransAlta has three other standing committees: the Governance, Safety and Sustainability Committee, the Human Resources Committee and the Investment Performance Committee. The members of these committees as at Dec. 31, 2020 are:
Governance, Safety and Sustainability Committee Human Resources Committee
Chair: Rona H. Ambrose
Chair: Bryan D. Pinney
Sandra R. Sharman Rona H. Ambrose
Yakout Mansour Sandra R. Sharman
Alan J. Fohrer Beverlee F. Park
Investment Performance Committee
Chair: Yakout Mansour
Georgia Nelson
Harry Goldgut
Richard Legault

Charters of the Governance, Safety and Sustainability Committee, the Human Resources Committee and the Investment Performance Committee may be found on our website under Governance, Board Committees at www.transalta.com. Further information about the Board and our corporate governance may also be found on our website or in our Management Proxy Circular which is filed on SEDAR at www.sedar.com and EDGAR at www.sec.gov.
For the years ended Dec. 31, 2020 and Dec. 31, 2019, Ernst & Young LLP and its affiliates billed $4,253,798 and $4,171,813, respectively, as detailed below:
Fees Paid to Ernst & Young LLP
Ernst & Young LLP
Year Ended December 31 2020 2019
Audit Fees(1)
$ 2,273,888 $ 2,475,985
Audit-related fees(1)(2)
1,122,771 1,356,412
Tax fees 857,139 339,415
All other fees —  — 
Total $ 4,253,798 $ 4,171,813
(1) Comparative figures have been reclassified to confirm to the current periods classification of fees.
(2) Included in the audit-related fees are $722,733 (2019 - $905,580) of fees billed to TransAlta Renewables.

No other audit firms provided audit services in 2020 or 2019.
The nature of each category of fees is described below:
Audit Fees
Audit fees are for professional services rendered for the audit and review of our financial statements or services provided in connection with statutory and regulatory filings and providing comfort letters associated with securities documents.
Audit-Related Fees
Assurance and related services that are reasonably related to the performance of the audit or review of our financial statements that are not included under "Audit Fees". Audit-related fees include statutory audits, pension audits and other compliance audits. In 2020 and 2019, we have included the fees billed to TransAlta Renewables, a controlled and consolidated subsidiary of TransAlta.
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Tax Fees
Tax fees are tax-related services for review of tax returns, assistance with questions on tax audits, and tax planning.
All Other Fees
Products and services provided by the 'Corporation's auditor other than those services reported under "Audit Fees", "Audit-Related Fees" and "Tax Fees." This includes fees related to training services provided by the auditor.
Pre-Approval Policies and Procedures
The AFRC has considered whether the provision of services other than audit services is compatible with maintaining the auditors' independence. In May 2002, the AFRC adopted a policy that prohibits TransAlta from engaging the auditors for "prohibited" categories of non-audit services and requires pre-approval of the AFRC for other permissible categories of non-audit services, such categories being determined under the Sarbanes Oxley Act. This policy also provides that the Chair of the AFRC may approve permissible non-audit services during the quarter and report such approval to the AFRC at its next regularly scheduled meeting.

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Appendix "A"
TransAlta Corporation
(the “Corporation”)
Audit, Finance and Risk Committee Charter

A.    Establishment of Committee and Procedures

1.    Composition of Committee

The Audit, Finance and Risk Committee (the "Committee") of the Board of Directors (the "Board") of TransAlta Corporation (the "Corporation") shall consist of not less than three Directors. All members of the Committee shall be determined by the Board to be independent as required under the provisions of Canadian Securities Regulators' Multilateral Instrument 52-110 Audit Committees, Section 303A of the New York Stock Exchange rules and Rule 10A-3 of the U.S. Securities and Exchange Act of 1934, as such rules apply to audit committee members. All members of the Committee must be financially literate pursuant to both Canadian and U.S. securities requirements and at least one member must be determined by the Board to be an "audit committee financial expert" within the meaning of Section 407 of the Sarbanes-Oxley Act of 2002 (the "Sarbanes-Oxley Act"). Determinations as to whether a particular director satisfies the requirements for membership on the Committee shall be made by the Board at the recommendation of the Governance, Safety and Sustainability Committee (the "GSSC").

2.    Appointment of Committee Members

Members of the Committee shall be appointed from time to time by the Board, on the recommendation of the GSSC, 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 Corporation.

3.    Vacancies

Where a vacancy occurs at any time in the membership of the Committee, it may be filled by the Board and on the recommendation of the GSSC. The Board shall fill any vacancy if the membership of the Committee is less than three directors.

4.    Committee Chair

The Board shall appoint a Chair for the Committee on the recommendation of the GSSC.
5.    Absence of Committee Chair

If the Chair of the Committee is not present at any meeting of the Committee, one of the members of the Committee who is present at the meeting shall be chosen by the Committee to preside at the meeting.

6.    Secretary of Committee

The Committee shall appoint a Secretary who need not be a director of the Corporation.

7.    Meetings

The Chair of the Committee may call a regular meeting of the Committee. The Committee shall meet at least quarterly and at such other time during each year as it deems appropriate to fulfil its responsibilities. In addition, the Chair of the Committee or any two members may call a special meeting of the Committee at any time.

The Committee shall also meet in separate executive session.

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8.    Quorum

A majority of the members of the Committee, present in person or by telephone or other telecommunication device that permits all persons participating in the meeting to speak to each other shall constitute a quorum.

9.    Notice of Meetings

Notice of the time and place of every meeting shall be given in writing (including by way of written facsimile communication or email) to each member of the Committee at least 48-hours prior to the time fixed for such meeting, provided, however, that a member may in any manner waive notice of a meeting; and attendance of a member at a meeting constitutes a waiver of notice of the meeting, except where a member attends for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called. Notice of every meeting shall also be provided to the external and internal auditors.

10.    Attendance at Meetings

At the invitation of the Chair of the Committee, other Board members, the President and Chief Executive Officer ("CEO"), other officers or employees of the Corporation, the external auditors, and other experts or consultants may attend a meeting of the Committee.

11.    Procedure, Records and Reporting

Subject to any statute or the articles and by-laws of the Corporation, the Committee shall fix its own procedures at meetings, keep records of its proceedings and report to the Board generally not later than the next scheduled meeting of the Board.

12.    Review of Charter and Evaluation of Committee

The Committee shall evaluate its performance and review and assess the adequacy of its Charter at least annually or otherwise, as it deems appropriate. All changes proposed by the Committee are reviewed and approved by the GSSC and the Board.

13.    Outside Experts and Advisors

In consultation with the Board, the Committee Chair, on behalf of the Committee or any of its members, is authorized, at the expense of the Corporation, when deemed necessary or desirable, to retain independent counsel, outside experts and other advisors to advise the Committee independently on any matter. The retention of such counsel, expert or advisor in no way requires the Committee to act in accordance with the recommendations of such counsel, expert or advisor.


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B.    Duties and Responsibilities of the Chair

The fundamental responsibility of the Chair of the Committee is to effectively manage the duties of the Committee.

The Chair is responsible for:

1.    Chairing meetings of the Committee and ensuring that the Committee is properly organized so that it functions effectively and meets its obligations and responsibilities.

2.    Establishing the frequency of Committee meetings, duly convening the same and confirming that quorum is present when required.

3.    Working with the CEO, the Chief Financial Officer (the "CFO"), the Corporate Secretary and Assistant Corporate Secretary, as applicable, on the development of agendas and related materials for the meetings.

4.    Providing leadership to the Committee and assisting the Committee in ensuring the proper and timely discharge of its responsibilities.

5.    Reporting to the Board on the recommendations and decisions of the Committee.

The Chair of the Committee shall review all expense accounts and perquisites of the Chair of the Board and the CEO not less than quarterly to ensure compliance with the Corporation’s policies, and shall report to the Committee on an annual basis.

C.    Mandate of the Committee

The Committee provides assistance to the Board in fulfilling its oversight responsibilities with respect to i) the integrity of the Corporation's financial statements and financial reporting process, ii) the systems of internal financial controls and disclosure controls established by Management, iii) the risk identification and assessment process conducted by Management including the programs established by Management to respond to such risks, iv) the internal audit function, v) compliance with financial, legal and regulatory requirements and vi) the external auditors' qualifications, independence and performance. In so doing, it is the Committee's responsibility to maintain an open avenue of communication between it and the external auditors, the internal auditors and Management of the Corporation.

The function of the Committee is oversight. Management is responsible for the preparation, presentation and integrity of the interim and annual financial statements and related disclosure documents. Management of the Corporation is also responsible for maintaining appropriate accounting and financial reporting policies and systems of internal controls and disclosure controls and procedures to comply with accounting standards, applicable laws and regulations which provide reasonable assurance that the assets of the Corporation are safeguarded and transactions are authorized, executed, recorded and properly reported.

While the Committee has the responsibilities and powers set forth herein, it is not the duty of the Committee to plan or conduct audits or to determine that the Corporation's financial statements are complete and accurate and in accordance with generally accepted accounting principles. This is the responsibility of Management and the external auditors.

The Committee must also designate at least one member as an "audit committee financial expert." The designation of a member or members as an "audit committee financial expert" is based on that individual's education and experience, which the individual will bring to bear in carrying out his or her duties on the Committee. Designation as an "audit committee financial expert" does not impose on such person any duties, obligations and liability that are greater than the duties, obligations and liability imposed on another member of the Committee and Board in the absence of such designation.

Management is also responsible for the identification and management of the Corporation's risks and the development and implementation of policies and procedures to mitigate such risks. The Committee's role is to provide oversight in order to ensure that the Corporation's assets are protected and safeguarded within reasonable business limits. The Committee reports to the Board on its risk oversight responsibilities.

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D.    Duties and Responsibilities of the Committee

1.    Financial Reporting, External Auditors and Financial Planning

A)    Duties and Responsibilities Related to Financial Reporting and the Audit Process

(a)    Review with Management and the external auditors the Corporation's financial reporting process the work to be conducted in conjunction with the annual audit and the preparation of the financial statements, including, without limitation, the annual audit plan of the external auditors, the judgment of the external auditors as to the quality, not just the acceptability, of and the appropriateness of the Corporation's accounting principles as applied in its financial reporting and the degree of aggressiveness or conservatism of the Corporation's accounting principles and underlying estimates;

(b)    Review with Management and the external auditors the Corporation's audited annual financial statements, including the notes thereto, "Management's Discussion and Analysis," the related earnings release, and recommend their approval to the Board for release to the public;

(c)    Review with Management and the external auditors the Corporation's interim financial statements, including the notes thereto, "Management's Discussion and Analysis," the related earnings release, and approve their release to the public as required;

(d)    In reviewing the financial statements and related financial disclosure, the Committee shall review and discuss with Management and the external auditors:

(i)    any changes in accounting principles, practices or policies considering their applicability to the business and financial impact;

(ii)    Management's processes for formulating sensitive accounting estimates and the reasonableness of the estimates;

(iii)    the use of "pro forma" or "non-comparable" information and the applicable reconciliation;

(iv)    alternative treatments of financial information within generally accepted accounting principles that have been discussed between Management and the auditors, ramifications of the use of such alternative disclosures and treatments and the treatment preferred by the external auditors; and

(v)    disclosures made to the Committee by the CEO and CFO during their certification process for the relevant periodic/annual report filed with securities regulators to ensure that information required to be disclosed is recorded, processed, summarized and reported within the time periods specified for the reporting period. Obtain assurances from the CEO and CFO as to the adequacy and effectiveness of the Corporation's disclosure controls and procedures and systems of internal control over financial reporting and that any fraud involving Management or other employees who have a significant role in the Corporation's internal controls is reported to the Committee.

(e)    In reviewing the financial statements and related financial disclosure, the Committee shall also, with the external auditors:

(i)    discuss the cooperation they received from Management during the course of their review and their access to all records, data and information requested; and

(ii)    satisfy itself that there are no unresolved issues between Management and the external auditors that could reasonably be expected to materially affect the financial statements.

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(f)    Review quarterly with senior Management, the Chief Legal and Compliance Officer (or, as necessary, outside legal advisors), and the Corporation's internal and external auditors, the effectiveness of the Corporation's internal controls to ensure the Corporation is in compliance with legal and regulatory requirements and the Corporation's policies;

(g)    Review with Management and the external auditors the processes relating to the assessment of potential fraud, programs and controls to mitigate the risk of fraud, and the processes put in place for monitoring the risks within the targeted areas; and

(h)    Discuss with Management and the external auditors any correspondence from or with regulators or governmental agencies, any employee complaints or any published reports that raise material issues regarding the Corporation's financial statements or accounting policies.

B)    Duties and Responsibilities Related to the External Auditors

(a)    The Committee shall have direct responsibility for the compensation and oversight of the external auditors including nominating the external auditors to the Board for appointment by the shareholders at the Corporation's general annual meeting. In performing its function, the Committee shall:

(i)    review and approve annually the external auditors audit plan;

(ii)    review and approve the basis and amount of the external auditors' fees and ensure the Corporation has provided appropriate funding for payment of compensation to the external auditors;

(iii)    subject to the delegation granted to the Chair of the Committee, pre-approve all audit related services including all non-prohibited non-audit services provided by the external auditors; the Chair of the Committee is authorized to approve all audit related services including non-prohibited non-audit services provided by the external auditors, and shall report all such approvals to the Committee at its next scheduled meeting;

(iv)    review and discuss annually with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors' independence, including, without limitation, (a) requesting, receiving and reviewing, at least annually, a formal written statement from the external auditors delineating all relationships that may reasonably be thought to bear on their independence with the Corporation; (b) discussing with the external auditors any relationships or services that the external auditors believe may affect their objectivity and professional skepticism; (c) reviewing with the external auditors the experience and qualifications of the senior personnel who are providing audit services to the Corporation; (d) reviewing the quality control procedures of the external auditors, including obtaining confirmation that the external auditors are in compliance with Canadian and U.S. regulatory registration requirements; and (e) evaluating the communication and interaction with the external auditor including quality of service considerations;

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(v)    in the year preceding the change of the lead (or coordinating) audit partner (having primary responsibility for the audit), and in any event not less than every five years, perform a comprehensive review of the external auditor which takes into consideration (a) the impact of the tenure of the audit firm on audit quality, trends in the audit firm's performance and expertise in the industry, incidences of independence threats and the effectiveness of safeguards to mitigate those threats, (b) the responsiveness of the audit firm to changes in the entity's business and suggestions for improvement from regulators, the audit committee and/or management, (c) the consistency and rigour of the professional skepticism applied by the external auditor, and the quality of the engagement team and its communications, review of Canadian Public Accountability Board (CPAB) inspection findings since the previous comprehensive review and how the audit firm responded to these findings, and following this comprehensive review, determine whether the audit firm should be nominated to the Board as the external auditors for appointment by the shareholders at the Corporation's next general annual meeting;

(vi)    inform the external auditors and Management that the external auditors shall have direct access to the Committee at all times, as well as the Committee to the external auditors;

(vii)    instruct the external auditors that they are ultimately accountable to the Committee as representatives of the shareholders of the Corporation; and

(viii)    at least annually, obtain and review the external auditors' report with respect to the auditing firm's internal quality-control procedures, any material issues raised by the most recent internal quality-control review or peer review of the auditing firm, any inquiry or investigation by governmental or professional authorities within the preceding five years undertaken respecting one or more independent audits carried out by the external auditors, and any steps taken to deal with any such issues.

C)    Duties and Responsibilities Related to Financial Planning

(a)    Review and recommend to the Board for approval the Corporation's issuance and redemption of securities (including the review of all public filings to effect any of the issuances or redemptions), financial commitments and limits, and any material changes underlying any of these commitments;

(b)    Review annually the Corporation's annual tax plan;

(c)    Receive regular updates with respect to the Corporation's financial obligations, loans, credit facilities, credit position and financial liquidity;

(d)    Review annually with Management the Corporation's overall financing plan in support of the Corporation's capital expenditure plan and overall budget/medium range forecast; and

(e)    Review with Management at least annually the approach and nature of earnings guidance and financial information to be disclosed to analysts and rating agencies.


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2.    Internal Audit

(a)    Approve whether the internal audit function should be outsourced and if outsourced, approve the audit firm to perform such internal audit service; provided that in no event shall the external auditor be retained to also perform the internal audit function;

(b)    Review and consider, as appropriate, any significant reports and recommendations made by internal audit relating to internal audit issues, together with Management's response thereto;

(c)    Review annually the scope and plans for the work of the internal audit group, the adequacy of the group's resources, the internal auditors' access to the Corporation's records, property and personnel;

(d)    Recognize and advise senior Management that the internal auditors shall have unfettered access to the Committee, as well as the Committee to the internal auditors;

(e)    Meet separately with Management, the external auditors and internal auditors to review issues and matters of concern respecting audits and financial reporting;

(f)    Review with the Corporation's senior financial Management and the internal audit group the adequacy of the Corporation's systems of internal control and procedures; and

(g)     Recommend to the Human Resources Committee the appointment, termination or transfer of the lead individual responsible for internal audit, provided that if the internal audit function has been, or is being, outsourced to an audit firm, the Committee itself shall approve the appointment, termination or transfer of such audit firm.

3.    Risk Management

The Board is responsible for ensuring that the Corporation has adopted processes and key policies for the identification, assessment and management of its principal risks. The Board has delegated to the Committee the responsibility for the oversight of Management's identification, and evaluation, of the Corporation's principal risks, and the implementation of appropriate policies, processes and systems to manage or mitigate the risks within the Corporation's risk appetite. The Committee reports to the Board thereon.
The Committee shall:

(a)    Review, at least quarterly, Management's assessment of the Corporation's principal risks; discuss with Management the processes for the identification of these risks and the efficacy of the policies and procedures for mitigating and/or addressing these risks;

(b)    Receive and review Managements' quarterly risk update including an update on residual risks;

(c)    Review the Corporation's enterprise risk management framework and reporting methodology;

(d)    Review annually the Corporation's Financial and Commodity Exposure Management Policies and approve changes to such policies;

(e)    Review and approve the Corporation's strategic hedging program, guidelines and risk tolerance;

(f)    Review and monitor quarterly results of financial and commodity exposure management activities, including foreign currency and interest rate risk strategies, counterparty credit exposure and the use of derivative instruments;

(g)    Review the Corporation's annual insurance program, including the risk retention philosophy, potential exposure and corporate liability protection programs;

(h)    Periodically consider the respective roles and responsibilities of the external auditor, the internal audit department, internal and external counsel concerning risk management and review their performance in relation to such roles and responsibilities; and

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(i)    Annually, together with Management, report and review with the Board:

(i)    the Corporation's principal risks and overall risk appetite/profile;

(ii)    the Corporation's strategies in addressing its risk profile;

(iii)    the processes, policies, procedures and controls in place to manage or mitigate the principal risks; and

(iv)    the overall effectiveness of the enterprise risk management process and program.

4.    Governance

A)    Public Disclosure, Legal and Regulatory Reporting

(a)    On behalf of the Committee, the Chair shall review all public disclosure inclusive of material financial information extracted or derived from the Corporation's financial statements prior to dissemination to the public;

(b)    Review quarterly with the Chief Legal and Compliance Officer, and, if necessary, outside legal advisors, significant legal, compliance or regulatory matters that may have a material effect on the Corporation's financial statements;

(c)    Discuss with the external auditors their perception of the Corporation's financial and accounting personnel, any recommendations which the external auditors may have, including those contained in the Management letter, with respect to improving internal financial controls, choice of accounting principles or management reporting systems, and review all Management letters from the external auditors together with Management's written responses thereto;

(d)    Review with Management, the external auditors and internal legal counsel (external counsel if necessary), any litigation, claim or contingency, including tax assessments, that could have a material effect upon the financial position of the Corporation, and the manner in which these may be or have been disclosed in the financial statements;

(e)    Review annually the Insider Trading Policy and approve changes as required; and

(f)    Review annually the Corporation's Disclosure Policy and Social Media Policy to ensure continued applicability with the law and the Corporation's disclosure principles.

B)    Pension Plan Governance

(a)    Review annually the Annual Pension Report and financial statements of the Corporation's pension plans including the actuarial valuation, asset/liability forecast, asset allocation, manager performance and plan operating costs, and reporting thereon to the Board annually; and

(b)    Together with the Human Resources Committee of the Board, review annually, and as required, the overall governance of the Corporation's Pension Plans, approving the broad objectives of the plans, the statement of investment policy, the appointment of investment managers, and reporting thereon to the Board annually.

C)    Information Technology – Cybersecurity

(a)    Receive bi-annually a system status update with respect to the Corporation's core IT operating systems; and

(b)    Review annually the Corporation's cybersecurity programs and their effectiveness. Receive an update on the Corporation's compliance program for cyber threats and security.


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D)    Administrative Responsibilities

(a)    Review the annual audit of expense accounts and perquisites of the Directors, the CEO and the CEO's direct reports and their use of corporate assets;

(b)    Establish procedures for the receipt, retention and treatment of complaints relating to securities law, accounting, internal accounting controls, auditing or financial reporting matters, and potential ethical or legal violations;

(c)    Review all incidents, complaints or information reported through the Ethics Help Line addressed to the Committee or relating to potential or suspected material breaches of securities laws, accounting, internal accounting controls, auditing or financial reporting matters and any material ethical or legal violation;

(d)    Establish procedures for the investigation of complaints or allegations, and, in respect of potentially material complaints or allegations, report to the Board thereon and ensure that appropriate action is taken as necessary to address such matter;

(e)    Review and consider any related party transaction and to recommend, if necessary, the use of a standing committee or an ad hoc special committee to assist the Board in the evaluation of any such related party transaction;
(f)    Review and approve the Corporation's hiring policies for employees or former employees of the external auditors and monitor the Corporation's adherence to the policy; and

(g)    Report annually to shareholders on the work of the Committee during the year.

E.    Compliance and Powers of the Committee

(a)    The responsibilities of the Committee comply with applicable Canadian laws and regulations, such as the rules of the Canadian Securities Administrators, and with the disclosure and listing requirements of the Toronto Stock Exchange, as they exist on the date hereof. In addition, this Charter complies with applicable U.S. laws, such as the Sarbanes-Oxley Act and the rules and regulations adopted thereunder, and with the New York Stock Exchange's corporate governance standards, as they exist on the date hereof.

(b)    The Committee may, at the request of the Board or on its own initiative, investigate such other matters as are considered necessary or appropriate in carrying out its mandate.

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Appendix "B"
Glossary of Terms
This Annual Information Form includes the following defined terms:
"AESO" – Alberta Electric System Operator.
"Air emissions" – Substances released to the atmosphere through industrial operations. For the fossil-fuel-fired power sector, the most common air emissions are sulphur dioxide, oxides of nitrogen, mercury, and GHGs.
"Alberta PPA" – Alberta Power Purchase Arrangement – A long-term arrangement established by regulation for the sale of electric energy from formerly regulated generating units to PPA buyers.
"AUC" – Alberta Utilities Commission.
"Availability" – A measure of time, expressed as a percentage of continuous operation 24 hours a day, 365 days a year that a generating unit is capable of generating electricity, regardless of whether or not it is actually generating electricity.
"Balancing Pool" – The Balancing Pool was established in 1999 by the Government of Alberta to help manage the transition to competition in Alberta's electric industry. Their current obligations and responsibilities are governed by the Electric Utilities Act (effective June 1, 2003) and the Balancing Pool Regulation. For more information, please go to www.balancing pool.ca
"Boiler" – A device for generating steam for power, processing or heating purposes, or for producing hot water for heating purposes or hot water supply. Heat from an external combustion source is transmitted to a fluid contained within the tubes of the boiler shell.
"Capacity" – The rated continuous load-carrying ability, expressed in megawatts, of generation equipment.
"Cogeneration" – A generating facility that produces electricity and another form of useful thermal energy (such as heat or steam) used for industrial, commercial, heating, or cooling purposes.
"Combined-cycle" – An electric generating technology in which electricity is produced from otherwise lost waste heat exiting from one or more gas (combustion) turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine in the production of electricity. This process increases the efficiency of the electric generating unit.
"E2SG" – Economic, Environmental, Social and Governance
"Force majeure" – Literally means "greater force." These clauses excuse a party from liability if some unforeseen event beyond the control of that party prevents it from performing its obligations under the contract.
"GGPPA" – Greenhouse Gas Pollution Pricing Act (Canada).
"GHG" – Greenhouse gases having potential to retain heat in the atmosphere, including water vapour, carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, and perfluorocarbons.
"Gigawatt" – A measure of electric power equal to 1,000 MW.
"GWh" – Gigawatt hour – A measure of electricity consumption equivalent to the use of 1,000 megawatts of power over a period of one hour.
"IESO" – Independent Electricity System Operator.
"LTC" – Long-term contract.
"MW" – Megawatt – A measure of electric power equal to 1,000,000 watts.
"MWh" – Megawatt hour – A measure of electricity consumption equivalent to the use of 1,000,000 watts of power over a period of one hour.
"Net capacity" – The maximum capacity or effective rating, modified for ambient limitations, that a generating unit or power plant can sustain over a specific period, less the capacity used to supply the demand of station service or auxiliary needs.
"NOx" – Nitrogen oxide.
B- 1

"ppmvd" – Parts per million by volume, dry basis.
"OBPS" – Output- Based Pricing Standard.
"Off-Coal Agreement" – Off-Coal Agreement dated Nov. 24, 2016 between, among others, TransAlta and Her Majesty the Queen in Right of Alberta.
"PPA" – Purchase power agreement.
"Renewables PPA" – Long-term power purchase agreements with certain subsidiaries of TransAlta Renewables providing for the purchase by TransAlta, for a fixed price, of all of the power produced at such subsidiaries.
"TA Cogen" – TransAlta Cogeneration LP.
"CO2e/GWh" – Carbon dioxide equivalent per gigawatt hour.
"CO2e/MWH" – Carbon dioxide equivalent per megawatt hour
"TSX" – Toronto Stock Exchange.

B- 2
Management’s Discussion and Analysis



Table of Contents
 
Business Model
M2
Competitive Forces
M56
Forward-Looking Statements
M3
Power-Generating Portfolio Capital
M58
Corporate Strategy
M5
Other Consolidated Analysis
M59
Highlights
M10
Critical Accounting Policies and Estimates
M63
Significant and Subsequent Events
M12
Accounting Changes
M70
Segmented Comparable Results
M16
Financial Instruments
M72
Additional IFRS Measures and Non-IFRS Measures
M28
Environment, Social and Governance ("ESG")
M74
Discussion of Consolidated Financial Results
M29
    Reliable, Low-Cost and Sustainable Energy Production
M76
Fourth Quarter
M33
    Natural Capital Management
M79
Discussion of Consolidated Financial Results for the
Fourth Quarter
M35
    Climate Change Management
M88
    Human Capital Management
M97
Selected Quarterly Information
M38
    Social and Relationship Capital Management
M101
Key Financial Ratios
M39
    Manufactured Capital Management
M107
Financial Position
M44
    2020 Sustainability Targets Performance
M109
Cash Flows
M46
    2021+ Sustainable Targets
M111
Financial Capital
M47
Governance and Risk Management
M113
2021 Financial Outlook
M53
Disclosure Controls and Procedures
M126
 
 
 
 
 
 
  
 
 




 
 
 
 
 
 






This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our 2020 audited annual consolidated financial statements (the "consolidated financial statements") and our 2020 annual information form ("AIF"), each for the fiscal year ended Dec. 31, 2020. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”) for Canadian publicly accountable enterprises as issued by the International Accounting Standards Board (“IASB”) and in effect at Dec. 31, 2020. All dollar amounts in the tables are in millions of Canadian dollars unless otherwise noted and except amounts per share, which are in whole dollars to the nearest two decimals. All other dollar amounts in this MD&A are in Canadian dollars, unless otherwise noted. This MD&A is dated March 2, 2021. Additional information respecting TransAlta Corporation (“TransAlta”, “we”, “our”, “us” or the “Corporation”), including our AIF, is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov and on our website at www.transalta.com. Information on or connected to our website is not incorporated by reference herein.




TRANSALTA CORPORATION M1

Management’s Discussion and Analysis

Business Model
Our Business
We are one of Canada’s largest publicly traded power generators with over 109 years of operating experience. We own, operate and manage a highly contracted and geographically diversified portfolio of assets representing 8,128 megawatts ("MW")(1) of capacity and use a broad range of fuels that include water, wind and solar, natural gas, and thermal coal. The Corporation is currently undertaking a multi-year transition to convert or retire all of our thermal coal units completely by the end of 2025. This transition will see our thermal units in Alberta discontinue all firing with thermal coal and the discontinuation of all coal mining operations by the end of Dec. 31, 2021. Our Centralia coal-fired facility in Washington State is committed to be retired under the TransAlta Energy Transition Bill. Consistent with our commitment under this bill, Centralia Unit 1 retired on Dec. 31, 2020, and the remaining unit is set to retire on Dec. 31, 2025. Our energy marketing operations maximize margins by securing and optimizing high-value products and markets for ourselves and our customers in dynamic market conditions.

Vision and Values
Our vision is to be a leader in clean electricity and we are committed to a sustainable future. Our mission is to provide safe, low-cost and reliable clean electricity. With our 109-year history of powering economies and communities, we apply our expertise, scale and diversified fuel mix to capitalize on opportunities in our core markets and grow in areas where our competitive advantages can be employed. Our values are grounded in safety, innovation, sustainability, integrity and respect, all of which enable us to work towards our common goals. These values are the principles that define our corporate culture. They reflect our skills and mindset, while providing a framework for everything we do, guiding both internal conduct and external relationships. These values are at the heart of our success.

Strategy for Value Creation
Our goals are to deliver shareholder value by delivering solid returns through a combination of dividend yield and disciplined growth in cash flow per share. We strive for a low to moderate risk profile over the long term while balancing capital allocation and maintaining financial strength to allow for financial flexibility. Our segmented cash flow growth is driven by optimizing and diversifying our existing assets and further expanding our overall portfolio and presence in Canada, the United States of America ("US") and Australia. We are focusing on these geographic areas as our expertise, scale and diversified fuel mix create a competitive advantage that we can leverage to capture expansion opportunities to create shareholder value.

Material Sustainability Impacts
Sustainability means ensuring that our financial returns consider short- and long-term economics, environmental impacts and societal and community needs. We refer to this as E2SG. This MD&A integrates our financial or economics ("E") and sustainability or environment, social and governance (“ESG”) reporting. Key elements of our sustainability disclosure are guided by our sustainability materiality assessment. To help inform discussion and provide context on how E2SG affects our business, we have referenced the provincial securities commission guidance, Global Reporting Initiative, Sustainability Accounting Standards Board and the Task Force on Climate-related Financial Disclosures. Our content is structured following guidance on non-traditional capitals from the International Integrated Reporting Framework. In addition, we track the performance of 80 sustainability-related Key Performance Indicators ("KPIs") and have obtained a limited assurance report from Ernst & Young LLP over material KPIs.

(1) We measure capacity as net maximum capacity (see the Glossary of Key Terms for the definition of this and other key terms), which is consistent with industry standards. Capacity figures represent capacity owned and in operation unless otherwise stated, and reflect the basis of consolidation of underlying assets.





TRANSALTA CORPORATION M2
Management’s Discussion and Analysis

Forward-Looking Statements
This MD&A includes "forward-looking information" within the meaning of applicable Canadian securities laws, and "forward-looking statements" within the meaning of applicable US securities laws, including the US Private Securities Litigation Reform Act of 1995 (collectively referred to herein as "forward-looking statements"). All forward-looking statements are based on our beliefs as well as assumptions based on information available at the time the assumption was made, and on management's experience and perception of historical trends, current conditions and expected future developments, as well as other factors deemed appropriate in the circumstances. Forward-looking statements are not facts, but only predictions and generally can be identified by the use of statements that include phrases such as "may," "will," "can," "could," "would," "shall," "believe," "expect," "estimate," "anticipate," "intend," "plan," "forecast," "foresee," "potential," "enable," "continue" or other comparable terminology. These statements are not guarantees of our future performance, events or results and are subject to risks, uncertainties and other important factors that could cause our actual performance, events or results to be materially different from that set out in or implied by the forward-looking statements.

In particular, this MD&A contains forward-looking statements including, but not limited to: operating performance and transition to clean power generation, including our goal to eliminate coal as a fuel source in the Alberta thermal fleet by 2021; our Clean Energy Investment Plan and the benefits thereof; transitioning to 100 per cent clean electricity by 2025; the source of funding for the Clean Energy Investment Plan; our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2021 and beyond, including potential for growth in renewables and on-site and cogeneration assets, including the demand therefor and greenfield development acquisitions; the amount of capital allocated to new growth or development projects and the funding thereof; our business, anticipated future financial performance and anticipated results, including our outlook and performance targets; our expectation that the sale of TransAlta's interest in the Pioneer Pipeline will close in 2021; receiving funding under the Canada Emergency Wage Subsidy program; the ability to reach a commercial solution with Energy Transfer Canada regarding the construction and operation of the Kaybob 3 cogeneration facility; the timing and the completion of growth and development projects, and their attendant costs; our estimated spend on growth and sustaining capital and productivity projects; expectations in terms of the cost of operations and maintenance, and the variability of those costs; the conversion or repowering of our coal-fired units to natural gas, and the timing and costs thereof; expectations relating to the benefits of the conversions and repowering; the terms of the current or any further proposed share buyback programs, including timing and number of shares to be repurchased pursuant to any normal course issuer bid and the acceptance thereof by the Toronto Stock Exchange ("TSX"); the mothballing of certain units; the impact of certain hedges on future earnings, results and cash flows; estimates of fuel supply and demand conditions and the costs of procuring fuel; expectations for demand for electricity, including for clean energy, in both the short term and long term, and the resulting impact on electricity prices; the impact of load growth, increased capacity and natural gas and other fuel costs on power prices; expectations in respect of generation availability, capacity and production; expectations regarding the role that different energy sources will play in meeting future energy needs; expected financing of our capital expenditures; expected governmental regulatory regimes and legislation, as well as the cost of complying with resulting regulations and laws; our marketing and trading strategy and the risks involved in these strategies; estimates of future tax rates, future tax expense and the adequacy of tax provisions; changes in accounting estimates and accounting policies; the mitigation of risks and effectiveness thereof, including as it pertains to climate change risk, environmental management, cybersecurity, commodity prices and fuel supply; anticipated growth rates and competition in our markets; our expectations and obligations and anticipated liabilities relating to the outcome of existing or potential legal and contractual claims, regulatory investigations and disputes, including the litigation with Fortescue Metals Group Ltd. relating to the South Hedland facility and the Mangrove (as defined below) proceedings relating to the Brookfield Investment, each discussed further below; our ability to achieve our E2SG targets; expectations regarding the renewal of collective bargaining agreements; expectations for the ability to access capital markets at reasonable terms; the estimated impact of changes in interest rates and the value of the Canadian dollar relative to the US dollar, the Australian dollar and other currencies in locations where we do business; the monitoring of our exposure to liquidity risk; expectations in respect to the global economic environment and growing scrutiny by investors relating to sustainability performance; and our credit practices.

The forward-looking statements contained in this MD&A are based on many assumptions including, but not limited to, the following: the impacts arising from COVID-19 not becoming significantly more onerous on the Corporation, which includes the Corporation being permitted to continue to operate as an essential service; no significant changes to applicable laws and regulations, including any tax and regulatory changes in the markets in which we operate; no material adverse impacts to investment and credit markets; Alberta spot power prices being in the range of $58 to $68 per megawatt hour ("MWh") in 2021; Mid-C spot power prices being in the range of US$25 to US$35 per MWh in 2021; sustaining capital in 2021 being between $175 million and $210 million; productivity capital of $3 million to $7 million; applicable discount rates; our proportionate ownership of TransAlta Renewables Inc. ("TransAlta Renewables") not changing materially; no decline in the dividends to be received from TransAlta Renewables; the expected life extension of the Alberta thermal fleet and anticipated financial results generated on conversion or repowering; assumptions




TRANSALTA CORPORATION M3
Management’s Discussion and Analysis

regarding the ability of the converted units to successfully compete in the Alberta energy market; and assumptions regarding our current strategy and priorities, including as it pertains to our current priorities relating to the conversion to gas, growing TransAlta Renewables and realizing the full economic benefit from our capacity, energy and ancillary services.

Forward-looking statements are subject to a number of significant risks, uncertainties and assumptions that could cause actual plans, performance, results or outcomes to differ materially from current expectations. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this MD&A include, but are not limited to, risks relating to the impact of COVID-19, which cannot currently be predicted, and which present risks including, but not limited to: more restrictive directives of government and public health authorities; reduced labour availability and ability to continue to staff our operations and facilities; disruptions to our supply chains, including our ability to secure necessary equipment or to obtain regulatory approvals on the expected timelines or at all; COVID-19-related force majeure claims; restricted access to capital and increased borrowing costs; a further decrease in short-term and/or long-term electricity demand and lower merchant pricing in Alberta and Mid-C; reductions in production; increased costs resulting from our efforts to mitigate the impact of COVID-19; deterioration of worldwide credit and financial markets; a higher rate of losses on our accounts receivable due to credit defaults; impairments and/or writedowns of assets; and adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats. The forward-looking statements are also subject to other risk factors that include, but are not limited to: fluctuations in market prices; changes in demand for electricity and capacity and our ability to contract our generation for prices that will provide expected returns and replace contracts as they expire; changes to the legislative, regulatory and political environments in the jurisdictions in which we operate; environmental requirements and changes in, or liabilities under, these requirements; changes in general economic or market conditions including interest rates; operational risks involving our facilities, including unplanned outages at such facilities; disruptions in the transmission and distribution of electricity; the effects of weather and other climate-change related risks; unexpected increases in cost structure; disruptions in the source of fuels, including natural gas required for the conversions and repowering, as well as the extent of water, solar or wind resources required to operate our facilities; failure to meet financial expectations; natural and man-made disasters, including those resulting in dam or dyke failures; the threat of domestic terrorism and cyberattacks; pandemics or epidemics and any associated impact on supply chain; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner, timely manner or at all; commodity risk management and energy trading risks; industry risk and competition; the need to engage or rely on certain stakeholder groups and third parties; fluctuations in the value of foreign currencies and foreign political risks; the need for and availability of additional financing; structural subordination of securities; counterparty credit risk; changes to our relationship with, or ownership of, TransAlta Renewables; risks associated with development projects and acquisitions, including capital costs, permitting, labour and engineering risks, and delays in the construction or commissioning of projects or delays in the closing of acquisitions; changes in expectations in the payment of future dividends, including from TransAlta Renewables; inadequacy or unavailability of insurance coverage; downgrades in credit ratings; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Corporation, including as it pertains to establishing commercial operations at the South Hedland facility and in relation to the Brookfield Investment; reliance on key personnel; and labour relations matters. The foregoing risk factors, among others, are described in further detail in the Governance and Risk Management section of this MD&A and the Risk Factors section in our AIF for the year ended Dec. 31, 2020.
Readers are urged to consider these factors carefully in evaluating the forward-looking statements and are cautioned not to place undue reliance on them, which reflect the Corporation's expectations only as of the date hereof. The forward-looking statements included in this document are made only as of the date hereof and we do not undertake to publicly update these forward-looking statements to reflect new information, future events or otherwise, except as required by applicable laws. The purpose of the financial outlooks contained herein is to give the reader information about management's current expectations and plans and readers are cautioned that such information may not be appropriate for other purposes. In light of these risks, uncertainties and assumptions, the forward-looking statements might occur to a different extent or at a different time than we have described, or might not occur at all. We cannot assure that projected results or events will be achieved.




TRANSALTA CORPORATION M4
Management’s Discussion and Analysis

Corporate Strategy
Our strategic focus is to invest in a disciplined manner in a range of clean and renewable power generation such as hydro, wind, solar, energy storage and thermal (natural gas-fired and cogeneration) and develop customer-centric green power solutions that produce electricity for the needs of our industrial customers and communities in order to deliver returns to our shareholders.

Clean Energy Investment Plan
TransAlta's Clean Energy Investment Plan, announced in 2019, includes converting our existing Alberta coal assets to natural gas and advancing our leadership position in on-site generation and renewable electricity. The Clean Energy Investment Plan identified opportunities of $1.9 billion to $2.1 billion that TransAlta is pursuing. A significant number of these opportunities have been completed, with the projects achieving commissioned status in 2019 and 2020.

The implementation and execution of TransAlta's Clean Energy Investment Plan, including the acceleration of certain features of that plan, is being facilitated by the $750 million strategic investment (the "Brookfield Investment") by Brookfield Renewable Partners or its affiliates (collectively, "Brookfield") that we announced in March 2019. The first $350 million tranche of Brookfield's Investment closed in May 2019 and facilitated the acceleration of our conversion to gas plan discussed below. The second $400 million tranche of Brookfield's Investment closed on Oct. 30, 2020, and will help further the advancement and implementation of the remainder of our Clean Energy Investment Plan. The Brookfield Investment will fund other growth initiatives, while helping the Corporation maintain a strong balance sheet and financial flexibility to carry out the other pillars of our strategy discussed below. Please refer to the Significant and Subsequent Events section of this MD&A for further details.

Please refer to the 2021+ Sustainable Development Targets section of this MD&A for further details on sustainability targets and near-term objectives that further support our Clean Energy Investment Plan.

Our strategic priorities were advanced in 2020 and what follows is an update of how we executed in 2020, as well as our intentions for 2021 and beyond:

1.Successfully convert to natural gas as the primary fuel source in the Alberta thermal fleet
We are transitioning our Alberta thermal fleet to natural gas as part of our Clean Energy Investment Plan. We plan to invest between $900 million to $1.0 billion to convert or repower our Alberta thermal fleet to natural gas. This will repurpose and reposition our fleet to a cleaner, gas-fired fleet while delivering attractive returns through leveraging the Corporation's existing infrastructure.

The highlights of these gas conversion investments include:
▪Positioning TransAlta’s fleet as a low-cost clean energy generator in the Alberta energy-only market;
▪Generating attractive returns by leveraging the Corporation’s existing infrastructure;
▪Significantly extending the life and cash flows of our Alberta thermal assets; and
▪Significantly reducing air emissions and costs.

The following key achievements over the past year helped us advance this part of our strategy:

▪Conversion to gas – TransAlta’s Clean Energy Investment Plan includes converting three of our existing Alberta thermal units to gas during 2021 by replacing existing coal burners with natural gas burners. The cost to convert each of TransAlta's wholly owned units is expected to be approximately $35 million per unit. On Feb. 1, 2021, we announced the completion of the conversion to gas of Sundance Unit 6. The Corporation continues to advance conversion of its Keephills Unit 2 and Keephills Unit 3 for completion later in 2021 and has issued Full Notice to Proceed (“FNTP”) for both units. In addition, on April. 4, 2020, the dual-fuel conversion of Sheerness Unit 2 was completed. The Sheerness Unit 1 conversion to gas is in progress with expected completion in the first quarter of 2021. The Sheerness facility will receive it's last coal shipment in the first quarter of 2021, with coal stock being actively depleted until the end of 2021. The elimination of coal as a fuel source will reduce future fuel costs and greenhouse gas ("GHG") costs at Sheerness.

▪Gas Repowering – The Clean Energy Investment Plan also includes the repowering of the steam turbines at Sundance Unit 5 and, potentially, Keephills Unit 1, by installing one or more combustion turbines and heat recovery steam generators, thereby creating highly efficient combined-cycle units. The repowered units are expected to be a 35 per cent to 45 per cent lower capital investment when compared to a new combined-cycle facility, while achieving a similar heat rate. During the first quarter of 2020, we received regulatory approval from the Alberta Utilities Commission ("AUC") and Alberta Environment and Parks for the repowering of




TRANSALTA CORPORATION M5
Management’s Discussion and Analysis

Sundance Unit 5 and Keephills Unit 1 into combined-cycle units. During the fourth quarter of 2020, an equipment supply agreement was executed as part of the strategy to repower Sundance Unit 5 into a highly efficient combined-cycle unit. The commercial operation date is anticipated in the fourth quarter of 2023. The Sundance Unit 5 repowered combined-cycle unit will have a capacity of approximately 730 MW and is expected to cost approximately $800 million to $825 million, well below a greenfield combined-cycle project. As part of this transaction, we also acquired a long-term power purchase agreement ("PPA") for capacity plus energy, including the pass-through of GHG costs, starting in late 2023 with Shell Energy North America (Canada). The Corporation will continue to evaluate the prospect for the repowering of Keephills Unit 1 in 2021 and 2022 as a supply addition to the Alberta market in the 2026 to 2030 time frame.

▪Cessation of Coal-Fired Operations by 2022 – TransAlta has determined to cease coal-fired operations in Canada by Jan. 1, 2022. During the third quarter of 2020, we approved the accelerated shutdown of the Highvale mine by the end of 2021, and the useful life of the related assets was adjusted to align with the Corporation's conversion to gas plans. We will continue to actively deplete our coal stock and will wind down our mining activity by the end of 2021. As a result, we announced that Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal and will be subject to further strategic assessment as to their feasibility to operate on gas effective Jan. 1, 2022. The maximum capability of these units will be reduced to 70 MW and 113 MW, respectively, when transitioned to operate on gas.

▪Pioneer Pipeline and Gas Supply – On Oct 1, 2020, TransAlta announced that it had entered into a definitive Purchase and Sale Agreement for the sale of its 50 per cent interest in the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. (“ATCO”) (the "Transaction"). The purchase price of $255 million represents both TransAlta's and Tidewater Midstream & Infrastructure Ltd.'s ("TMI") interests. This agreement replaces the previous Purchase and Sale Agreement to sell the Pioneer Pipeline to NOVA Gas Transmission Ltd. ("NGTL") from the second quarter of 2020. ATCO acquired the right to purchase the Pioneer Pipeline through an option agreement with NGTL. Following closing of the Transaction, the Pioneer Pipeline will be integrated into NGTL's and ATCO's Alberta integrated natural gas transmission systems to provide reliable natural gas supply to TransAlta's Sundance and Keephills power-generating stations. As part of the agreement, TransAlta has entered into incremental, long-term firm natural gas delivery transportation agreements with NGTL for 351 TJ per day, bringing the total firm natural gas transportation contracts up to 400 TJ per day by 2023. TransAlta’s current commitments, including the 139 TJ per day supply arrangement with TMI, will remain in place until the closing of the Transaction. The Transaction is subject to customary regulatory approvals and is anticipated to close during the second quarter of 2021.

▪Retirement of Sundance 3 – On July 22, 2020, the Corporation announced that it gave notice to the Alberta Electric System Operator ("AESO") to retire the mothballed coal-fired Sundance Unit 3 effective July 31, 2020. The retirement decision was largely driven by our assessment of future market conditions, the age and condition of the unit, and our ability to supply energy and capacity from our generation portfolio in Alberta. This decision advances our transition to 100 per cent clean electricity by 2025.

2. Deliver growth in our renewables fleet
We expanded our renewables platform in the US in 2020 and continue to identify additional opportunities with customers on electricity offerings with a higher component of power coming from renewable sources. Our focus is to deliver solid returns using exceptional project development, construction and integration of skills and capabilities. In 2019, the Big Level and Antrim wind development projects were commissioned, allowing us to invest $340 million in projects with solid returns. The Skookumchuck wind project and WindCharger battery storage project were commissioned in 2020, representing investments of $93 million, which were within expected cost estimates. For 2021, we are constructing the Windrise wind project in Alberta, which is expected to be commissioned by year-end. Our contract expansion at the Southern Cross facility in Australia provides an additional opportunity to invest in renewables.

The following provides more detail on our 2020 achievements:

Windrise Wind Project
On Dec. 17, 2018, TransAlta's 207 MW Windrise wind project ("Windrise") was identified by the AESO as one of the three selected projects in the third round of the Renewable Electricity Program. TransAlta and the AESO subsequently executed a Renewable Electricity Support Agreement with a 20-year term. Windrise is situated on 11,000 acres of land located in the county of Willow Creek, Alberta, and is expected to cost approximately $270 million to $285 million. Windrise has secured approval for the wind facility and transmission line required to connect the facility to the Alberta grid from the Alberta Utilities Commission ("AUC”). Construction activities on Windrise continue to advance with all appropriate procedures in place to protect the construction team during the COVID-19 pandemic. However, as a result




TRANSALTA CORPORATION M6
Management’s Discussion and Analysis

of COVID-19 and related delays in construction, the commercial operation date is expected to occur during the second half of 2021. As of Dec. 31, 2020, Windrise was 78 per cent complete.

Skookumchuck Wind Project
On Nov. 25, 2020, TransAlta completed the acquisition of the 49 per cent equity investment in the Skookumchuck wind project ("Skookumchuck") with Southern Power Company, a subsidiary of Southern Company. Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas V136 wind turbines. The project began commercial operation on Nov. 7, 2020, and has a 20-year PPA with Puget Sound Energy. TransAlta's total net capital investment was $86 million (US$66 million) cash, with an additional $77 million (US$59 million) being funded with tax equity financing.

BHP Nickel West Contract Extension
On Oct. 22, 2020, Southern Cross Energy ("SCE"), a subsidiary of the Corporation, replaced and extended its current PPA with BHP Billiton Nickel West Pty Ltd. ("BHP"). SCE is composed of four generation facilities with a combined capacity of 245 MW in the Goldfields region of Western Australia.

The new agreement was effective Dec. 1, 2020, and replaces the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038, and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross facilities for BHP's mining operations located in the Goldfields region of Western Australia. The extension will provide SCE a return on new capital investments, which will be required to support BHP's future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. Evaluation of renewable energy supply and carbon emissions reduction initiatives under the extended PPA with SCE are underway, including an 18.5 MW solar photovoltaic facility supported by a battery energy storage system and a waste heat steam turbine system.

WindCharger Project
On Aug. 1, 2020, the WindCharger battery storage project ("WindCharger") was sold to TransAlta Renewables. WindCharger has been operational since Oct. 15, 2020, and is the first utility-scale battery energy storage project in Alberta. The WindCharger project has a nameplate capacity of 10 MW with a total storage capacity of 20 MWh. It is located in southern Alberta in the Municipal District of Pincher Creek next to TransAlta’s existing Summerview wind facility substation. WindCharger stores energy produced by the nearby Summerview II wind facility and discharges it into the Alberta electricity grid at times of peak demand. TransAlta is expected to receive co-funding of almost 50 per cent of the $14 million construction cost from Emissions Reduction Alberta. WindCharger is participating in both the Alberta wholesale energy and ancillary services market of the AESO.

US Wind Projects
In 2019, we completed the construction of two wind projects (collectively, the "US Wind Projects") in the Northeastern US. The Big Level wind project ("Big Level") acquired on March 1, 2018, consists of a 90 MW project located in Pennsylvania that has a 15-year PPA with Microsoft Corporation. The Antrim wind project ("Antrim") acquired on March 28, 2019, consists of a 29 MW project located in New Hampshire with two 20-year PPAs with Partners Healthcare and New Hampshire Electric Co-op. Big Level and Antrim began commercial operations on Dec. 19, 2019, and Dec. 24, 2019, respectively. The US Wind Projects have added an additional 119 MW of generating capacity to our Wind and Solar portfolio.

3. Expand presence in the US renewables market
A major focus of our business development efforts is on the renewables segment of the US market. Demand for new renewables in the US is expected to continue its strong growth in the near term and President Biden is expected to initiate policies designed to support further renewables growth. We have started prospecting for new renewable development sites in a number of attractive US markets. These opportunities are expected to grow TransAlta Renewables, utilize its excess debt capacity and deliver stable dividends back to TransAlta.

In addition to the US Wind Projects, the Skookumchuck wind project and the prospecting activities discussed above, TransAlta acquired a portfolio of up to 1,250 gigawatts ("GW") of wind development projects in the US in 2019. A number of projects acquired within this portfolio are currently in the early stages of development by TransAlta.





TRANSALTA CORPORATION M7
Management’s Discussion and Analysis

4. Advance and expand our on-site generation and cogeneration business
We are focused on growing our on-site and cogeneration asset base, a business segment we have deep experience in, having provided on-site cogeneration services to customers since the early 1990s. Our current pipeline under evaluation is approximately 600 MW and our technical design, operations experience and safety culture make us a strong partner in this segment. We see this segment growing as industrial and large-scale customers are looking to find solutions to help lower the costs of power production, replace aging or inefficient equipment, reduce network costs and meet their ESG objectives.

On Nov. 30, 2020, TransAlta acquired a 30 per cent equity interest in EMG International, LLC ("EMG") to diversify our sustainability offerings to customers while directly supporting our clean energy transition and sustainability goals. Included in the purchase price of US$12 million is an estimated component contingent on EMG realizing certain earnings metrics in 2020 and 2021, following the acquisition. The final contingent amount will be calculated based on actual earnings metrics achieved. EMG is an established company with over 25 years of experience in process wastewater treatment and specializes in the design and construction of high-rate anaerobic digester systems. EMG’s wastewater treatment process converts organic waste into a valuable source of renewable energy. Their technology produces a biogas stream that can be used as fuel to generate electricity, displacing energy consumed from higher-emitting resources. The investment provides a unique opportunity for TransAlta to leverage its vast expertise in on-site generation to support further advancements by EMG in the waste-to-energy space. This investment will advance the Corporation's presence in the US sustainability and on-site generation markets.

On May 19, 2020, the Corporation closed the acquisition of a contracted natural-gas-fired cogeneration asset from two private companies for a purchase price of US$27 million. The Ada facility is a 29 MW cogeneration facility ("Ada") in Michigan that is contracted under a PPA and a steam sale agreement for approximately six years with Consumers Energy and Amway.

In 2019, TransAlta and Energy Transfer Canada ("ET Canada" formerly known as SemCAMS Midstream ULC) entered into agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant (“K3”). The facility was expected to receive its final regulatory approvals in the second half of the year and begin construction in December 2020. On Sept. 25, 2020, the AUC released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. We are in ongoing commercial and technical discussions with ET Canada relative to the project at K3, or potentially developing a new project at another site owned and/or operated by ET Canada

5. Maintain a strong financial position
We intend to remain disciplined in our capital investment strategy and continue to build on our already strong financial position.

We currently have access to $2.1 billion in liquidity, including $703 million in cash. During 2020, we closed an AU$800 million offering ("TEC Offering"), through TEC Hedland Pty Ltd. ("TEC"), a subsidiary of the Corporation, and received $400 million of the second and final tranche of the $750 million strategic financing from Brookfield. We repaid a $400 million medium-term note due on Nov. 25, 2020. Further to the final closings of the recently announced dropdown transaction to TransAlta Renewables, the Corporation has reached its target balance of $1.2 billion of senior corporate debt. In 2019, we received the first tranche of the Brookfield Investment for $350 million, increased our credit facilities by $200 million to a total of $2.2 billion while extending the maturity of the term by one year, and successfully obtained US$126 million of tax equity financing associated with the US Wind Projects.

The Clean Energy Investment Plan is being funded from the cash raised through the Brookfield Investment, cash generated from operations and capital raised through TransAlta Renewables. For further details on the Brookfield Investment and TEC Offering, please refer to the Significant and Subsequent Events section of this MD&A.






TRANSALTA CORPORATION M8
Management’s Discussion and Analysis

Management of the Alberta Portfolio
On Dec. 31, 2020, the power purchase arrangement for many of our Alberta hydro facilities and Keephills 1 and 2 units expired and, effective Jan. 1, 2021, these facilities began operating on a merchant basis in the Alberta market. The facilities are dispatched to benefit from the price volatility in the Alberta energy-only electricity market and to provide ancillary services. As such, they are to be part of our Alberta electricity portfolio optimization activities. The variability in production by facility is driven by the diversity in our fuel types, which enables portfolio management. The Alberta portfolio of production includes hydro, wind, energy storage and thermal units. A portion of the baseload of the portfolio is hedged to provide cash flow certainty.

Growth and Conversion to Gas Expenditures
Our growth projects are focused on sustaining our current operations and supporting our growth strategy in our Clean Energy Investment Plan. A summary of the status of the significant growth and major projects in the Clean Energy Investment Plan is outlined below:
  Total project Estimated spend in 2021
Target completion date(2)
 
  Estimated
spend
Spent to
date(1)
Details
Project          
Big Level wind
   development project(3)
225  - 240 234  1  Commissioned in 2019 90 MW wind project with a 15-year PPA
Antrim wind
   development project(4)
100  - 110 106  1  Commissioned in 2019 29 MW wind project with two 20-year PPAs
Pioneer gas pipeline
partnership 		95  - 100 105  —  Commissioned in 2019 50 per cent ownership in the 120 km natural gas pipeline to supply gas to Sundance and Keephills
Skookumchuck wind
   development project(5,6)
160  - 170 86  —  Commissioned in 2020 Option to purchase a 49 per cent ownership in the 136.8 MW wind project with a 20-year PPA
Windrise wind
   development project(6)
270  - 285 205  68  H2 2021 207 MW wind project with a 20-year Renewable Electricity Support Agreement with AESO
WindCharger battery(7)
7  - 8 7  —  Commissioned in 2020 10 MW/ 20 MWh utility-scale Battery Storage Project
Boiler conversions 120  - 200 75  40  2020 to 2021 Conversion to gas at Alberta Thermal
Repowering 800  - 825 113  298  Q4 2023 Repower Sundance Unit 5 to a combined cycle design
Kaybob cogeneration
project 		105  - 115 48  40 
TBD(8)
40 MW cogeneration project with ET Canada
Total 1,882  - 2,053  979  448     
(1) Represents cumulative amounts spent as of Dec. 31, 2020.
(2) H1 is defined as the first half of the year and H2 is defined as the second half of the year.
(3) The numbers reflected above are in Canadian dollars, but the actual cash spend on this project is in US dollars and therefore these amounts will fluctuate with changes in foreign exchange rates. The estimated total spend is approximately US$173 million to US$185 million, spent to date is US$179 million and estimated remaining spend in 2021 is US$1 million. TransAlta Renewables funded a portion of the construction costs using its existing liquidity and the remaining was funded with tax equity financing.
(4) The numbers reflected above are in Canadian dollars, but the actual cash spend on this project is in US dollars and therefore these amounts will fluctuate with changes in foreign exchange rates. The estimated total spend is approximately US$77 million to US$85 million, spent to date is US$80 million and estimated remaining spend in 2021 is US$1 million. TransAlta Renewables funded a portion of the construction costs using its existing liquidity and the remaining was funded with tax equity financing.
(5) The numbers reflected above are in Canadian dollars, but the actual cash spent on this project is in US dollars. The total cash spent was US$66 million, with the remainder funded through tax equity financing of $77 million (US$59 million).
(6) The economic interest in Skookumchuck will be sold to TransAlta Renewables in the first half of 2021. The Windrise wind development project was sold to TransAlta Renewables on Feb. 26, 2021.
(7) The WindCharger project was acquired by TransAlta Renewables in 2020. Amounts shown are net of expected government reimbursements.
(8) Timing of the Kaybob cogeneration project is to be determined subject to ongoing commercial and technical discussions with ET Canada, as described above.





TRANSALTA CORPORATION M9
Management’s Discussion and Analysis

Highlights
Consolidated Financial Highlights
Year ended Dec. 31 2020 2019 2018
Adjusted availability (%) 90.3  90 91.3 
Production (GWh) 24,980  29,071  28,409 
Revenues 2,101  2,347  2,249 
Fuel, carbon compliance and purchased power 968  1,086  1,100 
Operations, maintenance and administration 472  475  515 
Net earnings (loss) attributable to common shareholders(1)
(336) 52  (248)
Cash flow from operating activities 702  849  820 
Comparable EBITDA(1,2)
927  984  1,161 
Funds from operations(1,2)
685  757  927 
Free cash flow(1,2)
358  435  524 
Net earnings (loss) per share attributable to common shareholders, basic and
diluted 		(1.22) 0.18  (0.86)
Funds from operations per share(1,2)
2.49  2.67  3.23 
Free cash flow per share(1,2)
1.30  1.54  1.83 
Dividends declared per common share 0.22  0.12  0.20 
Dividends declared per preferred share(3)
1.27  0.78  1.29 
As at Dec. 31 2020 2019 2018
Total assets 9,747  9,508  9,428 
Total consolidated net debt(2,4)
3,175  3,110  3,141 
Total long-term liabilities(5)
5,376  4,329  4,414 
(1) Includes $157 million received from the Balancing Pool for the early termination of Sundance B and C PPAs in the first quarter of 2018 and $56 million received on settlement of the dispute with the Balancing Pool in the third quarter of 2019.
(2) These items are not defined and have no standardized meaning under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Please refer to the Discussion of Consolidated Financial Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(3) Weighted average of the Series A, B, C, E and G preferred share dividends declared. Dividends declared vary year over year due to timing of dividend declarations.
(4) Total consolidated net debt includes long-term debt, including current portion, amounts due under credit facilities, exchangeable securities, US tax equity financing and lease liabilities, net of available cash and cash equivalents, the principal portion of restricted cash on our subsidiary TransAlta OCP LP ("TransAlta OCP") and the fair value of economic hedging instruments on debt. See the table in the Financial Capital section of this MD&A for more details on the composition of total consolidated net debt.
(5) Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications did not impact previously reported net earnings.

We showed strong performance and results within the current year, advancing our Clean Energy Investment Plan by accelerating our conversion to gas strategy, successfully managing our business during a global pandemic and keeping our people healthy and safe. We achieved these objectives despite the unfavourable impacts of COVID-19, including reduced electricity demand load, delays in construction and additional costs associated with new safety protocols and protective equipment required to effectively and safely operate our business. In spite of these challenges, we delivered strong operational performance and financial results in line with our guidance for comparable EBITDA and free cash flow ("FCF").

FCF, one of the Corporation's key financial metrics, totalled $358 million in 2020, down $77 million compared to last year. FCF, excluding the PPA Termination Payment received in 2019, decreased by $21 million compared to 2019. The decline was driven primarily by lower segmented cash flows at the Alberta Thermal segment and higher sustaining capital expenditures, partially offset by strong cash flows for Centralia and lower distributions paid to subsidiaries' non-controlling interests. Segmented cash flows for 2020 are consistent with 2019. Lower power demand and production in our Alberta Thermal segment and the impact of the total return swap recognized in 2019 in the Corporate segment was offset by higher performance in our Centralia, Wind and Solar, North American Gas and Energy Marketing segments. Significant changes in segmented cash flows are highlighted in the Segmented Comparable Results section of this MD&A.





TRANSALTA CORPORATION M10
Management’s Discussion and Analysis

Adjusted availability for 2020 was 90.3 per cent compared to 90.0 per cent in 2019. Lower planned and unplanned outages and derates within the generation segments were offset by the planned outage at Alberta Thermal for the Sundance Unit 6 turnaround and conversion to gas outage.

Production for 2020 was 24,980 gigawatt hours ("GWh") compared to 29,071 GWh in 2019. Overall, the production decrease was primarily due to planned outages, curtailments at Alberta Thermal and increased dispatch optimization at Alberta Thermal and Centralia due to lower merchant pricing, which was partially offset by higher production from higher wind and hydro resources and a full year of production at the Big Level and Antrim facilities. There was reduced electricity demand in North America due to COVID-19, which also had a significant impact on production.

Revenues for 2020 decreased by $246 million compared to 2019, as we saw lower demand and power prices across North America. This was partially offset by a full year of production from the Big Level and Antrim facilities in the Wind and Solar segment and the acquisition of the Ada facility during the year in the North American Gas segment.

Fuel, carbon compliance and purchased power costs in 2020 decreased by $118 million compared to 2019. Fuel, carbon compliance and purchased power costs were impacted by lower production in the year, offset by higher coal costs at Alberta Thermal and by the additional costs of production of the Ada facility. Coal costs include a writedown of coal inventory and increased depreciation resulting from the decision to accelerate the closure of the Highvale mine. Our ability to co-fire with natural gas assisted in reducing fuel costs as co-firing allows us to produce fewer GHG emissions than 100 per cent coal combustion and lowers our GHG compliance costs.

Operations, maintenance and administration ("OM&A") expenses for 2020 decreased by $3 million compared to 2019. OM&A decreased due to tighter cost controls, reduced staffing in line with conversion to gas transition plans, lower production at Centralia and Alberta Thermal, lower labour costs across multiple segments and lower legal fees. This was partially offset by the impact of the total return swap recognized in 2019 of $15 million, additional operating costs from new facilities including Big Level, Antrim and Ada, and the renegotiation of the Fort Saskatchewan maintenance agreement. Excluding the impact of the total return swap and new facilities, OM&A decreased by $28 million.

Comparable EBITDA decreased by $57 million compared to 2019. After adjusting for the PPA Termination Payments for 2019 and the AESO line loss adjustment of $8 million, comparable EBITDA increased by $7 million compared to 2019. Comparable EBITDA increased as a result of the new facilities at the Wind and Solar segment, higher comparable EBITDA in Centralia and continued strong performance in the Energy Marketing segment. This was partially offset by lower production at Alberta Thermal as a result of lower merchant demand. Significant changes in segmented comparable EBITDA are highlighted in the Segmented Comparable Results within this MD&A.

Net loss attributable to common shareholders for 2020 was $336 million compared to earnings of $52 million in 2019.
Net loss attributable to common shareholders has been impacted by higher interest expense associated with the TEC Offering and the second tranche of the Brookfield Investment, higher depreciation from acceleration of the conversion to gas, gains recognized on the Keephills 3 and Genesee 3 asset swap that occurred in 2019, the $56 million settlement on the Sundance B and C PPAs in 2019 and further impacts related to our decisions to accelerate our transition to gas, including:
▪Higher depreciation as we accelerate the closure of the Highvale mine;
▪Writedown of $37 million of coal inventory;
▪Onerous provision of $29 million on the coal supply contract for Sheerness; and
▪Impairment of $70 million associated with the retirement of Sundance 3.







TRANSALTA CORPORATION M11
Management’s Discussion and Analysis

Ability to Deliver Financial Results
The metrics we use to track our performance are comparable EBITDA and FCF. The following table compares target to actual amounts for each of the three past fiscal years:
Year ended Dec. 31 2020 2019 2018
Comparable EBITDA
Target(1)
925-1,000 875-975 1,000-1,050
Actual 927  984  1,161 
Adjusted actual(2)
927  928  1,004 
FCF
Target(1)
325-375 350-380 300-350
Actual 358  435  524 
Adjusted actual(2)
358  379  367 
(1) Represents our revised outlook. In the fourth quarter of 2019, we revised our FCF target from a range of $270 million to $330 million to a range of $350 million to $380 million. As a result of strong performance in the first quarter of 2018, we revised the following 2018 targets: comparable EBITDA from the previously announced target range of $950 million to $1,050 million to $1,000 to $1,050 million, FCF target range from $275 million to $350 million to the target range of $300 million to $350 million.
(2) 2019 and 2018 were adjusted for the PPA Termination Payments as these were not included in the targets.


Significant and Subsequent Events
TransAlta Renewables Acquisitions
On Dec. 23, 2020, the Corporation announced that it had entered into definitive agreements for the acquisition by TransAlta Renewables of its 100 per cent direct interest in the 207 MW Windrise wind project located in the Municipal District of Willow Creek, Alberta; a 49 per cent economic interest in the 137 MW Skookumchuck wind facility located across Thurston and Lewis counties in Washington State; and a 100 per cent economic interest in the 29 MW Ada cogeneration facility located in Ada, Michigan. TransAlta Renewables' acquisition of the Windrise wind project closed on Feb. 26, 2021, and the acquisition of the economic interests in the Ada facility and the Skookumchuck wind facility are expected to close in April 2021. The total acquisition value for the portfolio of assets is expected to be $439 million, which includes the remaining construction costs for the Windrise wind project. TransAlta Renewables will fund the acquisition and remaining construction costs with the proceeds from the TEC Hedland financing as further described below.

TEC Hedland Pty Ltd. Secures AU$800 Million Financing
On Oct. 22, 2020, TEC, a subsidiary of the Corporation, closed an AU$800 million senior secured note offering, by way of a private placement, which is secured by, among other things, a first ranking charge over all assets of TEC. The TEC Offering bears interest at 4.07 per cent per annum, payable quarterly and maturing on June 30, 2042, with principal payments starting on March 31, 2022. The TEC Offering has a rating of BBB by Kroll Bond Rating Agency.

TransAlta Renewables has received $480 million (AU$515 million) of the proceeds from the TEC Offering through the redemption of certain intercompany structures. An additional AU$200 million has been loaned to TransAlta Renewables by TransAlta Energy (Australia) Pty Ltd., which is a subsidiary of TransAlta. The loan bears interest at 4.32 per cent and will be repaid by Oct. 23, 2022, or on demand. The remaining proceeds from the TEC Offering were set aside for required reserves and transaction costs.

TransAlta Renewables used a portion of the proceeds from the redemption and the intercompany loan to repay existing indebtedness on its credit facility and to acquire the asset and economic interests noted above.

COVID-19
The World Health Organization declared a Public Health Emergency of International Concern relating to COVID-19 on Jan. 30, 2020, which they subsequently declared, on March 11, 2020, as a global pandemic. The outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to constrain the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods, self-isolation, physical and social distancing, and the closure of non-essential businesses, have caused significant disruption to businesses globally, which has resulted in an uncertain and challenging economic environment.

The Corporation continued to operate under its business continuity plan, which focused on ensuring that: (a) employees who could work remotely did so and (b) employees who operate and maintain our facilities, and who were not able to work remotely, were able to work safely and in a manner that ensured they remained healthy. During the second and third quarters of 2020, the Corporation successfully brought employees who were working remotely back to the office




TRANSALTA CORPORATION M12

Management’s Discussion and Analysis
without compromising health and safety standards. In November 2020, as a result of rising COVID-19 case counts in the Province of Alberta and in light of office attendance restrictions eventually imposed by the Government of Alberta, staff at TransAlta's head office returned to remote work protocols. All of TransAlta's offices and sites follow strict health screening and social distancing protocols with personal protective equipment readily available and in use. Further, TransAlta maintains travel bans aligned to local jurisdictional guidance, enhanced cleaning procedures, revised work schedules, contingent work teams and the reorganization of processes and procedures to limit contact with other employees and contractors on-site.

While our results have been impacted by price and demand as a result of COVID-19, all of our facilities continue to remain fully operational and capable of meeting our customers' needs. The Corporation continues to work and serve all of our customers and counterparties under the terms of their contracts. We have not experienced interruptions to service requirements. Electricity and steam supply continues to remain a critical service requirement to all of our customers and has been deemed an essential service in our jurisdictions.

During the second quarter of 2020, the Government of Canada passed the Canada Emergency Wage Subsidy as part of its COVID-19 Economic Response Plan. The program's intent is to support employment by providing expense relief to companies that experienced revenue declines in 2020. In January 2021, TransAlta applied for support under this program and expects to receive $8 million (pre-tax) for application periods in 2020. This represents a portion of the funding that the Corporation is eligible for and funds will be used to support a strategy to add incremental employment within the Corporation. The Corporation will recognize these wage subsidies as funds are received in 2021.

The Corporation continues to maintain a strong financial position due in part to its long-term contracts and hedged positions. At year-end, we had access to $2.1 billion in liquidity, including $703 million in cash and cash equivalents.

Strategic Investment by Brookfield
On March 22, 2019, the Corporation entered into an agreement (the "Investment Agreement") whereby Brookfield agreed to invest $750 million in the Corporation. The Brookfield Investment provides the financial flexibility to drive TransAlta's transition to 100 per cent clean electricity by 2025, recognizes the anticipated future value of TransAlta's Alberta Hydro Assets and accelerates the Corporation's plan to return capital to its shareholders. As discussed in the Corporate Strategy section of this MD&A, the Brookfield Investment was key to the implementation and advancement of TransAlta's Clean Energy Investment Plan, including facilitating or accelerating several key pillars of our strategic plan.

Under the terms of the Investment Agreement, Brookfield agreed to invest $750 million in TransAlta through the purchase of exchangeable securities, which are exchangeable by Brookfield into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted EBITDA. Upon entering into the Investment Agreement and as required under the terms of the agreement, the Corporation paid Brookfield a $7.5 million-structuring fee. A commitment fee of $15 million was also paid upon completion of the initial funding. These transaction costs were recognized as part of the carrying value of the unsecured subordinated debentures issued at that time.

On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039. On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in consideration for redeemable, retractable first preferred shares. The proceeds from the first tranche were used to accelerate our conversion to gas program. The Corporation intends to use the proceeds from the second tranche of the financing to advance the Corporation’s conversion to gas program, fund other growth initiatives and for general corporate purposes.

TransAlta has indicated that it intends to return up to $250 million of capital to shareholders through share repurchases within three years of receiving the first tranche of the Brookfield Investment. As of Dec. 31, 2020, 15,068,900 common shares have been repurchased in 2020 and 2019 for $129 million under the normal course issuer bid ("NCIB") program.

Under the terms of the Investment Agreement, Brookfield committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent by May 1, 2021. As of Jan. 8, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 33,845,685 common shares, representing approximately 12.4 per cent of the issued and outstanding common shares, calculated on an undiluted basis. In connection with the Investment Agreement, Brookfield is entitled to nominate two directors for election to the Board.





TRANSALTA CORPORATION M13

Management’s Discussion and Analysis
In accordance with the terms of the Investment Agreement, TransAlta has formed a Hydro Assets Operating Committee
consisting of two representatives from Brookfield and two representatives from TransAlta to collaborate in connection with the operation and maximization of the value of the Alberta Hydro Assets. In connection with this, the Corporation has committed to pay Brookfield an annual fee of $1.5 million for six years beginning May 1, 2019 (the "Brookfield Hydro Fee"), which is recognized in the OM&A expense on the Consolidated Statements of Earnings (Loss).

On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice alleging, among other things, oppression by the Corporation and its directors and seeking to set aside the Brookfield Investment. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter was adjourned due to the COVID-19 pandemic and is now scheduled to proceed to trial for three weeks starting April 19, 2021. Please refer to the Other Consolidated Analysis section of this MD&A for additional information on the Mangrove proceedings.

Centralia Unit 1 Retirement
The Corporation owns a two-unit 1,340 MW thermal coal-fired facility in Centralia, Washington, in relation to which we have entered into a number of multiple year medium- and short-term energy sales agreements. In 2011, Washington State passed the TransAlta Energy Transition Bill (chapter 180, Laws of 2011) (the "Bill'') allowing the Centralia thermal facility to comply with the state's GHG emissions performance standards by ceasing coal generation in one of its two boilers by the end of 2020, and the other by the end of 2025. The Bill removed restrictions that had previously been imposed on the facility limiting the duration of new contracts from the facility and limiting the technology that the facility would be required to implement for nitrogen oxide ("NOx ") controls. Centralia Unit 1 was retired from service effective Dec. 31, 2020.

Accelerated Shutdown of the Highvale Mine
During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021 and, accordingly, the useful life of the related assets was adjusted to align with the Corporation's conversion to gas plans. As at Dec. 31, 2020, the carrying value of the Highvale mine, including property, plant and equipment ("PP&E"), right-of-use assets and intangible assets, was $373 million. As a result, our cost per tonne of coal will increase as the fixed coal costs will be spread over lower volumes. During the second half of 2020, the increased depreciation expense and our cost per tonne of coal exceeded the net realizable value of the coal inventory and a writedown of $37 million was recognized in fuel, carbon compliance and purchased power. As the Highvale mine moves into the reclamation phase, our anticipated coal consumption is expected to continue to decline, further increasing the cost of coal and future expected writedowns in fuel costs. In 2020, we started the year with 2.1 million tonnes of coal inventory, during which we mined an additional 2.3 million tonnes and consumed 3.5 million tonnes. We ended the year with approximately one million tonnes of coal inventory and we will continue to actively deplete our coal stock as we wind down our mining activity by the end of 2021.

Normal Course Issuer Bid
On May 26, 2020, the Corporation announced that the TSX accepted the notice filed by the Corporation to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, the Corporation may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its public float of common shares, as at May 25, 2020. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.

The period during which the Corporation is authorized to make purchases under the NCIB began on May 29, 2020 and ends on May 28, 2021, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Corporation's election.

Under TSX rules, not more than 228,157 common shares (being 25 per cent of the average daily trading volume on the TSX of 912,630 common shares for the six months ended April 30, 2020) can be purchased on the TSX on any single trading day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar week.

During the year ended Dec. 31, 2020, under the current and previous NCIB, the Corporation purchased and cancelled a total of 7,352,600 common shares at an average price of $8.33 per common share, for a total cost of $61 million.




TRANSALTA CORPORATION M14

Management’s Discussion and Analysis
Management Changes
On Feb. 4, 2021, we announced that that Dawn Farrell, President and Chief Executive Officer, will retire from the Corporation and the Board on March 31, 2021, after leading the Corporation for almost a decade. John Kousinioris, currently Chief Operating Officer and, until his resignation on Feb. 5, 2021, President of TransAlta Renewables, will succeed Ms. Farrell as President and Chief Executive Officer and will join the Board on April 1, 2021. Prior to his appointment as Chief Operating Officer of TransAlta, Mr. Kousinioris held the roles of Chief Growth Officer and Chief Legal and Compliance Officer and Corporate Secretary at TransAlta. In the role of Chief Growth Officer, Mr. Kousinioris was responsible for overseeing the areas of business development, gas and renewables operations, and commercial and energy marketing.

On Feb. 6, 2021, Todd Stack, the Executive Vice President, Finance and Chief Financial Officer of the Corporation, accepted the position of President of TransAlta Renewables. Mr. Stack was promoted to Chief Financial Officer of the Corporation on May 16, 2019. Prior to being appointed as Chief Financial Officer, Mr. Stack served as Managing Director and Corporate Controller of the Corporation, and has been responsible for providing leadership and direction over TransAlta’s financial activities, corporate accounting, reporting, tax and corporate planning. Since joining TransAlta in 1990, Mr. Stack has acted as the Corporation's Treasurer, Corporate Controller, as well as a member of Corporate Development, and he played a prominent role in the growth and the initial public offering of TransAlta Renewables. Prior to joining the finance team, Mr. Stack held a number of roles in the engineering team, including design, operations and project management.

During the first quarter of 2021, Brett Gellner, our Chief Development Officer, announced he will retire effective April 30, 2021. Mr. Gellner has been employed with TransAlta for almost 13 years and during this time he has fulfilled multiple roles in commercial, finance, growth and strategy and served as our Chief Financial Officer. Mr. Gellner has built a reputation amongst investors and the broader community as a highly respected key leader in the power industry. He was central in TransAlta's recent corporate transformations and developing the Clean Energy Investment Plan. Mr. Gellner will remain on TransAlta Renewables' Board of Directors.

The roles of Chief Operating Officer and Chief Development Officer will not be backfilled.

Board of Director Changes
On April 21, 2020, we announced that the Board appointed John P. Dielwart as Chair of the Board, upon his re-election as an independent director at TransAlta’s annual shareholder meeting. As previously announced, Ambassador Gordon Giffin, the previous Chair of the Board, retired from the Board after serving as Chair since 2011.

Mr. Dielwart has served as an independent director on the Board since 2014, and has also served as the Chair of the Governance, Safety and Sustainability Committee and as a member of the Investment Performance Committee and the Audit, Finance and Risk Committee of the Board. Mr. Dielwart is a founder and director of ARC Resources Ltd. from 1996 to present and served as Chief Executive Officer of ARC Resources Ltd. from 2001 to 2013. Mr. Dielwart earned a Bachelor of Science (Distinction) in Civil Engineering from the University of Calgary, is a member of the Association of Professional Engineers and Geoscientists of Alberta and a Past-Chairman of the Board of Governors of the Canadian Association of Petroleum Producers. Mr. Dielwart is also a director and former Co-Chair of the Calgary and Area Child Advocacy Centre. In 2015, Mr. Dielwart was inducted into the Calgary Business Hall of Fame.

Also effective April 21, 2020, Sandra Sharman joined the Board. Ms. Sharman leads the Human Resources, Communications, Marketing and Enterprise Real Estate teams at CIBC, supporting execution of business strategy and enabling a world-class culture. A proven business leader with over 30 years of human resources and financial services experience in both Canada and the US, Ms. Sharman has played a leading role in shaping an inclusive and collaborative culture at CIBC, focused on empowering and enabling employees to reach their full potential. Ms. Sharman assumed the leadership of Human Resources at CIBC in 2014 and added accountability for communications and public affairs in 2017. Since 2017, her portfolio has expanded to encompass purpose, brand, marketing and most recently, corporate real estate. Ms. Sharman earned her Masters of Business Administration (MBA) from Dalhousie University. At TransAlta, Ms. Sharman is a member of the Governance, Safety and Sustainability Committee and the Human Resources Committee.

Robert Flexon resigned from the Board effective Aug. 1, 2020. Mr. Flexon assumed the role of Chair of the Board of Directors of PG&E Corporation (“PG&E”) and resigned from the Board due only to the potential for perceived conflicts of interests between PG&E and the Corporation.

Please refer to the Corporate Strategy section of this MD&A for further updates on ongoing projects.





TRANSALTA CORPORATION M15

Management’s Discussion and Analysis
Please refer to Note 4 of the consolidated financial statements within our 2020 Annual Integrated Report for significant events impacting both prior and current year results.

Segmented Comparable Results
Segmented cash flow generated by the business measures the net cash generated by each of our segments after sustaining and productivity capital expenditures, principal payments on lease liabilities, reclamation costs and provisions. This is the cash flow available to pay our interest and cash taxes, make distributions to our non-controlling partners, pay dividends to our preferred shareholders, grow the business, pay down debt and return capital to our shareholders.

The table below shows the segmented cash flow generated by the business by each of our segments:
Year ended Dec. 31 2020 2019 2018
Segmented cash flow(1)
   Hydro 83  93  96 
   Wind and Solar 241  206  211 
   North American Gas(2)
109  99  228 
   Australian Gas 114  112  136 
   Alberta Thermal(3)(4)
47  214  279 
   Centralia(3)
122  54  63 
Generation segmented cash flow 716  778  1,013 
   Energy Marketing 114  105  33 
   Corporate(5)
(100) (92) (107)
Total segmented cash flow 730  791  939 
Total segmented cash flow – excluding the PPA Termination Payments 730  735  782 
(1) Segmented cash flow is a non-IFRS measure and has no standardized meaning under IFRS. Please refer to the Additional IFRS Measures and Non-IFRS Measures section for further details.
(2) This segment was previously known as the Canadian Gas segment but was renamed with the acquisition of the US cogeneration facility in the second quarter of 2020.
(3) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
(4) Includes $157 million received from the Balancing Pool for the early termination of Sundance B and C PPAs in the first quarter of 2018 and $56 million received on settlement of the dispute with the Balancing Pool in the third quarter of 2019.
(5) Includes gains and losses on the total return swap.

Segmented cash flow generated by the business, after adjusting for the PPA Termination Payments, was consistent in 2020 compared to 2019, primarily due to higher performance in our Centralia, Wind and Solar, North American Gas and Energy Marketing segments. This was offset by lower power demand and production in our Alberta Thermal segment and the impact of the total return swap recognized in 2019 in the Corporate segment.

Cash flow in 2019, after adjusting for the PPA Termination Payments, was down $47 million in 2019 compared to 2018, mainly due to the expiry of the Mississauga Non-Utility Generator ("NUG") Enhanced Dispatch Contract (the "NUG Contract") and lower scheduled repayments on the Poplar Creek finance lease, partially offset by strong cash flows from Energy Marketing as well as lower sustaining capital expenditures.




TRANSALTA CORPORATION M16

Management’s Discussion and Analysis
Hydro
Year ended Dec. 31 2020 2019 2018
Production
Energy contracted
Alberta Hydro PPA assets (GWh)(1)
1,703  1,653  1,519 
Other hydro energy (GWh)(1)
353  331  306 
Energy merchant
Other hydro energy (GWh) 76  61  81 
Total energy production (GWh) 2,132  2,045  1,906 
Ancillary service volumes (GWh)(2)
2,857  2,978  3,265 
Gross installed capacity (MW) 926  926  926 
Revenues
Alberta Hydro PPA assets energy 87  101  90 
Alberta Hydro PPA assets ancillary 66  90  104 
Capacity payments received under Alberta Hydro PPA(3)
60  57  56 
Other revenue(4)
45  44  41 
Total gross revenues 258  292  291 
Net payment relating to Alberta Hydro PPA(5)
(106) (136) (135)
Revenues 152  156  156 
Fuel and purchased power 8  7  6 
Comparable gross margin 144  149  150 
Operations, maintenance and administration 37  36  38 
Taxes, other than income taxes 2  3  3 
Comparable EBITDA 105  110  109 
Deduct:
Sustaining capital:
Routine capital 12  7  4 
Planned major maintenance 8  7  8 
Total sustaining capital expenditures 20  14  12 
Productivity capital —  1  1 
Total sustaining and productivity capital 20  15  13 
Provisions 2  —  — 
Decommissioning and restoration costs settled —  2  — 
Hydro cash flow 83  93  96 
(1) Alberta Hydro PPA assets include 13 hydro facilities on the Bow and North Saskatchewan river systems included under the PPA legislation. Other hydro facilities include our hydro facilities in BC and Ontario and the hydro facilities in Alberta not included in the legislated PPAs.
(2) Ancillary services as described in the AESO Consolidated Authoritative Document Glossary.
(3) Capacity payments include the annual capacity charge as described in the Power Purchase Arrangements Determination Regulation AR 175/2000, available from Alberta Queen's Printer. The PPA expired on Dec. 31, 2020.
(4) Other revenue includes revenues from our non-PPA hydro facilities, our transmission business and other contractual arrangements including the flood mitigation agreement with the Alberta government and black start services.
(5) The net payment relating to the Alberta Hydro PPA represents the Corporation's financial obligations for notional amounts of energy and ancillary services in accordance with the Alberta Hydro PPA that expired on Dec. 31, 2020.






TRANSALTA CORPORATION M17

Management’s Discussion and Analysis
2020
Production for 2020 increased by 87 GWh over 2019, primarily due to higher water resources.

Ancillary service volumes for 2020 decreased by 121 GWh compared to 2019. This was primarily due to the AESO procuring lower ancillary volumes in 2020. Additionally, there has been weaker market conditions for ancillary services, partially due to COVID-19 and reduced industrial demand in Alberta.

2020 2019 2018
Gross Revenues per MWh
Alberta Hydro PPA assets energy ($/MWh) $51 $61 $59
Alberta Hydro PPA assets ancillary ($/MWh) $23 $30 $32

In 2020, Alberta Hydro energy revenue per MWh of production decreased by approximately $10 per MWh, compared to 2019, as result of lower merchant prices in Alberta.

In 2020, Alberta Hydro ancillary revenue per MWh of production decreased by approximately $7 per MWh, compared to 2019. Lower realized prices were primarily due to unfavourable market conditions in Alberta in 2020. For further discussion on the market conditions and pricing, please refer to the Competitive Forces section of this MD&A.

Total gross revenues for 2020 decreased $34 million compared to 2019, as lower energy and ancillary services revenues resulted from lower Alberta pricing and lower demand for ancillary products, partially offset by higher water resources.

Comparable EBITDA for 2020 decreased by $5 million compared to 2019, from lower revenues partially offset by recoveries allocated by the AESO related to the AESO transmission line loss proceeding. For additional information, please see Note 36 Commitments & Contingencies within the financial statements.

Sustaining capital expenditures for 2020 were $6 million higher than in 2019, due to more planned outages in 2020.

Hydro's cash flow decreased by $10 million for 2020 compared to 2019 mainly due to lower EBITDA and higher sustaining capital spend, partially offset by lower settlements of decommissioning and restoration costs.

2019
 
Production for 2019 increased by 139 GWh over 2018 primarily due to higher water resources.

Total gross revenues were comparable to 2018 as the Hydro business optimized its revenue through a combination of
energy sales and ancillary services, which allows us to maintain consistent revenues year-over-year.

Comparable EBITDA for 2019 increased by $1 million compared to 2018, as we were able to reduce OM&A due to cost-saving initiatives, while absorbing the $1.5 million Brookfield Hydro Fee.

Hydro's cash flow decreased by $3 million for 2019 compared to 2018 mainly due to higher capital expenditures and
decommissioning costs related to transmission assets.






TRANSALTA CORPORATION M18

Management’s Discussion and Analysis
Wind and Solar
Year ended Dec. 31 2020 2019 2018
Availability (%) 95.1 95.0 95.4 
Contract production (GWh) 2,871  2,395  2,363 
Merchant production (GWh) 1,198  960  1,005 
Total production (GWh) 4,069  3,355  3,368 
Gross installed capacity (MW)(1)
1,572  1,495  1,382 
Revenues 334  295  302 
Fuel and purchased power 25  16  17 
Comparable gross margin 309  279  285 
Operations, maintenance and administration 53  50  50 
Taxes, other than income taxes 8  8  8 
Net other operating income(2)
—  (10) (6)
Comparable EBITDA 248  231  233 
Deduct:
Sustaining capital:
Routine capital —  2  5 
Planned major maintenance 13  11  8 
Total sustaining capital expenditures 13  13  13 
Productivity capital 1  —  2 
Total sustaining and productivity capital 14  13  15 
Provisions (8) —  — 
Principal payments on lease liabilities 1  1  — 
Decommissioning and restoration costs settled —  1  1 
Other(2)
—  10  6 
Wind and Solar cash flow 241  206  211 
(1) 2020 gross installed capacity includes the WindCharger battery storage facility and our proportionate share of the Skookumchuck wind facility. The 2020 and 2019 gross installed capacity includes the addition of Big Level and Antrim, partially offset by the reduction of wind turbines due to tower fires at Wyoming Wind and Summerview.
(2) Relates to insurance proceeds included in net other operating income.

2020
Availability for the year ended Dec. 31, 2020, was consistent with 2019, which was in line with our expectations.

Production for the year ended Dec. 31, 2020, increased 714 GWhs, mainly due to the Big Level and Antrim wind facilities commencing commercial operations in December 2019 and strong wind resources across all regions in 2020, in particular for our Alberta wind facilities.

Comparable EBITDA for 2020 increased by $17 million compared to 2019, primarily due to the addition of the Big Level and Antrim wind facilities and higher production, partially offset by insurance proceeds received in 2019, lower Alberta pricing and the planned expiry of certain wind power production incentives in 2019. In addition, during 2020, the AESO began issuing invoices pertaining to the AESO transmission line loss. Wind and Solar has been allocated $8 million in costs in 2020, which has been reflected in fuel and purchased power within the current year. For additional information, please refer to Note 36 Commitments & Contingencies within the financial statements.

Sustaining and productivity capital expenditures for 2020 were consistent with 2019.

Wind and Solar's cash flow increased by $35 million for the year ended Dec. 31, 2020, compared to the prior year, mainly due to higher comparable EBITDA and insurance proceeds received in 2019, partially offset by higher sustaining and productivity capital spend for Kent Hills foundation expenditures.





TRANSALTA CORPORATION M19

Management’s Discussion and Analysis
2019
 
Availability and production for the year ended Dec. 31, 2019, was comparable to 2018, which was in line with our expectations. The Big Level and Antrim wind facilities had minimal impact on 2019 availability and production due to their commercial operation occurring in late December.

Comparable EBITDA for 2019 was consistent with 2018. Higher insurance proceeds from tower fires at Wyoming Wind and Summerview were partially offset by a reduction in revenues due to the scheduled expiration of production-based incentives for three wind facilities.

Wind and Solar's cash flow decreased by $5 million for the year ended Dec. 31, 2019, compared to the prior year, mainly due to lower revenue.

North American Gas(1)
Year ended Dec. 31 2020 2019 2018
Availability (%) 96.9 94.8 93.3 
Contract production (GWh) 1,896  1,655  1,620 
Merchant production (GWh)(2)
131  262  172 
Purchased power (GWh)(2)
(198) (92) (79)
Total production (GWh) 1,829  1,825  1,713 
Gross installed capacity (MW)(3)
974  945  945 
Revenues 234  238  407 
Fuel and purchased power 66  74  99 
Comparable gross margin 168  164  308 
Operations, maintenance and administration 49  44  48 
Taxes, other than income taxes 2  1  1 
Net other operating income —  (1) — 
Comparable EBITDA 117  120  259 
Deduct:
Sustaining capital:
Routine capital 4  10  4 
Planned major maintenance 2  8  16 
Total sustaining capital expenditures 6  18  20 
Productivity capital —  —  2 
Total sustaining and productivity capital 6  18  22 
Provisions and other —  —  9 
Decommissioning and restoration costs settled 2  3  — 
North American Gas cash flow 109  99  228 
(1) This segment was previously known as the Canadian Gas segment but was renamed with the acquisition of the Ada facility in the second quarter of 2020. See the Corporate Strategy section of this MD&A and Note 4 of the consolidated financial statements for further details.
(2) Purchased power used for dispatch optimization has been separated from merchant production in the current year. Comparable periods have been adjusted to reflect this change.
(3) 2020 includes 29 MW for the acquisition of the Ada facility in the second quarter of 2020.






TRANSALTA CORPORATION M20

Management’s Discussion and Analysis
2020
 
Availability for the year ended Dec. 31, 2020, increased compared to 2019, primarily due to lower planned and unplanned outages at our Fort Saskatchewan, Sarnia and Ottawa facilities, partially offset by planned outages at the Ada facility.

Production was consistent with 2019. Higher customer demand at our Sarnia facility and the addition of the Ada facility was offset by lower Ontario market demand in 2020. Due to low power pricing in Ontario, we settled some customer power purchases with power purchased from the merchant market. Overall, due to the nature of our contracts, changes in production do not have a significant financial impact as our contracts are structured as capacity payments with customer-supplied fuel or a pass-through of fuel costs.

OM&A costs for 2020 were $5 million higher than in 2019, due to the addition of the new Ada facility and the new recontracted terms of the Fort Saskatchewan commercial agreement.
 
Comparable EBITDA for 2020 decreased by $3 million compared to 2019, mainly due to lower earnings at Fort Saskatchewan as the new commercial agreement was negatively impacted by lower merchant pricing in Alberta, partially offset by the addition of the Ada facility.
 
Sustaining capital expenditures in 2020 decreased by $12 million mainly due to a major planned outage for Sarnia in 2019.

Cash flow at North American Gas increased by $10 million for the year ended Dec. 31, 2020, compared to the prior year mainly due to lower sustaining capital, partially offset by lower comparable EBITDA.

2019
 
Availability for the year ended Dec. 31, 2019, increased compared to 2018, primarily due to lower planned outages at Fort Saskatchewan and Sarnia.

Production for the year increased by 112 GWh compared to 2018, mainly due to higher customer and market demand as well as lower planned outages, partially offset by higher unplanned outages.

Comparable EBITDA for 2019 decreased by $139 million compared to 2018 mainly due to the Mississauga contract ending Dec. 31, 2018, and lower scheduled payments from the Poplar Creek finance lease. Comparable EBITDA for the year ended Dec. 31, 2019, includes nil (2018 — $105 million) and $20 million (2018 — $57 million) from the Mississauga and Poplar Creek contracts, respectively. Additionally, comparable EBITDA benefited from lower OM&A compared to
the prior year as a result of reduced overhead and operating costs.

Sustaining capital totalled $18 million in 2019, a decrease of $2 million due to lower planned outage costs, partially offset by the timing of capital spares purchases for Sarnia.

Cash flow at Canadian Gas decreased by $129 million for the year ended Dec. 31, 2019, compared to the prior year mainly due to lower comparable EBITDA.






TRANSALTA CORPORATION M21

Management’s Discussion and Analysis
Australian Gas
Year ended Dec. 31 2020 2019 2018
Availability (%) 93.8 90.6 94.0 
Contract production (GWh) 1,779  1,832  1,814 
Gross installed capacity (MW) 450  450  450 
Revenues 162  160  165 
Fuel and purchased power 6  5  4 
Comparable gross margin 156  155  161 
Operations, maintenance and administration 32  37  37 
Comparable EBITDA 124  118  124 
Deduct:
Sustaining capital:
Routine capital 3  2  2 
Planned major maintenance 6  3  — 
Total sustaining capital expenditures 9  5  2 
Productivity capital 1  1  — 
Total sustaining and productivity capital 10  6  2 
Other —  —  (14)
Australian Gas cash flow 114  112  136 

2020
 
Availability for the year ended Dec. 31, 2020, increased compared to 2019, mainly due to unplanned outages in 2019.

Production for 2020 decreased compared to 2019, mainly due to changes in customer demand at the South Hedland facility. Due to the nature of our contracts, changes in production do not have a significant financial impact as our contracts are structured as capacity payments with customer-supplied fuel or a pass-through of fuel costs.
 
Comparable EBITDA for the year ended Dec. 31, 2020, increased by $6 million compared to 2019, due to the deferral of legal costs associated with our dispute with Fortescue Metals Group Ltd ("FMG"), reduced staffing due to cost controls and the strengthening of the Australian dollar against the Canadian dollar.

Sustaining and productivity capital for 2020 increased by $4 million compared to 2019, mainly due to planned major maintenance at our Southern Cross facility.

Australian Gas' cash flow increased by $2 million in 2020, mainly due to higher comparable EBITDA, partially offset by higher sustaining capital expenditures.

2019
Availability for the year ended Dec. 31, 2019, decreased compared to 2018 mainly due to unplanned outages.

Production for 2019 was comparable to 2018. Due to the nature of our contracts, changes in production do not have a significant financial impact as our contracts are structured as capacity payments with customer-supplied fuel or a pass-through of fuel costs.

Comparable EBITDA for the year ended Dec. 31, 2019, decreased by $6 million compared to 2018 due to the weakening of the Australian dollar and ongoing legal costs associated with our dispute with FMG.

Sustaining and productivity capital for 2019 increased by $4 million compared to 2018 mainly due to planned major maintenance at our Southern Cross facility.

Cash flow at Australian Gas decreased by $24 million in 2019 mainly due to lower comparable EBITDA, as well as higher sustaining capital expenditures. In addition, 2018 cash flow included the collection of a long-term receivable.





TRANSALTA CORPORATION M22

Management’s Discussion and Analysis
Alberta Thermal(1)
Year ended Dec. 31 2020 2019 2018
Availability (%) 84.8 89.2  91.6 
Contract production (GWh) 5,851  6,927  8,936 
Merchant production (GWh) 4,186  5,932  5,304 
Total production (GWh) 10,037  12,859  14,240 
Gross installed capacity (MW)(2)
2,866  3,229  3,231 
Revenues 659  823  901 
Fuel, carbon compliance and purchased power(3)
391  449  526 
Comparable gross margin 268  374  375 
Operations, maintenance and administration 131  138  171 
Taxes, other than income taxes 15  13  13 
Termination of Sundance B and C PPAs —  (56) (157)
Net other operating income (40) (40) (41)
Comparable EBITDA(3)
162  319  389 
Deduct:
Sustaining capital:      
Routine capital 16  15  17 
Mine capital 7  23  42 
Planned major maintenance 62  34  15 
Total sustaining capital expenditures 85  72  74 
Productivity capital 1  6  12 
Total sustaining and productivity capital 86  78  86 
Provisions —  (6) (10)
Principal payments on lease liabilities 20  16  14 
Decommissioning and restoration costs settled 9  17  19 
Other —  —  1 
Alberta Thermal cash flow 47  214  279 
(1) The Canadian Coal segment was renamed Alberta Thermal in the third quarter of 2020.
(2) All years include 406 MW for Sundance Unit 5, which is temporarily mothballed. Sheerness Unit 2's capacity was increased in 2020 following a generator rewind and final testing. 2019 and 2018 also include 368 MW for Sundance Unit 3, which was temporarily mothballed and then retired during the third quarter of 2020. In addition, the Keephills 3 and Genesee 3 asset swap resulted in a net 2 MW reduction of capacity that occurred in the fourth quarter of 2019.
(3) In 2020, the interest on the line loss provision was reclassified from fuel, carbon compliance and purchased power to interest expense.


Supplemental disclosure 2020 2019 2018
Comparable EBITDA – excluding the PPA Termination Payments 162  263  232 
Alberta Thermal cash flow – excluding the PPA Termination Payments 47  158  122 

2020
Availability for the year was lower compared to 2019 due to the Sundance Unit 6 planned turnaround and conversion to gas outage occurring in late 2020 and higher unplanned outages and derates. The Sundance Unit 6 return to service was delayed due to unexpected issues identified during recommissioning. Our Keephills Unit 2 has experienced increased outages as we approach the 2021 turnaround outage. Increased derates are attributed to our conversion to gas transition plan and our consumption of lower-quality coal inventory.

Production for the year ended Dec. 31, 2020, decreased 2,822 GWh compared to 2019. This was largely a result of curtailments and dispatch optimization resulting in lower merchant production in the Alberta Thermal fleet due to reduced industrial demand in the province and the impact of COVID-19 on demand generally. Production also decreased due to lower availability.

Revenue for the year ended Dec. 31, 2020, decreased by $164 million compared to 2019, mainly due to lower merchant production.




TRANSALTA CORPORATION M23

Management’s Discussion and Analysis
2020 2019 2018
Revenues per MWh $66 $64 $63
Fuel, carbon compliance and purchased power per MWh $39 $35 $37

In 2020, revenue per MWh of production increased by $2 per MWh in 2020 compared with 2019 primarily due to higher realized prices as a result of optimizing production during periods of favourable pricing and hedging positions minimizing the impact of unfavourable market pricing.

In 2020, fuel, carbon compliance and purchased power costs per MWh of production increased by $4 per MWh compared with 2019. Costs per MWh increased due to fixed coal costs spread over less volumes, resulting in increased costs per MWh.

We continued to co-fire with natural gas, when economic. Natural gas combustion produces fewer GHG emissions than coal combustion, which lowers our GHG compliance costs.

OM&A costs were lower in 2020 compared to 2019 as a result of strong cost controls, reduced staffing in line with conversion to gas transition plans, and a reflection of lower production.

Excluding the PPA Termination Payments, comparable EBITDA for the year ended Dec. 31, 2020, decreased $101 million compared to 2019. Merchant production was lower due to unfavourable market conditions and higher fuel costs.
 
For the year ended Dec. 31, 2020, sustaining capital expenditures increased by $13 million compared to 2019 mainly due to the major maintenance that occurred during the Sheerness dual-fuel conversion and the Sundance Unit 6 turnaround.

Alberta Thermal cash flow for the year ended Dec. 31, 2020, excluding the PPA Termination Payments, decreased by $111 million compared to 2019 mainly due to lower comparable EBITDA, increased sustaining and productivity capital expenditures and the early settlement of mining equipment leases, partially offset by the deferral of decommissioning expenditures due to COVID-19.

2019
Availability for the year was lower compared to 2018 due to planned outages at our Keephills 1 and Sundance 4 units, whereas 2018 only had one outage at one of our non-operated units; this was partially offset by fewer unplanned losses in 2019.

Production for the year ended Dec. 31, 2019, decreased 1,381 GWh compared to 2018 primarily due to the mothballing of certain Sundance units and planned outages, partially offset by lower unplanned outages. Lower contract production was partially offset by higher merchant production.

Revenue for the year ended Dec. 31, 2019, decreased by $78 million compared to 2018, mainly due to lower production as a result of the termination of the Sundance B and C PPAs on March 31, 2018.

Revenue per MWh of production rose to approximately $64 per MWh in 2019 from $63 per MWh in 2018. Revenues in the first quarter of 2018 included the Sundance B and C PPA revenue as well as the pass-through revenues associated with carbon compliance costs, which are no longer recoverable on the Sundance units as the PPAs have been terminated.

Fuel, carbon compliance and purchased power costs per MWh were lower in 2019 compared to 2018. Cost per MWh of production fell to approximately $35 per MWh in 2019 from $37 per MWh in 2018.

We continued to co-fire with natural gas, when economical. Natural gas combustion produces fewer GHG emissions than coal combustion, which lowers our GHG compliance costs. In addition, fuel costs can be lower by co-firing, depending on the market price for natural gas. On Nov. 1, 2019, the firm contract to transport natural gas on the Pioneer Pipeline began, which substantially increased gas quantities available to us and increased our supply available to co-fire.






TRANSALTA CORPORATION M24

Management’s Discussion and Analysis
OM&A costs were lower in 2019 compared to 2018 as a result of the full-year impact of cost reductions progressively implemented over the preceding year. These cost reductions arose from a combination of factors that included fewer units operating, lower capacity factor operation on merchant units, co-firing with gas, and operations and maintenance work optimization.

Excluding the PPA Termination Payments, comparable EBITDA for the year ended Dec. 31, 2019, increased $31 million compared to 2018. This largely reflects lower fuel, carbon compliance and purchased power costs, as well as lower OM&A costs.
 
For the year ended Dec. 31, 2019, sustaining capital expenditures decreased by $2 million compared to 2018, mainly due to less mine development work being completed in 2019, partially offset by higher spend on planned major maintenance. In 2018, there was only one planned major outage at one of our non-operating units, while during 2019 there were two planned major outages at the Keephills 1 and Sundance 4 units.

Alberta Thermal's cash flow for the year ended Dec. 31, 2019, increased by $36 million (excluding the PPA Termination Payments) compared to 2018, mainly due to higher comparable EBITDA and decreased sustaining and productivity capital expenditures.

Centralia(1)
Year ended Dec. 31 2020 2019 2018
Availability (%) 76.2  74.0  60.2 
Adjusted availability (%)(2)
90.2  83.5  84.6 
Contract sales volume (GWh) 3,338  3,329  3,329 
Merchant sales volume (GWh) 5,571  7,691  5,704 
Purchased power (GWh) (3,775) (3,865) (3,665)
Total production (GWh) 5,134  7,155  5,368 
Gross installed capacity (MW) 1,340  1,340  1,340 
Revenues 483  559  471 
Fuel and purchased power 279  416  314 
Comparable gross margin 204  143  157 
Operations, maintenance and administration 60  67  61 
Taxes, other than income taxes 5  3  5 
Comparable EBITDA 139  73  91 
Deduct:
Sustaining capital:
Routine capital 3  2 2 
Planned major maintenance 7  5 11 
Total sustaining capital expenditures 10  7 13 
Productivity capital —  1 — 
Total sustaining and productivity capital 10  8 13 
Principal payments on lease liabilities —  —  4 
Decommissioning and restoration costs settled 7  11 11 
Centralia cash flow 122  54 63 
(1) The US Coal segment was renamed Centralia in the third quarter of 2020.
(2) Adjusted for dispatch optimization.

2020
Adjusted availability for the year increased compared to 2019 due to lower forced outages and derates in 2020. In the first half of 2019, Centralia Unit 1 had significant derates that were resolved and not experienced in 2020.

Production decreased by 2,021 GWh in 2020 compared to 2019 due mainly to lower merchant pricing throughout 2020 and timing of dispatch optimization. In 2020, both Centralia units were taken out of service in February and March as a result of seasonally lower prices in the Pacific Northwest, whereas in 2019 both units remained in service into April due to higher prices in the Pacific Northwest.





TRANSALTA CORPORATION M25

Management’s Discussion and Analysis
OM&A costs were $7 million lower in 2020 compared to 2019 mainly due to lower levels of maintenance required to support an almost 30 per cent decrease in production and strong cost controls.

Comparable EBITDA increased by $66 million compared to 2019, primarily due to increased benefits from dispatch optimization in 2020 and from an isolated and extreme pricing event in March 2019 for $25 million where Centralia was unable to commit one of its units to physical production for day-ahead supply due to an unplanned forced outage repair. In addition, comparable EBITDA in 2020 increased with the strengthening of the US dollar relative to the Canadian dollar throughout the year.

Sustaining and productivity capital expenditures for 2020 were $2 million higher than 2019 mainly due to increased planned outage work performed in 2020 during the reserve shutdown.

Centralia's cash flow for 2020 increased by $68 million compared to the prior year, mainly due to higher comparable EBITDA and deferral of decommissioning expenditures due to COVID-19, partially offset by higher sustaining capital spend.

2019
Adjusted availability for 2019 was down compared to 2018 due to higher forced outages and derates in 2019. Centralia Unit 1 operated with a derate due to blocked precipitator hoppers impacting the first half of 2019. This derate was resolved when the unit was offline during the second quarter of 2019.

Production was up 1,787 GWh in 2019 compared to 2018 due mainly to higher merchant pricing in the first half of 2019 and timing of dispatch optimization. In 2019, both Centralia units remained in service into April due to higher prices in the Pacific Northwest, whereas in 2018, both Centralia units were taken out of service in February as a result of seasonally lower prices in the Pacific Northwest. In 2018, we performed major maintenance on both units during that time.

OM&A costs were $6 million higher in 2019 compared to 2018 mainly due to higher levels of maintenance required to support a 33 per cent increase in production and as a result of higher costs to resolve precipitator blockages.

Comparable EBITDA in 2019 decreased by $18 million compared to 2018, primarily due to an isolated and extreme pricing event in March. Centralia was unable to commit one of its units to physical production for day-ahead supply due to an unplanned forced outage repair.

Sustaining and productivity capital expenditures for 2019 were $5 million lower than 2018, mainly due to less planned outage work performed in 2019.

Centralia's cash flow for 2019 decreased by $9 million compared to 2018, mainly due to lower comparable EBITDA, partially offset by lower sustaining and productivity capital spend.

Energy Marketing
Year ended Dec. 31 2020 2019 2018
Revenues and comparable gross margin 143  119  67 
Operations, maintenance and administration 30  30  24 
Comparable EBITDA 113  89  43 
Deduct:
Provisions and other (1) (16) 10 
Energy Marketing cash flow 114  105  33 

2020
 
Comparable EBITDA for 2020 increased by $24 million compared to 2019. Results were primarily from continued strong performance in both power and natural gas markets. Gains were realized from short-term strategies across various geographic regions aided by market and price volatility. The Energy Marketing team was able to capitalize on short-term arbitrage opportunities in the markets in which we trade without materially changing the risk profile of the business unit. OM&A spending for 2020 and 2019 was similar.

Energy Marketing's cash flows for 2020 increased by $9 million compared to 2019 mainly due to higher comparable EBITDA, partially offset by changes in emissions obligations and prepaid balances for transmission rights.




TRANSALTA CORPORATION M26

Management’s Discussion and Analysis
 
2019
Comparable EBITDA for 2019 increased by $46 million compared to 2018 results due to strong results from all Energy Marketing segments, with particularly strong performance from US Western and Eastern markets due to continued high levels of volatility. OM&A increased due to higher incentives related to stronger performance. The Energy Marketing team was able to capitalize on short-term arbitrage opportunities in the markets in which we trade without materially changing the risk profile of the business unit.

Energy Marketing's cash flows for 2019 increased by $72 million compared to 2018, mainly due to higher comparable EBITDA and changes in emissions obligations and prepaid balances for transmission rights.


Corporate
Year ended Dec. 31 2020 2019 2018
Operations, maintenance, and administration 80  73  86 
Taxes, other than income taxes 1  1  1 
Net other operating loss —  2  — 
Comparable EBITDA (81) (76) (87)
Deduct:
Sustaining capital:
Routine capital 14  12  16 
Total sustaining capital expenditures 14  12  16 
Productivity capital 1  —  4 
Total sustaining and productivity capital expenditures 15  12  20 
Provisions —  —  — 
Principal payments on lease liabilities 4  4  — 
Corporate cash flow (100) (92) (107)
 

Supplemental disclosure 2020 2019 2018
Corporate cash flow (100) (92) (107)
Total return swap (gains) losses 2  (13) (1)
Adjusted Corporate cash flow (98) (105) (108)

2020
 
Our Corporate overhead costs in 2020 were $81 million, an increase of $5 million compared to $76 million in 2019, primarily due to realized gains and losses from the total return swap. A portion of the settlement cost of our employee share-based payment plans is fixed by entering into total return swaps, which are cash settled every quarter. Excluding the impact of the total return swap, Corporate overhead costs for 2020 decreased by $10 million compared to 2019, mainly due to lower legal fees and lower labour and reduced travel costs, partially offset by additional costs to support growth and development projects, centralization of shared services to the Corporate segment and additional costs incurred to support COVID-19 protocols.

Corporate cash flow, excluding the impact of the total return swap, was also lower in 2020 compared to 2019 due to slightly higher sustaining and productivity capital spend on information technology.
 
2019
Our Corporate overhead costs in 2019 were $76 million, a decrease of $11 million compared to $87 million in 2018, primarily due to cost-efficiency initiatives and principal payments on lease liabilities. In addition, we realized a net gain of $13 million from the total return swap, which was mostly offset by higher legal costs. Corporate cash flow also benefited from lower sustaining and productivity capital spend due to higher spend in 2018 on automation and new information technology solutions implemented in prior years, which helped contribute to the cost efficiencies realized in 2019.





TRANSALTA CORPORATION M27

Management’s Discussion and Analysis
Additional IFRS Measures and Non-IFRS Measures
An additional IFRS measure is a line item, heading or subtotal that is relevant to an understanding of the consolidated financial statements but is not a minimum line item mandated under IFRS, or the presentation of a financial measure that is relevant to an understanding of the consolidated financial statements but is not presented elsewhere in the consolidated financial statements. We have included line items entitled gross margin and operating income (loss) in our Consolidated Statements of Earnings (Loss) for the years ended Dec. 31, 2020, 2019 and 2018. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.
 
We evaluate our performance and the performance of our business segments using a variety of measures to provide management and investors with an understanding of our financial position and results. Certain financial measures discussed in this MD&A are not defined under IFRS, are not standard measures under IFRS and, therefore, should not be considered in isolation or as an alternative to, or to be more meaningful than, net earnings attributable to common shareholders or cash flow from operating activities, as determined in accordance with IFRS when assessing our financial performance or liquidity. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. Comparable EBITDA, deconsolidated comparable EBITDA, deconsolidated comparable EBITDA by segment, FFO, deconsolidated FFO, FCF, total net debt, total consolidated net debt, adjusted net debt, deconsolidated net debt and segmented cash flow generated by the business, all as defined below, are non-IFRS measures that are presented in this MD&A. See the Discussion of Consolidated Financial Results, Segmented Comparable Results, Selected Quarterly Information, Key Financial Ratios and Financial Capital sections of this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS measure.





TRANSALTA CORPORATION M28

Management’s Discussion and Analysis
Discussion of Consolidated Financial Results
Each business segment assumes responsibility for its operating results measured to comparable EBITDA and cash flows generated by the business. Gross margin is also a useful measure as it provides management and investors with a measurement of operating performance that is readily comparable from period to period.

Comparable EBITDA
EBITDA is a widely adopted valuation metric and an important metric for management that represents our core business profitability. Interest, taxes, depreciation and amortization are not included, as differences in accounting treatments may distort our core business results. In addition, under comparable EBITDA we reclassify certain transactions to facilitate the discussion of the performance of our business:
▪Comparable EBITDA is adjusted to exclude the impact of unrealized mark-to-market gains or losses.
▪Any gains or losses on asset sales or foreign exchange gains or losses are not included as these are not part of operating income.
▪Certain assets we own in Canada and in Australia are fully contracted and recorded as finance leases under IFRS. We believe it is more appropriate to reflect the payments we receive under the contracts as a capacity payment in our revenues instead of as finance lease income and a decrease in finance lease receivables.
▪We also reclassify the depreciation on our mining equipment from fuel, carbon compliance and purchased power to reflect the actual cash cost of our business in our comparable EBITDA.
▪Coal inventory writedowns are not included as these are non-cash adjustments that are not reflective of our core business results upon conversion to gas. To accelerate our conversion to gas plans, a decision was made to accelerate the mine shutdown to 2021.
▪In December 2016, we agreed to terminate our existing arrangement with the Independent Electricity System Operator relating to our Mississauga cogeneration facility in Ontario and entered into the NUG Contract effective Jan. 1, 2017. Under the new NUG Contract, we received fixed monthly payments until Dec. 31, 2018, with no delivery obligations. Under IFRS, for our reported results in 2016, as a result of the NUG Contract, we recognized a receivable of $207 million (discounted), a pre-tax gain of approximately $191 million net of costs to mothball the units and accelerated depreciation of $46 million. In 2017 and 2018, on a comparable basis, we recorded the payments we received as revenues as a proxy for operating income and depreciated the facility until Dec. 31, 2018.
▪On the commissioning of the South Hedland facility in July 2017, we prepaid approximately $74 million of electricity transmission and distribution costs. Interest income is recorded on the prepaid funds. We reclassify this interest income as a reduction in the transmission and distribution costs expensed each period to reflect the net cost to the business.
▪In October 2019, we acquired Capital Power's 50 per cent ownership of Keephills 3 in exchange for selling our 50 per cent ownership in the Genesee 3 facility to Capital Power, and we now own 100 per cent of the Keephills 3 facility. As a result, all of the Keephills 3 and Genesee 3 project agreements with Capital Power were terminated, including the agreement governing the supply of coal from TransAlta’s Highvale mine to the Keephills 3 facility. Upon termination of this agreement in the fourth quarter of 2019, the Highvale mine had no future performance obligations and, accordingly, the balance of the contract liability of $88 million was recognized in earnings. On a comparable basis, we removed this gain from 2019 results.
▪Asset impairment charges (reversals) are removed to calculate comparable EBITDA as these are accounting adjustments that impact depreciation and amortization and do not reflect business performance.
▪During the fourth quarter of 2020, we acquired a 49 per cent interest in the Skookumchuck wind facility, which is treated as an equity investment under IFRS and our proportionate share of the net earnings is reflected as equity income on the statement of earnings under IFRS. As this investment is part of our regular power-generating operations, we have included our proportionate share of the comparable EBITDA of Skookumchuck in our total comparable EBITDA. In addition, in the Wind and Solar comparable results, we have included our proportionate share of revenues and expenses to reflect the full operational results of this investment. We have not included EMG's comparable EBITDA in our total comparable EBITDA as it does not represent our regular power-generating operations.
▪During the fourth quarter of 2020, we recorded an onerous contract provision on the coal supply contract for Sheerness as we accelerated our plans to eliminate coal as a fuel source by the end of 2021. This is a one-time charge that is not reflective of ongoing operations and therefore has been removed for comparable EBITDA.




TRANSALTA CORPORATION M29

Management’s Discussion and Analysis
A reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA results is set out below:
Year ended Dec. 31 2020 2019 2018
Net earnings (loss) attributable to common shareholders (336) 52  (248)
Net earnings attributable to non-controlling interests 34  94  108 
Preferred share dividends 49  30  50 
Net earnings (loss) (253) 176  (90)
Adjustments to reconcile net income to comparable EBITDA    
Income tax expense (recovery) (50) 17  (6)
Gain on sale of assets and other (9) (46) (1)
Foreign exchange (gain) loss (17) 15  15 
Net interest expense 238  179  250 
Equity income (1) —  — 
Depreciation and amortization 654  590  574 
Comparable reclassifications
Decrease in finance lease receivables 17  24  59 
Mine depreciation included in fuel cost 145  121  140 
Australian interest income 4  4  4 
Unrealized mark-to-market (gains) losses 46  (33) 38 
Adjustments to earnings to arrive at comparable EBITDA
Impact of Sheerness going off coal(1)
29  —  — 
Impacts associated with Mississauga recontracting(2)
—  —  105 
Gain on termination of Keephills 3 coal rights contract —  (88) — 
Coal inventory writedown 37  —  — 
Asset impairment (3)
84  25  73 
Share of adjusted EBITDA from joint venture(4)
3  —  — 
Comparable EBITDA 927  984  1,161 
Comparable EBITDA – excluding the PPA Termination Payments 927  928  1,004 
(1) During the fourth quarter of 2020, a decision was made to accelerate our plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. As such, the existing coal supply contract has been classified as an onerous contract and the remaining expected contract payments have been accrued for in the current year.
(2) Impacts associated with Mississauga facility recontracting for the year ended Dec. 31, 2018, are as follows: revenue ($108 million) and fuel and purchased power and de-designated hedges ($3 million).
(3) Asset impairment for 2020 primarily includes the retirement of Sundance Unit 3 ($70 million), impairment on a BC hydro facility ($2 million), impairment on the Centralia land ($9 million) and asset impairments resulting from changes in discount rates for the decommissioning and restoration liabilities for our retired assets (2019 — $141 million increase for the decommissioning and restoration liability at the Centralia mine, $15 million for trucks held for sale and written down to net realizable value and the $18 million write-off of project development costs, partially offset by a $151 million impairment reversal at Centralia; 2018 — $38 million charge related to the retirement of Sundance Unit 2, Lakeswind and Kent Breeze impairment of $12 million and a write-off of project development costs of $23 million). For further details, please refer to the Critical Accounting Estimates section of this MD&A.
(4) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

Funds from Operations and Free Cash Flow 
Funds from Operations ("FFO") is an important metric as it provides a proxy for cash generated from operating activities before changes in working capital and provides the ability to evaluate cash flow trends in comparison with results from prior periods. FCF is an important metric as it represents the amount of cash that is available to invest in growth initiatives, make scheduled principal repayments on debt, repay maturing debt, pay common share dividends or repurchase common shares. Changes in working capital are excluded so FFO and FCF are not distorted by changes that we consider temporary in nature, reflecting, among other things, the impact of seasonal factors and timing of receipts and payments. FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period.





TRANSALTA CORPORATION M30

Management’s Discussion and Analysis
The table below reconciles our cash flow from operating activities to our FFO and FCF:. (
Year ended Dec. 31 2020 2019 2018
Cash flow from operating activities(1)(2)
702  849  820 
Change in non-cash operating working capital balances (89) (121) 44 
Cash flow from operations before changes in working capital 613  728  864 
Adjustments    
Share of adjusted FFO from joint venture(2)
3  —  — 
Decrease in finance lease receivable 17  24  59 
Coal inventory writedown 37  —  — 
Other 15  5  4 
FFO 685  757  927 
Deduct:    
Sustaining capital(2)
(157) (141) (150)
Productivity capital (4) (9) (21)
Dividends paid on preferred shares (39) (40) (40)
Distributions paid to subsidiaries’ non-controlling interests (102) (111) (169)
Principal payments on lease liabilities(2)
(25) (21) (18)
Other —  —  (5)
FCF 358  435  524 
Weighted average number of common shares outstanding in the year 275  283  287 
FFO per share 2.49  2.67  3.23 
FCF per share 1.30  1.54  1.83 
(1) 2019 and 2018 amounts include the PPA Termination Payments. See the Significant and Subsequent Events section for further details.
(2) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

The table below bridges our comparable EBITDA to our FFO and FCF:
Year ended Dec. 31 2020 2019 2018
Comparable EBITDA(1)
927  984  1,161 
Provisions and other 7  13  (9)
Interest expense(2)
(192) (174) (187)
Current income tax expense(2)
(35) (35) (28)
Realized foreign exchange gain (loss) 8  (6) 5 
Decommissioning and restoration costs settled(2)
(18) (34) (31)
Other cash and non-cash items (12) 9  16 
FFO 685  757  927 
Deduct:    
Sustaining capital(2)
(157) (141) (150)
Productivity capital (4) (9) (21)
Dividends paid on preferred shares (39) (40) (40)
Distributions paid to subsidiaries’ non-controlling interests (102) (111) (169)
Principal payments on lease liabilities(2)
(25) (21) (18)
Other —  —  (5)
FCF 358  435  524 
(1) 2019 and 2018 amounts include the PPA Termination Payments. See the Significant and Subsequent Events section for further details.
(2) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.






TRANSALTA CORPORATION M31

Management’s Discussion and Analysis
Supplemental disclosure 2020 2019 2018
FFO – excluding the PPA Termination Payments 685  701  770 
FCF – excluding the PPA Termination Payments 358  379  367 
FFO per share – excluding the PPA Termination Payments 2.49  2.48  2.68 
FCF per share – excluding the PPA Termination Payments 1.30  1.34  1.28 

For explanations for the current period, please refer to the Highlights section of this MD&A.

FCF in 2019, after adjusting for the PPA Termination Payments, increased $12 million compared to 2018, primarily as a result of lower sustaining and productivity capital expenditures and lower distributions paid to subsidiaries' non-controlling interests. Significant changes in segmented cash flows are highlighted in the Segmented Comparable Results section of this MD&A.

The table below bridges our reported EBITDA of our owned assets to our comparable EBITDA:
Year ended Dec. 31, 2020 Reported
Adjustments(1)
Joint venture investment(2)
Comparable total
Revenues 2,101  70  3  2,174 
Fuel, carbon compliance and purchased power 968  (186) —  782 
Gross margin 1,133  256  3  1,392 
Operations, maintenance and administration 472  —  —  472 
Asset impairment 84  (84) —  — 
Taxes, other than income taxes 33  —  —  33 
Net other operating income (expense) (11) (29) —  (40)
Comparable EBITDA 555  369  3  927 
(1) Refer to the reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA table above for details of all adjustments.
(2) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.


 




TRANSALTA CORPORATION M32

Management’s Discussion and Analysis
Fourth Quarter
Consolidated Financial Highlights
Three months ended Dec. 31 2020 2019
Adjusted availability (%)(1)
87.1  91.6 
Production (GWh)(1)
7,704  8,153 
Revenues 544  609 
Fuel, carbon compliance and purchased power(3)
327  286 
Operations, maintenance and administration 118  127 
Net earnings (loss) attributable to common shareholders (167) 66 
Cash flow from operating activities 110  181 
Comparable EBITDA(2),(3)
234  243 
FFO(2)
161  189 
FCF(2)
52  121 
Net earnings (loss) per share attributable to common shareholders, basic and diluted (0.61) 0.24 
FFO per share(2)
0.59  0.67 
FCF per share(2)
0.19  0.43 
Dividends declared per common share(4)
0.09  0.04 
Dividends declared per preferred share(5)
0.50  0.26 
(1) Adjusted availability and production include all generating assets that we operate and finance leases and exclude hydro assets and equity investments.
(2) These items are not defined and have no standardized meaning under IFRS. Presenting these items from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Please refer to the Discussion of Consolidated Financial Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(3) During the fourth quarter of 2020, we reclassified interest expense on the AESO transmission line loss from fuel costs to interest expense.
(4) Dividends declared vary year over year due to timing of dividend declarations.
(5) Weighted average of the Series A, B, C, E and G preferred share dividends declared. Dividends declared vary year over year due to timing of dividend declarations.

Financial Highlights 
During the fourth quarter of 2020, the Corporation demonstrated strong performance at the Wind and Solar and North American Gas segments with the addition of new facilities,and higher wind resources, which was more than offset by the expected impact on EBITDA of the Sundance Unit 6 turnaround and conversion to gas outage at Alberta Thermal and high levels of volatility in the market impacting the Energy Marketing segment.

FCF in the fourth quarter of 2020 was $52 million compared to $121 million in the same period of 2019, mainly due to lower comparable EBITDA, higher interest expense, higher sustaining capital expenditures, increased distributions paid to subsidiary non-controlling interests and final settlement of lease payments at the Highvale mine. FFO was $161 million, which was $28 million lower than the fourth quarter of 2019, also mainly due to lower comparable EBITDA and higher interest expense relating to new debt issuances.

Net loss attributable to common shareholders in the fourth quarter of 2020 was $167 million compared to net earnings of $66 million in the same period of 2019, a decrease of $233 million. The net loss in 2020 was impacted by lower availability, which reduced revenues, the additional coal inventory writedowns of $15 million from an increased cost of coal and higher depreciation from the acceleration of the Highvale mine closure of $8 million, the onerous contract provision recognized on the coal contract for Sheerness for $29 million and higher interest expense associated with the TEC Offering and the second tranche of the Brookfield Investment, partially offset by lower asset impairments. The prior year also benefited from the gain on the termination of the Keephills 3 coal rights contract of $88 million and the gain on the sale of Genesee 3 of $77 million.





TRANSALTA CORPORATION M33

Management’s Discussion and Analysis
Segmented Cash Flow Generated by the Business and Operational Performance
Segmented cash flow generated by the business measures the net cash generated by each of our segments after sustaining and productivity capital expenditures, reclamation costs and provisions. It also excludes non-cash mark-to-market gains or losses. This is the cash flow available to pay our interest, and cash taxes, distributions to our non-controlling partners, dividends to our preferred shareholders, grow the business, pay down debt and return capital to our shareholders.

Segmented cash flow and operational performance for the business for the three months ended Dec. 31, 2020 and 2019 is as follows:
Three months ended Dec. 31 2020 2019
Segmented cash flow(1)
Hydro 11  13 
Wind and Solar 80  72 
North American Gas(2)
28  22 
Australian Gas 24  25 
Alberta Thermal(3)
(10) 37 
Centralia(3)
28  25 
Generation segmented cash flow 161  194 
Energy Marketing 15  31 
Corporate(4)
(28) (29)
Total segmented cash flow 148  196 
(1) This is not defined and has no standardized meaning under IFRS. Presenting this item from period to period provides management and investors with the ability to evaluate earnings trends more readily in comparison with prior periods’ results. Please refer to the Discussion of Consolidated Financial Results section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020
(3) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
(4) Includes gains and losses on the total return swap.

Availability for the three months ended Dec. 31, 2020, was lower than with the same period in 2019, mainly due to the Sundance Unit 6 planned turnaround and conversion to gas outage at Alberta Thermal in late 2020, which was partially offset by higher availability at Centralia due to lower unplanned outages and derates. Production was lower for the three months ended Dec. 31, 2020, compared to the same period in 2019, primarily due to lower availability and economic dispatch at Alberta Thermal, partially offset by higher wind resources at Wind and Solar.

Segmented cash flow generated by the business totalled $148 million in the fourth quarter, a decrease of $48 million compared with last year’s performance. The decrease in cash flow is largely due to lower availability resulting from planned outages and additional sustaining capital spend resulting from the Sundance Unit 6 turnaround and conversion to gas outages at Alberta Thermal and lower cash flows from Energy Marketing due to market volatility. This was partially offset by increased segmented cash flows at North American Gas with the addition of the Ada facility, lower capital expenditures and higher margins at our Sarnia facility. In addition, segmented cash flows at Wind and Solar increased as a result of the addition of the Skookumchuck wind facility and full year of operations for Big Level and Antrim.




TRANSALTA CORPORATION M34

Management’s Discussion and Analysis
Discussion of Consolidated Financial Results for the Fourth Quarter
Comparable EBITDA
A reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA results is set out below:
Three months ended Dec. 31 2020 2019
Net earnings (loss) attributable to common shareholders (167) 66 
Net earnings attributable to non-controlling interests 5  27 
Preferred share dividends 19  10 
Net earnings (loss) (143) 103 
Adjustments to reconcile net income to comparable EBITDA
Income tax expense (25) 40 
Gain on sale of assets and other (7) (64)
Foreign exchange (gain) loss (2) (3)
Net interest expense 63  18 
Equity income (1) — 
Depreciation and amortization 173  154 
Comparable reclassifications
Decrease in finance lease receivables 6  5 
Mine depreciation included in fuel cost 58  31 
Australian interest income 1  1 
Unrealized mark-to-market (gains) losses 47  (1)
Adjustments to earnings to arrive at comparable EBITDA
Inventory writedown 15  — 
Impact of Sheerness going off-coal(1)
29  — 
Asset impairment charge(2)
17  47 
Gain on termination of Keephills 3 coal rights contract —  (88)
Share of adjusted EBITDA from joint venture(3)
3  — 
Comparable EBITDA 234  243 
(1) During the fourth quarter of 2020, a decision was made to accelerate our plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. As such, the existing coal supply contract has been classified as an onerous contract and the remaining expected contract payments have been accrued for in the current year.
(2) Asset impairment charges for the three months ended Dec. 31, 2020, primarily relates to the impairment on the Centralia land ($9 million) relating to Centralia land and asset impairments resulting from changes in discount rates for the decommissioning and restoration liabilities for our retired assets (2019 — $32 million increase for the decommissioning and restoration liability at the Centralia mine and $15 million for trucks held for sale and written down to net realizable value).
(3) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

A summary of our comparable EBITDA by segment for the three months ended Dec. 31, 2020 and 2019 is as follows:
Three months ended Dec. 31 2020 2019
Comparable EBITDA    
Hydro 22  18 
Wind and Solar 77  80 
North American Gas(1)
32  29 
Australian Gas 31  28 
Alberta Thermal(2)
41  55 
Centralia(2)
30  29 
Energy Marketing 23  26 
Corporate (22) (22)
Total Comparable EBITDA 234  243 
(1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020.
(2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.




TRANSALTA CORPORATION M35

Management’s Discussion and Analysis
Comparable EBITDA decreased by $9 million for the fourth quarter 2020, compared to 2019, primarily as a result of:
▪Hydro results were $4 million higher due to increased revenues from higher water resources and lower fuel and purchased power costs primarily resulting from allocated AESO transmission line loss recoveries.
▪Wind and Solar results were down $3 million mainly due to provisions for the AESO transmission line loss and insurance proceeds benefiting 2019, partially offset by higher production volumes and additional earnings from Skookumchuck.
▪Our North American Gas business was up $3 million mainly due to the addition of the new Ada facility and higher margins at our Sarnia facility.
▪Australian Gas was up $3 million, mainly due to lower legal costs.
▪Our Alberta Thermal results were down $14 million mainly due to lower production and increased fuel costs incurred from the acceleration of the Highvale mine closing and higher costs of coal.
▪Centralia results were consistent with the prior year's fourth quarter results as lower revenues were offset with decreases in fuel and purchased power costs and lower OM&A due to dispatch optimization.
▪Energy Marketing’s comparable EBITDA was down $3 million, mainly due to continued high levels of volatility in the market.
▪Corporate costs were consistent with the prior year's fourth quarter results. Impacts from the total return swap on our share-based payment plans were similar in 2020 compared to 2019.

Funds from Operations and Free Cash Flow
FFO per share and FCF per share are calculated as follows using the weighted average number of common shares outstanding during the period. FFO, FFO per share, FCF and FCF per share are non-IFRS measures, are not defined under IFRS, and therefore should not be considered in isolation or as an alternative to or to be more meaningful than cash flow from operating activities as determined in accordance with IFRS, when assessing our financial performance or liquidity. See the Additional IFRS Measures and Non-IFRS Measures section in this MD&A for further details.

The table below reconciles our cash flow from operating activities to our FFO and FCF for the three months ended Dec. 31, 2020 and 2019: 

Three months ended Dec. 31 2020 2019
Cash flow from operating activities 110  181 
Change in non-cash operating working capital balances 25  1 
Cash flow from operations before changes in working capital 135  182 
Adjustments    
Share of adjusted FFO from joint venture(1)
3  — 
Decrease in finance lease receivable 6  5 
Coal inventory writedown 15  — 
Other 2  2 
FFO 161  189 
Deduct:    
Sustaining capital(1)
(58) (30)
Productivity capital (3) (2)
Dividends paid on preferred shares (9) (10)
Distributions paid to subsidiaries’ non-controlling interests (29) (22)
Principal payments on lease liabilities(1)
(10) (5)
Other —  1 
FCF 52  121 
Weighted average number of common shares outstanding in the period 273  280 
FFO per share 0.59  0.67 
FCF per share 0.19  0.43 
(1) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.






TRANSALTA CORPORATION M36

Management’s Discussion and Analysis
The table below provides a reconciliation of our comparable EBITDA to our FFO and FCF for the three months ended Dec. 31, 2020 and 2019:
Three months ended Dec. 31 2020 2019
Comparable EBITDA 234  243 
Provisions (10) (1)
Interest expense(1)
(56) (41)
Current income tax expense(1)
5  (7)
Realized foreign exchange gain (loss) (1) 1 
Decommissioning and restoration costs settled(1)
(5) (10)
Other non-cash items (6) 4 
FFO 161  189 
Deduct:
Sustaining capital(1)
(58) (30)
Productivity capital (3) (2)
Dividends paid on preferred shares (9) (10)
Distributions paid to subsidiaries’ non-controlling interests (29) (22)
Principal payments on lease liabilities(1)
(10) (5)
Other —  1 
Comparable FCF 52  121 
Weighted average number of common shares outstanding in the period 273  280 
Comparable FFO per share 0.59  0.67 
Comparable FCF per share 0.19  0.43 
(1) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.

The table below bridges our reported EBITDA of our owned assets to our comparable EBITDA:
Year ended Dec. 31, 2020 Reported
Adjustments(1)
Joint venture investment(2)
Comparable total
Revenues 544  56  3  603 
Fuel, carbon compliance and purchased power 327  (74) —  253 
Gross Margin 217  130  3  350 
Operations, maintenance and administration 118  —  —  118 
Asset impairment 17  (17) —  — 
Taxes, other than income taxes 8  —  —  8 
Net other operating income (expense) 19  (29) —  (10)
Comparable EBITDA 55  176  3  234 
(1) Please refer to the reconciliation of net earnings (loss) attributable to common shareholders to comparable EBITDA table above for details of all adjustments.
(2) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.





TRANSALTA CORPORATION M37

Management’s Discussion and Analysis
Selected Quarterly Information
Our results are seasonal due to the nature of the electricity market and related fuel costs. Higher maintenance costs are often incurred in the spring and fall when electricity prices are expected to be lower, as electricity prices generally increase in the peak winter and summer months in our main markets due to increased heating and cooling loads. Margins are also typically impacted in the second quarter due to the volume of hydro production resulting from spring runoff and rainfall in the Pacific Northwest, which impacts production at Centralia. Typically, hydroelectric facilities generate most of their electricity and revenues during the spring months when melting snow starts feeding watersheds and rivers. Inversely, wind speeds are historically greater during the cold winter months and lower in the warm summer months.
  Q1 2020 Q2 2020 Q3 2020 Q4 2020
Revenues 606  437  514  544 
Comparable EBITDA 220  217  256  234 
FFO 172  159  193  161 
Net earnings (loss) attributable to common shareholders 27  (60) (136) (167)
Net earnings (loss) per share attributable to common shareholders,
   basic and diluted(1)
0.10  (0.22) (0.50) (0.61)
  Q1 2019 Q2 2019 Q3 2019 Q4 2019
Revenues 648  497  593  609 
Comparable EBITDA 221  215  305  243 
FFO 169  155  244  189 
Net earnings (loss) attributable to common shareholders (65) —  51  66 
Net earnings (loss) per share attributable to common shareholders,
   basic and diluted(1)
(0.23) —  0.18  0.24 
(1) Basic and diluted earnings per share attributable to common shareholders and comparable earnings per share are calculated each period using the weighted average common shares outstanding during the period. As a result, the sum of the earnings per share for the four quarters making up the calendar year may sometimes differ from the annual earnings per share.
 
Reported net earnings, comparable EBITDA and FFO are generally higher in the first and fourth quarters due to higher demand associated with the cold winter months in the markets in which we operate and lower planned outages.
 
Net earnings (loss) attributable to common shareholders has also been impacted by the following variations and events:
▪Revenues declined due to weaker market conditions in 2020 as a result of COVID-19 and low oil prices;
▪Impact of Sheerness going off-coal, which has resulted in the remaining coal supply payments on the existing coal supply agreement being recognized as an onerous contract in the fourth quarter of 2020;
▪Coal inventory writedowns in the third and fourth quarters of 2020;
▪Impact of the updated provision estimates for the AESO transmission line loss during the last three quarters of 2020;
▪Significant foreign exchange gains in the last three quarters of 2020 more than offset foreign exchange losses experienced during the first quarter of 2020, while 2019 experienced overall foreign exchange losses for the year;
▪Gains relating to the Keephills 3 and Genesee 3 swap in the fourth quarter of 2019;
▪Effects of impairments and reversals during the second, third and fourth quarters of 2020 and the third and fourth quarters of 2019;
▪Effects of changes in decommissioning and restoration provision in the third quarter of 2020 and third quarter of 2019;
▪Effects of changes in useful lives of certain assets during the third quarter of 2020 and third quarter of 2019;
▪Change in income tax rates in Alberta in the second quarter of 2019;
▪Lower scheduled payments commencing in January 2019 from the Poplar Creek finance lease; and
▪Recognition of $56 million received on winning the arbitration against the Balancing Pool in the third quarter of 2019.





TRANSALTA CORPORATION M38

Management’s Discussion and Analysis
Key Financial Ratios
 
The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined and have no standardized meaning under IFRS and may not be comparable to those used by other entities or by rating agencies. We maintained a strong and flexible financial position in 2020.
 
Funds from Operations before Interest to Adjusted Interest Coverage
For the year ended Dec. 31 2020 2019 2018
FFO(1)
685  757  927 
Less: PPA Termination Payments —  (56) (157)
Add: Interest on debt, exchangeable debentures and leases, net of interest income and
   capitalized interest(2)
182  166  174 
FFO before interest 867  867  944 
Interest on debt, exchangeable securities and leases, net of interest income(2)(3)
185  172  176 
Add: 50 per cent of dividends paid on preferred shares(3)
22  20  20 
Adjusted interest 207  192  196 
FFO before interest to adjusted interest coverage (times) 4.2  4.5  4.8 
(1) See the Discussion of Consolidated Financial Results section in this MD&A for reconciliation of cash flow from operating activities to FFO. See also the IFRS Measures and Non-IFRS Measures section for further details.
(2) The interest on tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in the amounts.
(3) Exchangeable preferred shares are considered equity with dividend payments for credit purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements.

Our target for FFO before interest to adjusted interest coverage is four to five times. While all periods are within our target range, the ratio decreased in 2020 compared to 2019, mainly due to lower FFO before interest.

Adjusted FFO to Adjusted Net Debt
As at Dec. 31 2020 2019 2018
FFO(1)(2)
685  757  927 
Less: PPA Termination Payments(1)
—  (56) (157)
Add: 100 per cent of interest paid on exchangeable preferred shares (3)
5  —  — 
Less: 50 per cent of dividends paid on preferred shares(1)(3)
(22) (20) (20)
Adjusted FFO(1)
668  681  750 
Period-end long-term debt(4)
3,361  3,212  3,267 
Exchangeable securities 730  326  — 
Less: 100 per cent of exchangeable preferred shares(3)
(400) —  — 
Less: Cash and cash equivalents (703) (411) (89)
Less: Principal portion of TransAlta OCP restricted cash (11) (10) (27)
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(3)
671  471  471 
Fair value asset of hedging instruments on debt(5)
(2) (7) (10)
Adjusted net debt(6)
3,646  3,581  3,612 
Adjusted FFO to adjusted net debt (%) 18.3  19.0 20.8 
(1) Last 12 months.
(2) Refer to the Discussion of Consolidated Financial Results section of this MD&A for the reconciliation of cash flow from operating activities to FFO. See also the IFRS Measures and Non-IFRS Measures section for further details.
(3) Exchangeable preferred shares are considered equity with dividend payments for credit purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements.
(4) Includes lease liabilities and tax equity financing.
(5) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2020, Dec. 31, 2019, and Dec. 31, 2018.
(6) The tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in the amounts.

Our target range for adjusted FFO to adjusted net debt is 20 to 25 per cent. Our adjusted FFO to adjusted net debt declined due to lower adjusted FFO compared with 2019, partially due to higher adjusted net debt. We reached the low end of our target range of 20 to 25 per cent in 2018.
 




TRANSALTA CORPORATION M39

Management’s Discussion and Analysis
Adjusted Net Debt to Adjusted Comparable EBITDA
As at Dec. 31 2020 2019 2018
Period-end long-term debt(1)
3,361  3,212  3,267 
Exchangeable securities 730  326  — 
Less: 100 per cent of exchangeable preferred shares(2)
(400) —  — 
Less: Cash and cash equivalents (703) (411) (89)
Less: Principal portion of TransAlta OCP restricted cash (11) (10) (27)
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(2)
671  471  471 
Fair value asset of hedging instruments on debt(3)
(2) (7) (10)
Adjusted net debt(4)
3,646  3,581  3,612 
Comparable EBITDA(5)
927  984  1,161 
Less: PPA Termination Payments(5)
—  (56) (157)
Adjusted comparable EBITDA(5)
927  928  1,004 
Adjusted net debt to adjusted comparable EBITDA (times) 3.9  3.9  3.6 
(1) Includes lease liabilities and tax equity financing.
(2) Exchangeable preferred shares are considered equity with dividend payments for credit purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements.
(3) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2020, Dec. 31, 2019, and Dec. 31, 2018.
(4) The tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in the amounts.
(5) Last 12 months.

Our target for adjusted net debt to comparable EBITDA is 3.0 to 3.5 times. Our adjusted net debt to comparable EBITDA ratio was consistent to 2019, as adjusted net debt only increased slightly during the year.





TRANSALTA CORPORATION M40

Management’s Discussion and Analysis
Deconsolidated Net Debt to Deconsolidated Comparable EBITDA
In addition to reviewing fully consolidated ratios and results, management reviews net debt to comparable EBITDA on a deconsolidated basis to highlight TransAlta's financial flexibility, balance sheet strength and leverage, excluding the portion of TransAlta Renewables and TransAlta Cogeneration L.P. ("TA Cogen") that are not owned by TransAlta. These metrics and ratios are not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies. See also the IFRS Measures and Non-IFRS Measures section of this MD&A for further details.
As at Dec. 31 2020 2019 2018
Period-end long-term debt(1)
3,361  3,212  3,267 
Exchangeable securities 730  326  — 
Less: 100 per cent of exchangeable preferred shares(2)
(400) —  — 
Less: Cash and cash equivalents (703) (411) (89)
Add: TransAlta Renewables cash and cash equivalents(3)
582  63  73 
Less: Principal portion of TransAlta OCP restricted cash (11) (10) (27)
Add: 50 per cent of issued preferred shares(2)
671  471  471 
Fair value asset of hedging instruments on debt(4)
(2) (7) (10)
Less: TransAlta Renewables long-term debt (692) (961) (932)
Less: US tax equity financing and South Hedland debt(5)
(905) (145) (28)
Deconsolidated net debt 2,631  2,538  2,725 
Comparable EBITDA(6)(7)
927  984  1,161 
Less: PPA Termination Payments(6)
—  (56) (157)
Less: TransAlta Renewables comparable EBITDA(6)
(462) (438) (430)
Less: TA Cogen comparable EBITDA(6)
(54) (80) (181)
Less: comparable EBITDA from equity accounted investments(8)
(3) —  — 
Add: Dividends from TransAlta Renewables(6)
151  151  151 
Add: Dividends from TA Cogen(6)
17  37  86 
Deconsolidated comparable EBITDA(6)(7)
576  598  630 
Deconsolidated net debt to deconsolidated comparable EBITDA(6)(7) (times)
4.6  4.2  4.3 
(1) Includes lease liabilities and tax equity financing.
(2) Exchangeable preferred shares are considered equity with dividend payments for credit purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements.
(3) In the second quarter of 2020, we adjusted the calculation to remove the portion of cash relating to TransAlta Renewables' cash and cash equivalents to reflect deconsolidated cash. Prior periods have also been updated.
(4) Included in risk management assets and/or liabilities on the consolidated financial statements as at Dec. 31, 2020, Dec. 31, 2019, and Dec. 31, 2018.
(5) Relates to assets where TransAlta Renewables has economic interests.
(6) Last 12 months.
(7) During the fourth quarter of 2020, we revised comparable EBITDA to exclude the interest on the AESO transmission line loss.
(8) Represents our share of amounts for Skookumchuck, an equity accounted joint venture.

Our target for deconsolidated net debt to deconsolidated comparable EBITDA is 2.5 to 3.0 times. Our deconsolidated net debt to deconsolidated comparable EBITDA ratio increased compared with 2019, as higher deconsolidated net debt was partially offset by higher deconsolidated comparable EBITDA.






TRANSALTA CORPORATION M41

Management’s Discussion and Analysis
Deconsolidated Comparable EBITDA by Segment
Comparable EBITDA is a key metric for TransAlta and TransAlta Renewables and provides management and shareholders a representation of core business profitability. Deconsolidated EBITDA is used in key planning and credit metrics and segment results highlight the operating performance of assets held directly at TransAlta that are comparable from period to period.

A reconciliation of comparable EBITDA to deconsolidated comparable EBITDA by segment results is set out below:

2020 2019 2018
TransAlta Consolidated TransAlta Renewables TransAlta Deconsolidated TransAlta Consolidated TransAlta Renewables TransAlta Deconsolidated TransAlta Consolidated TransAlta Renewables TransAlta Deconsolidated
Hydro 105  21  110  18  109 17 
Wind and Solar 248  256  231  238  233 218 
North American Gas 117  80  120  82  259 84 
Australian Gas 124  125  118  120  124 130 
Alberta Thermal 162  —  319  —  389 — 
Centralia 139  —  73  —  91 — 
Energy Marketing 113  —  89  —  43 — 
Corporate (81) (20) (76) (20) (87) (19)
Comparable EBITDA(1)(2)
927  462  465  984  438  546  1,161  430  731 
Less: TA Cogen comparable
EBITDA 		(54) (80) (181)
Less: Termination of
   Sundance B and C PPAs(1)
—  (56) (157)
Less: EBITDA from joint
   venture investments(3)
(3) —  — 
Add: Dividend from
   TransAlta Renewables((1)
151  151  151 
Add: Dividend from
   TA Cogen(1)
17  37  86 
Deconsolidated TransAlta
comparable EBITDA 		576  598  630 
(1) Last 12 months.
(2) During the fourth quarter of 2020, we revised comparable EBITDA to exclude the interest on the AESO transmission line loss.
(3) Represents our share of amounts for Skookumchuck, an equity accounted joint venture.





TRANSALTA CORPORATION M42

Management’s Discussion and Analysis
Deconsolidated FFO
The Corporation has set a target to return 10 to 15 per cent of TransAlta's deconsolidated FFO to shareholders as it aligns shareholder returns to the assets held directly at TransAlta. This metric is not defined and has no standardized meaning under IFRS, and may not be comparable to those used by other entities or by rating agencies. See also the IFRS Measures and Non-IFRS Measures section of this MD&A for further details. Deconsolidated FFO for the years ended Dec. 31 is detailed below:

2020 2019 2018
TransAlta Consolidated TransAlta Renewables TransAlta Deconsolidated TransAlta Consolidated TransAlta Renewables TransAlta Deconsolidated TransAlta Consolidated TransAlta Renewables TransAlta Deconsolidated
Cash flow from operating
activities 		702  267  849  331  820  385 
Change in non-cash
operating working capital
balances 		(89) 31  (121) (23) 44  5 
Cash flow from operations
before changes in working
capital 		613  298  728  308  864  390 
Adjustments:
   Decrease in finance lease
receivable 		17  —  24  —  59  — 
   Coal inventory writedown 37  —  — 
Share of FFO from joint
 venture(1)
3  —  —  —  —  — 
   Finance and interest
income - economic
interests 		—  (69) —  (76) —  (171)
   Adjusted FFO - economic
interests 		—  148  —  146  —  162 
   Other 15  —  5  —  4  — 
FFO 685  377  308 757  378  379 927  381  546
Dividend from TransAlta
Renewables 		151  151  151 
Distributions to TA Cogen's
Partner 		(17) (37) (86)
Less: Share of adjusted FFO
   from joint venture(1)
(3) —  — 
Less: PPA Termination
Payments 		—  (56) (157)
Deconsolidated
TransAlta FFO 		439  437  454 
(1) Represents our share of amounts for Skookumchuck, an equity accounted joint venture.





TRANSALTA CORPORATION M43

Management’s Discussion and Analysis
Financial Position
The following table highlights significant changes in the consolidated statements of financial position from Dec. 31, 2019, to Dec. 31, 2020:
  Increase
Assets Dec. 31, 2020 Dec. 31, 2019 (decrease)
Cash and cash equivalents 703  411  292 
Restricted cash 71  32  39 
Trade and other receivables 583  462  121 
Risk management assets (current and long-term) 692  806  (114)
Assets held for sale 105  —  105 
Investments 100  —  100 
Finance lease receivables (long-term) 228  176  52 
Property, plant and equipment, net 5,822  6,207  (385)
Deferred income tax assets 51  18  33 
Others(1)
1,392  1,396  (4)
Total assets 9,747  9,508  239 
Liabilities and equity
Accounts payable and accrued liabilities 599  413  186 
Credit facilities, long-term debt and lease liabilities (current and
long-term) 		3,361  3,212  149 
Exchangeable securities 730  326  404 
Decommissioning and other provisions (current and long-term) 673  546  127 
Risk management liabilities (current and long-term) 162  110  52 
Deferred income tax liabilities 396  472  (76)
Equity attributable to shareholders 2,352  2,961  (609)
Others(2)
1,474  1,468  6 
Total liabilities and equity 9,747  9,508  239 
(1) Includes prepaid expenses, inventory, right-of-use assets, intangible assets, goodwill and other assets.
(2) Includes income taxes payable, dividends payable, contract liabilities, defined benefit obligation and other long-term liabilities and non-controlling interests.






TRANSALTA CORPORATION M44

Management’s Discussion and Analysis
Significant changes in TransAlta's consolidated statements of financial position were as follows:
▪See the cash flow section of this MD&A for details on the change in cash during the period.
▪Restricted cash increased by $45 million related to the TEC Notes, offset by a reduction in the Big Level and Antrim restricted cash balances.
▪Trade and other receivables increased largely due to timing of customer receipts, partially offset by lower collateral payments.
▪Risk management assets, net of liabilities, decreased primarily due to contract settlements and changes in market prices and foreign exchange rates.
▪Assets held for sale relate primarily to the future sale of the Pioneer Pipeline.
▪Investments increased due to the acquisition of Skookumchuck and EMG during the fourth quarter of 2020.
▪Finance lease receivables increased in the year with the execution of the BHP Nickle West contract extension.
▪PP&E decreased due to depreciation ($717 million), the reclass of pipeline and certain mining equipment to assets held for sale ($105 million), the reclass of the Southern Cross facility to finance lease receivables ($69 million) and asset impairments ($81 million). This was partially offset by additions ($486 million) relating to assets under construction for the conversion to gas, the Windrise wind facility, WindCharger battery storage project, the Kaybob cogeneration project, land and planned major maintenance expenditures. In addition, there were net revisions for increasing decommissioning provisions as a result of changes in cash flows and discount rates ($94 million).
▪Deferred income tax assets increased mainly due to lower earnings in Canada compared to the same period last year.
▪Accounts payable and accrued liabilities increased largely due to timing of payments for operational payables.
▪Credit facilities, long-term debt and lease liabilities increased due to TEC Notes issued in the fourth quarter 2020. This was partially offset by the repayment of $400 million of debentures, repayment of the credit facility ($106 million) and other scheduled principal payments ($86 million).
▪Exchangeable securities increased due to the $400 million invested by Brookfield on Oct. 30, 2020, in exchange for redeemable, retractable first preferred shares as part of the Brookfield Investment.
▪Decommissioning and other provisions have increased mainly due to revisions in estimated cash flows ($72 million), changes in discount rates ($36 million), liabilities incurred ($35 million) and accretion ($30 million), which was partially offset by liabilities settled ($37 million).
▪Equity attributable to shareholders decreased mainly due to net losses for the period ($287 million), common and preferred share dividend payments ($107 million), net losses on cash flow hedges ($91 million), fair value investments losses ($50 million), actuarial losses on defined benefit plans ($11 million) and the share repurchases under the NCIB ($61 million).






TRANSALTA CORPORATION M45

Management’s Discussion and Analysis
Cash Flows
The following chart highlights significant changes in the consolidated statements of cash flows for the years ended Dec. 31, 2020, Dec. 31, 2019, and Dec. 31, 2018:
 
Year ended Dec. 31 2020 2019 Increase/ (decrease)
Cash and cash equivalents, beginning of year 411  89  322 
Provided by (used in):    
Operating activities 702  849  (147)
Investing activities (687) (512) (175)
Financing activities 272  (14) 286 
Translation of foreign currency cash 5  (1) 6 
Cash and cash equivalents, end of year 703  411  292 
Year ended Dec. 31 2019 2018 Increase/ (decrease)
Cash and cash equivalents, beginning of year 89  314  (225)
Provided by (used in):    
Operating activities 849  820  29 
Investing activities (512) (394) (118)
Financing activities (14) (651) 637 
Translation of foreign currency cash (1) —  (1)
Cash and cash equivalents, end of year 411  89  322 

Cash provided by operating activities for the year ended Dec. 31, 2020, was lower compared with 2019 primarily due to lower revenues in 2020.

Cash used in investing activities for the year ended Dec. 31, 2020, increased compared with 2019, largely due to:
▪Increase due to the investments in Skookumchuck and EMG ($102 million);
▪Changes in our restricted cash ($73 million), increased cash spent on construction activities ($69 million) and higher non-cash working capital related to the timing of construction payables for the assets under construction ($54 million); and
▪Offset by lower cash spent on acquisitions (TransAlta acquired Ada for $32 million in 2020, compared with the Kineticor acquisition of $87 million and the Pioneer Pipeline acquisition of $83 million in 2019).

Cash from financing activities for the year ended Dec. 31, 2020, increased compared with 2019, largely due to:
▪Issuance of long-term debt ($753 million) in 2020 and the exchangeable securities of $400 million; and
▪Higher debt repayments ($380 million) as a result of higher scheduled principal repayments on project debt ($393 million) offset by lower payments on the credit facilities ($13 million).





TRANSALTA CORPORATION M46

Management’s Discussion and Analysis
Financial Capital
The Corporation is focused on maintaining a strong balance sheet and financial position to ensure access to sufficient financial capital. Credit ratings provide information relating to the Corporation's financing costs, liquidity and operations and affect the Corporation's ability to obtain short-term and long-term financing and/or the cost of such financing. Maintaining a strong balance sheet also allows our commercial team to contract the Corporation’s portfolio with a variety of counterparties on terms and prices that are favourable to the Corporation’s financial results and provide TransAlta with better access to capital markets through commodity and credit cycles.

During 2020, Moody’s reaffirmed its issuer rating of Ba1 with a stable outlook; DBRS Limited reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred Shares rating of Pfd-3 (low) and Issuer Rating of BBB (low) with a stable outlook; and Standard and Poor’s reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BB+ with a stable outlook. Risks associated with our credit ratings are discussed in the Governance and Risk Management section of this MD&A.





TRANSALTA CORPORATION M47

Management’s Discussion and Analysis
Capital Structure
Our capital structure consists of the following components as shown below:
As at Dec. 31 2020 2019 2018
 $  %  $  %  $  %
TransAlta Corporation
Recourse debt - CAD debentures 249  3  647  9  647  9 
Recourse debt - US senior notes 886  13  905  13  943  13 
Exchangeable securities(1)
730  11  326  5  —  — 
Credit facilities 114  2  —  —  174  2 
Other 7  —  9  —  11  — 
Less: cash and cash equivalents (121) (2) (348) (5) (16) — 
Less: 50 per cent of exchangeable preferred shares(1)
(200) (3) —  —  —  — 
Less: principal portion of restricted cash on TransAlta OCP (11) —  (10) —  (27) — 
Less: fair value asset of economic hedging instruments on debt (2) —  (7) —  (10) — 
Net recourse debt, excluding US tax equity financing 1,652  24  1,522  22 1,722  24 
Non-recourse debt 385  6  426  6  469  6 
Lease liabilities 112  2  119  2  63  1 
US tax equity financing for TransAlta Renewables economic interests(2)
134  2  145  2  28  — 
Non-recourse debt for TransAlta Renewables economic interests(3)
782  11  —  —  —  — 
Total net debt - TransAlta Corporation 3,065  45  2,212  32  2,282  31 
TransAlta Renewables
Credit facility —  —  220  3  165  2 
Less: cash and cash equivalents (582) (9) (63) (1) (73) (1)
Net recourse debt (582) (9) 157  2  92  1 
Non-recourse debt 670  10  718  10  767  11 
Lease liabilities 22  —  23  —  —  — 
Total net debt - TransAlta Renewables 110  1  898  12  859  12 
Total consolidated net debt(4)
3,175  46  3,110  44  3,141  43 
Non-controlling interests 1,084  16  1,101  15  1,137  16 
50 percent of exchangeable preferred securities(1)
200  3  —  —  —  — 
Equity attributable to shareholders
Common shares 2,896  43  2,978  42  3,059  42 
Preferred shares 942  14  942  13  942  13 
Contributed surplus, deficit and accumulated other comprehensive
income 		(1,486) (22) (959) (14) (1,004) (14)
Total capital 6,811  100  7,172  100  7,275  100 
(1) Exchangeable preferred securities are considered equity with dividend payments for credit purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements.
(2) TransAlta Renewables has an economic interest in the entities holding these debts.
(3) TransAlta Renewables has an economic interest in the Australia entities, which includes the AU$800 million senior secured notes.
(4) The tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in these amounts.
 
We continued strengthening our financial position during 2020 and have sufficient liquidity to fund our growth strategy. We have enhanced shareholder value by:

2020
▪Obtaining AU$800 million in project financing related to our South Hedland facility;
▪On Oct. 30, 2020, we received the second tranche of $400 million from Brookfield in consideration for redeemable, retractable first preferred shares;
▪Redeeming our outstanding 5 per cent $400 million medium-term notes due on Nov. 25, 2020; and
▪Purchasing and cancelling 7,352,600 common shares at an average price of $8.33 per share through our NCIB program, for a total cost of $61 million.





TRANSALTA CORPORATION M48

Management’s Discussion and Analysis
2019
▪Obtaining US$126 million in tax equity financing to fund the Big Level and Antrim wind facilities;
▪Entering into a strategic investment with Brookfield whereby Brookfield agreed to invest $750 million in the Corporation. On May 1, 2019, we received the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039, which are exchangeable by Brookfield into an equity ownership interest in our Alberta Hydro Assets in the future; and
▪Purchasing and cancelling 7,716,300 common shares at an average price of $8.80 per share through our NCIB program, for a total cost of $68 million.

2018
▪Early redeeming our outstanding 6.65 per cent US$500 million senior notes due May 15, 2018, for approximately $617 million (US$516 million) using proceeds from the Sundance B and C PPAs termination payment and existing liquidity;
▪Early redeeming our outstanding 6.40 per cent $400 million debentures due Nov. 2019, for approximately $425 million;
▪Paying out the US$25 million non-recourse debt related to the Mass Solar projects, and
▪Purchasing and cancelling 3,264,500 common shares at an average price of $7.02 per share through our NCIB program, for a total cost of $23 million.

Between 2021 and 2023, we have approximately $1 billion of debt maturing, comprised of approximately $631 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. We expect to refinance the senior notes maturing in 2022.

The Corporation's credit facilities are summarized in the table below:

As at Dec. 31, 2020 Facility
size 		Utilized Available
capacity 		Maturity
date
Outstanding letters of credit(1)
Actual drawings
TransAlta Corporation
Committed syndicated bank facility(2)
1,250  379  114  757  Q2 2023
Canadian committed bilateral credit facilities(3)
240  150  —  90  Q2 2021 & 2022
TransAlta Renewables
Committed credit facility(2)
700  92  —  608  Q2 2023
Total 2,190  621  114  1,455 
(1) TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. At Dec. 31, 2020, we provided cash collateral of $49 million.
(2) TransAlta has letters of credit of $89 million and TransAlta Renewables has letters of credit of $92 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities.
(3) One of the bilateral $80 million credit facilities has a maturity date of Q2 2021.

The weakening of the US dollar has decreased our long-term debt balances by $24 million as at Dec. 31, 2020. Almost all our US-denominated debt is hedged either through financial contracts or net investments in our US operations. During the period, these changes in our US-denominated debt were offset as follows:

As at Dec. 31 2020 2019
Effects of foreign exchange on carrying amounts of US operations
(net investment hedge) and finance lease receivable 		(11) (21)
Foreign currency cash flow hedges on debt (5) (9)
Economic hedges and other (5) (9)
Unhedged (3) (3)
Total (24) (42)
 





TRANSALTA CORPORATION M49

Management’s Discussion and Analysis
The Melancthon Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond, Kent Hills Wind LP, TEC and TransAlta OCP non-recourse bonds with a carrying value of $1.8 billion (Dec. 31, 2019 - $1.1 billion) are subject to customary financing conditions and covenants that may restrict the Corporation’s ability to access funds generated by the facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the third quarter of 2020. However, funds in these entities that have accumulated since the third quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2021. At Dec. 31, 2020, $73 million (Dec. 31, 2019 - $42 million) of cash was subject to these financial restrictions.
Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit.

Proceeds received from the TEC Notes in the amount of AU$7 million are not able to be accessed by other Corporate entities as the funds must be solely used by the project entities for the purpose of paying major maintenance costs.

Working Capital
Including the current portion of long-term debt and lease liabilities, the excess of current assets over current liabilities was $967 million as at Dec. 31, 2020 (2019 - $224 million). Our working capital increased year over year mainly due to repayment of the $400 million debenture in 2020. Excluding the current portion of long-term debt and lease liabilities of $105 million, the excess of current assets over liabilities was $1.1 billion as at Dec. 31, 2020 (2019 - $737 million), an increase of $335 million, mainly due to higher cash and cash equivalents. For further details on changes in cash during the year, please refer to the Cash Flows section of this MD&A.
 
Share Capital
On March 1, 2021, the Corporation announced that it does not intend to exercise its right to redeem all or any part of the currently outstanding Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") and Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares"). The Corporation has provided a notice to the registered shareholders of Series A Shares of the conversion right, on a one-for-one basis, into Series B Shares, and vice versa, providing Series B shareholders the right to exchange Series B Shares, on a one-for-one basis, into Series A Shares. Series A shareholders may elect to retain any or all of their current share holdings and continue to receive a fixed rate quarterly dividend. Series B shareholder may also elect to retain any or all of their current share holdings and continue to receive a floating rate quarterly dividend. After exercising conversion rights, if the balance that remains for either Series A Shares or Series B Shares is less than 1 million, that remaining balance will automatically convert to the other Series. Shareholders' notice of intention to convert must be received by the transfer agent no later than March 16, 2021 and the conversion date will be effective March 31, 2021. The annual dividend rate for the Series A Shares for the five-year period from and including March 31, 2021, to, but excluding, March 31, 2026, will be 2.877 per cent, which is equal to the five-year Government of Canada Bond yield of 0.847 per cent, determined as of March 1, 2021, plus 2.03 per cent. The annual dividend rate for the Series B Shares for the three month floating rate period from and including March 31, 2021, to, but excluding, June 30, 2021, will be 2.103 per cent based on the most recent auction of 90-day Government of Canada Treasury Bills of 0.073 per cent plus 2.03 per cent. The Floating Quarterly Dividend Rate will be reset every quarter.

Our Series C and Series E Cumulative Redeemable Rate Reset Preferred Shares failed to receive the required number of minimum votes in 2017 to give effect to conversions into Series D and Series F, respectively; accordingly, both the Series C and Series E Preferred Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The Series G Cumulative Redeemable Rate Reset Preferred Shares also failed to receive the required number of minimum votes in 2019 to give effect to conversions into Series H. Therefore, the Series G Preferred Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board.





TRANSALTA CORPORATION M50

Management’s Discussion and Analysis
The following tables outline the common and preferred shares issued and outstanding:
As at March 2, 2021 Dec. 31, 2020 Dec. 31, 2019
 
Number of shares (millions)
Common shares issued and outstanding, end of period 269.9 269.8  277.0 
Preferred shares      
Series A 10.2  10.2  10.2 
Series B 1.8  1.8  1.8 
Series C 11.0  11.0  11.0 
Series E 9.0  9.0  9.0 
Series G 6.6  6.6  6.6 
Preferred shares issued and outstanding in equity, end of period 38.6  38.6  38.6 
Series I - Exchangeable Securities(1)
0.4  0.4  — 
Preferred shares issued and outstanding, end of period 39.0  39.0  38.6 
(1) Brookfield invested $400 million in consideration for redeemable, retractable, first preferred shares. For accounting purposes, these preferred share are considered debt and disclosed as such in the consolidated financial statements.

Non-Controlling Interests
As of Dec. 31, 2020, we own 60.1 per cent (2019 - 60.4 per cent) of TransAlta Renewables. In 2020, our ownership percent decreased due to TransAlta Renewables issuing approximately 1 million common shares under their Dividend Reinvestment Plan ("DRIP"). We did not participate in this plan.

In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends. The dividend paid on Oct. 30, 2020, to shareholders of record on Oct. 15, 2020, was the last dividend payment eligible for reinvestment by participating shareholders. Subsequent dividends will be paid only in cash.

TransAlta Renewables is a publicly traded company whose common shares are listed on the TSX under the symbol “RNW.” TransAlta Renewables holds a diversified, highly contracted portfolio of assets with comparatively lower carbon intensity.

We also own 50.01 per cent of TA Cogen, which owns, operates or has an interest in three natural-gas-fired facilities (Ottawa, Windsor and Fort Saskatchewan) and one dual-fuel generating facility. Since we own a controlling interest in TA Cogen and TransAlta Renewables, we consolidate the entire earnings, assets and liabilities in relation to those assets.

Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2020, decreased by $60 million to $34 million compared to 2019. Earnings were down at TransAlta Renewables in 2020 mainly due to lower finance income and change in the fair value of financial assets an increase in income tax expense, offset by higher operating income and an increase in foreign exchange gains resulting from the strengthening of the Australian dollar relative to the Canadian dollar. Earnings from TA Cogen were lower in 2020 mainly due to lower operating income as a result of the planned outage for the dual-fuel conversion at Sheerness Unit 2, low Alberta market demand and the onerous contract provision for the coal supply agreement (see Note 9 of the consolidated financial statements for further details).
 
Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2019, decreased by $14 million to $94 million compared to 2018. Earnings were down at TransAlta Renewables in 2019 mainly due to lower finance and interest income from subsidiaries of TransAlta, foreign exchange losses due to the weakening of the Australian dollar and higher depreciation expense, partially offset by an increase in the fair value of investments in subsidiaries of TransAlta. Earnings from TA Cogen were higher in 2019 mainly due to strong Alberta pricing and lower costs of fuel at the coal-fired generating facility. The coal-fired generating facility was converted to dual-fuel in 2020.





TRANSALTA CORPORATION M51

Management’s Discussion and Analysis
Returns to Providers of Capital
Net Interest Expense
The components of net interest expense are shown below:
Year ended Dec. 31 2020 2019 2018
Interest on debt 158  161  184 
Interest on exchangeable securities 34  20  — 
Interest income (10) (13) (11)
Capitalized interest (8) (6) (2)
Loss on redemption of bonds —  —  24 
Interest on lease liabilities 8  4  3 
Credit facility fees, bank charges and other interest 18  15  13 
Tax shield on tax equity financing(1)
1  (35) — 
Interest on the line loss proceeding 5  —  — 
Other(2)
2  10  15 
Accretion of provisions 30  23  24 
Net interest expense 238  179  250 
(1) Relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim wind projects that was assigned to the tax equity investor. The tax equity investment is treated as debt under IFRS and the monetization of the tax depreciation is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.
(2) In 2020, other interest expense included approximately nil (2019 — $5 million; 2018 — $7 million) for the significant financing component required under IFRS 15. In addition, in 2018, approximately $5 million of costs were expensed due to project-level financing that is no longer practicable.

Net interest expense was higher in 2020 primarily due to interest on the additional $400 million exchangeable preferred shares issued as part of the Brookfield Investment and the AU$800 million TEC Offering, both issued in October 2020. In addition, interest was higher due to interest charges received in 2020 for the AESO transmission line loss proceedings, and the 2019 impact of the $35 million tax credit received relating to the tax shield on Big Level and Antrim projects offset by the termination of the Keephills 3 contract liability in 2019, resulting in the deferred financing costs being recognized.

Net interest expense was lower in 2019 compared to 2018, primarily due to the $35 million credit related to the tax shield on the Big Level and Antrim projects and allocated to the tax equity investor. In addition, there were no prepayment premiums in 2019 as there were no early redemptions of bonds during the year, compared to 2018, which included $24 million in prepayment premiums.

Dividends to Shareholders
 
The declaration of dividends is at the discretion of the Board. The following are the common and preferred shares dividends declared each quarter during 2020 and the first quarter of 2021:
  Common Preferred Series dividends per share
  Payable date dividends          
Declaration date Common shares Preferred shares per share A B C E G
Jan. 16, 2020 Apr 1, 2020 Mar. 31, 2020 0.0425  0.16931  0.22949  0.25169  0.32463  0.31175 
Apr. 20, 2020 Jul 1, 2020 Jun 30, 2020 0.0425  0.16931  0.22800  0.25169  0.32463  0.31175 
Jul 22, 2020 Oct.1, 2020 Sept. 30, 2020 0.0425  0.16931  0.14359  0.25169  0.32463  0.31175 
Nov. 3, 2020 Jan. 1, 2021 Dec. 31. 2020 0.0425  0.16931 0.13693 0.25169 0.32463 0.31175
Dec. 23, 2020 Apr. 1, 2021 Mar. 31, 2021 0.0450  0.16931 0.13186 0.25169 0.32463 0.31175





TRANSALTA CORPORATION M52

Management’s Discussion and Analysis
2021 Financial Outlook
The following table outlines our expectation on key financial targets and related assumptions for 2021 and should be read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of this MD&A:
Measure Target
Comparable EBITDA $960 million - $1,080 million
FCF $340 million - $440 million
Dividend $0.18 per share annualized

Range of key power price assumptions
Market Power prices ($/MWh)
Alberta Spot $58 - $68
Mid-C Spot (US$) US$25 - US$35

Other assumptions relevant to the 2021 financial outlook
Sustaining capital $175 million - $210 million

Operations
Market Pricing and Hedging Strategy
For 2021, power prices in Alberta are expected to be higher than 2020 with the expiry of the remaining PPAs at six thermal facilities that transferred dispatch control from the Balancing Pool to the asset owners, higher carbon compliance costs, and demand recovery relative to the economy-wide closures from COVID-19 during most of 2020; however, weather and demand are major factors in actual settled prices. Pacific Northwest power prices for 2021 are expected to be comparable to or higher than 2020, but will depend on the actual weather and hydrology of the year. Ontario power prices for 2021 are expected to be higher than 2020 prices if demand recovers from COVID-19 and normal weather is experienced in the province.

The objective of our portfolio management strategy in Alberta is to balance opportunity and risk, and to deliver optimization strategies that contribute to our total investment, which includes a return of and on invested capital. We can be more or less hedged in a given period, and we expect to realize our annual targets through a combination of forward hedging and selling generation into the spot market. The Alberta assets are managed as a portfolio to maximize the overall value of generation and capacity from our hydro, wind and energy storage and thermal facilities. Financial hedging is a key component of cash flow certainty and the hedges are tied to the portfolio of assets rather than a single facility.

Fuel Costs
For the Alberta thermal fleet, we expect the 2021 cash fuel costs per tonne of coal to be higher than 2020 as mine volumes are declining, resulting in slightly less mine cost efficiency. Coal volumes are declining as a result of increased gas consumption in the Alberta thermal fleet. This change in fuel mix will drive lower GHG emissions and the combined effect will result in lower total fuel and GHG costs for a given volume of power production.

In the Pacific Northwest of the US, the coal mine adjacent to our Centralia thermal facility is in the reclamation stage. Fuel at Centralia has been purchased primarily from external suppliers in the Powder River Basin and delivered by rail. In 2020, we amended our fuel and rail contract such that our rail freight costs fluctuate partly with power prices. The delivered fuel cost in 2021 is expected to be marginally higher than 2020 costs.

Most of the generation from gas turbine-based power facilities is sold under contracts with pass-through provisions for fuel. For gas generation with no pass-through provisions, we purchase natural gas from outside companies coincident with production, thereby minimizing our risk to changes in prices.

We closely monitor the risks associated with changes in electricity and input fuel prices on our future operations and, where we consider it appropriate, use various physical and financial instruments to hedge our assets and operations from such price risks.
 




TRANSALTA CORPORATION M53

Management’s Discussion and Analysis
Energy Marketing
EBITDA from our Energy Marketing segment is affected by prices and volatility in the market, overall strategies adopted and changes in regulation and legislation. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2021 objective for Energy Marketing is for the segment to contribute between $90 million to $110 million in gross margin for the year.
 
Exposure to Fluctuations in Foreign Currencies
Our strategy is to minimize the impact of fluctuations in the Canadian dollar against the US dollar and Australian dollar by offsetting foreign-denominated assets with foreign-denominated liabilities and by entering into foreign exchange contracts. We also have foreign-denominated expenses, including interest charges, which largely offset our net foreign-denominated revenues.
 
Net Interest Expense
Interest expense for 2021 is expected to be higher than in 2020 largely due to higher levels of debt. The increase in debt is mainly due to the AU$800 million TEC Offering and the $400 million exchangeable preferred shares issued as part of the Brookfield Investment, both occurring in October 2020. The increase in debt is offset by repayment of $400 million medium-term notes in November 2020. In addition, changes in interest rates on variable debt, and in the value of the Canadian dollar relative to the US and Australian dollars can affect the amount of interest expense incurred.
 
Liquidity and Capital Resources
We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to $2.1 billion in liquidity, including $703 million in cash. We expect to be well positioned to refinance the upcoming debt maturity in 2022. Please refer to the Corporate Strategy and Financial Capital sections of this MD&A for further details.
 
Sustaining and Productivity Capital Expenditures
Our estimate for total sustaining and productivity capital is allocated among the following:
Category Description Spent in 2019 Spent in 2020 Expected spend in 2021
Routine capital(1)
Capital required to maintain our existing generating capacity 50  52  44  - 54
Planned major maintenance Regularly scheduled major maintenance 68  98  130  - 154
Mine capital Capital related to mining equipment and land purchases 23  7  1  - 2
Total sustaining capital(2)
141  157  175  - 210
Insurance recoveries of sustaining
capital expenditures 		Insurance proceeds: 2019 relates to the tower fires at Wyoming Wind and Summerview (10) —  —  - —
Total sustaining capital 131  157  175  - 210
Productivity capital Projects to improve power production efficiency and corporate improvement initiatives 9  4  3  - 7
Total sustaining and productivity capital 140  161  178  - 217
(1) Includes hydro life extension expenditures.






TRANSALTA CORPORATION M54

Management’s Discussion and Analysis
Significant planned major outages at TransAlta's operated units for 2021 include the following:
▪Major maintenance turnarounds at Keephills Units 2 and 3;
▪Distributed planned maintenance expenditures across the entire hydro fleet; and
▪Distributed expenditures across our wind fleet, focusing on planned component replacements.

There is also one major planned outage at one of our non-operated units in 2021:
▪An outage for major maintenance at Sheerness Unit 1 is in progress with expected completion in the first quarter of 2021. This work will be undertaken in parallel with the conversion to gas of this unit.

Lost production as a result of planned major maintenance, excluding planned major maintenance for Centralia, which is scheduled during a period of dispatch optimization, is estimated as follows for 2021:
  Coal Gas and
renewables 		Total
 
GWh lost
 
1,600-1,700 550-600 2,150-2,300
 
Funding of Capital Expenditures
Funding for these planned capital expenditures is expected to be provided by cash flow from operating activities and existing liquidity. In addition, we have access to approximately $2.1 billion, including $703 million in cash, as required. The funds required for committed growth, sustaining capital and productivity projects are not expected to be significantly impacted by the current economic environment.

A significant portion of our sustaining and productivity capital is planned major maintenance, which includes inspection, repair and maintenance of existing components, and the replacement of existing components. Planned major maintenance costs are capitalized as part of PP&E and are amortized on a straight-line basis over the term until the next major maintenance event. These costs exclude amounts for day-to-day routine maintenance, unplanned maintenance activities and minor inspections and overhauls, which are expensed as incurred.  





TRANSALTA CORPORATION M55

Management’s Discussion and Analysis
Competitive Forces
Supply and demand balances are the fundamental drivers of prices for electricity. Underlying economic growth is the main driver of longer-term changes in the demand for electricity, whereas system capacity, natural gas prices, GHG pricing, government subsidies and renewable resource availability are key drivers to the supply. Growth in behind-the-fence generation for mining investments is key to developing our Australian gas segment.
 
Renewable capacity additions will continue as a result of government policy and evolving corporate stakeholder objectives. New supply in the near term and intermediate term is expected to come primarily from investment in renewable electricity as well as natural-gas-fired generation. This expectation is driven by the low prices in the natural gas market combined with public policies that favour carbon emission reductions.
 
We have substantial merchant capacity in Alberta and the Pacific Northwest. In those regions, we enter into contracts and business relationships with commercial and industrial customers to sell power for various terms, up to our available capacity in the markets. We can further reduce the portion of production not sold in advance of the spot markets through short-term physical and financial contracts, and we optimize production in real time against our position and market conditions.
 
We also compete for long-term contracted opportunities in renewable and gas power generation, including cogeneration, across Canada, the US and Australia. Our target customers in this area are incumbent utility providers and large industrial and mining operators.

Alberta
Approximately 54 per cent of our gross installed capacity is located in Alberta. Previously, 45 per cent of this was subject to legislated Alberta PPAs, all of which have expired as of Dec. 31, 2020.

Our portfolio of merchant assets in Alberta is a combination of hydro facilities, wind facilities, a battery storage facility and co-fired and converted natural gas-fired thermal facilities. This balance of fuel types provides us with portfolio generation diversification. It also provides us with capacity that can be monetized as ancillary services or dispatched into the energy market during times of supply tightness. We also enter into financial contracts to reduce our exposure to variable power prices on our merchant generation.



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Our Clean Energy Investment Plan, which includes converting our existing Alberta coal facilities to natural gas, will position TransAlta's fleet as a low-cost generator in Alberta. Please refer to the Corporate Strategy section of this MD&A for further details.

Alberta's annual demand contracted approximately 2.5 per cent from 2019 to 2020 due to the combined impacts of COVID-19 and oil production shut-ins. The drop in demand was most significant in the second and third quarters. The average pool price decreased from $55/MWh in 2019 to $47/MWh in 2020. Pool prices were lower in each quarter compared to 2019, with additional weakness during the second quarter as a result of higher power imports into Alberta.
Our market share of offer control in Alberta in 2020 was approximately 21 per cent.

In late November 2016, we announced that we entered into an Off-Coal Agreement with the Government of Alberta that provides transition payments for the cessation of coal-fired emissions from the Keephills 3, Genesee 3 and Sheerness coal-fired facilities on or before Dec. 31, 2030. The Oct. 1, 2019 swap of the Corporation's 50 per cent ownership interest in Genesee 3 for the 50 percent interest in Keephills 3 did not impact the transition payments received under the Off-Coal Agreement. The affected facilities are not, however, precluded from generating electricity at any time by any method other than the combustion of coal.

We expect additional compliance costs as a result of the Canadian federal government’s Greenhouse Gas Pollution Pricing Act, which sets a national price on GHG emissions with each province expected to implement a GHG policy equivalent to a carbon price of $50 per tonne by 2022. We believe that our extensive portfolio of assets provides us with brownfield




TRANSALTA CORPORATION M56

Management’s Discussion and Analysis
development opportunities in wind, solar, hydro and gas that give us a cost advantage over competitors when constructing generation facilities that use these fuel types.

Pursuant to the Electric Utilities Act (Alberta), the Balancing Pool announced the complete termination of the Sundance B and C PPAs, effective March 31, 2018. As of April 1, 2018, the Sundance facility has been operated as a merchant facility. 

US Pacific Northwest
Our capacity in the US Pacific Northwest has been represented by our 1,340 MW Centralia thermal facility. Half of the facility's capacity was retired at the end of 2020 and the other half is scheduled to retire at the end of 2025. Our competitiveness is enhanced by our long-term contract with Puget Sound Energy for up to 380 MW over the remaining life of the facility. We enter into short-term hedges for the remaining generation and can satisfy these or our long-term contract with power purchased from the market during low-priced periods.


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Installed capacity in the region is primarily comprised of hydro and gas generation, with substantial wind capacity as well, including our Skookumchuck wind facility, which began production in November 2020. Demand growth in the region has been limited and further constrained by an emphasis on energy efficiency.

We maintain the right to redevelop Centralia as a gas facility after coal capacity retires, with an opportunity for expedited permitting provided for in our agreement for coal transition established with the State of Washington in 2011.

Contracted Gas and Renewables
 
The market for developing or acquiring gas and renewable generation facilities is highly competitive in all markets in which we operate. Our solid record as operator and developer supports our competitive position. We expect, where possible, to reduce our cost of capital and improve our competitive profile by using project financing and leveraging the lower cost of capital with TransAlta Renewables. In the US, our substantial tax attributes further increase our competitiveness.
 
While depressed commodity prices have reduced sectoral growth in the oil, gas and mining industries, the change is also creating opportunities for us as a service provider as some of our potential customers are more carefully evaluating non-core activities and driving for operational efficiencies. In renewables, we are primarily evaluating greenfield opportunities in Western Canada and the US along with acquisitions in markets in which we have existing operations. We maintain highly qualified and experienced development teams to identify and develop these opportunities. In cogeneration, we are working with customers to evaluate behind-the-fence solutions.
 
Some of our older gas facilities are now reaching the end of their original contract life. The facilities generally have a substantial cost advantage over new builds and we have been able to add value by recontracting these facilities with limited life extending capital expenditures. We have recently extended the life of our Ottawa (2033 expiry), Windsor (2031 expiry), Parkeston (2026 expiry), Fort Saskatchewan (2030 expiry) and Southern Cross (2038) facilities in this manner.  





TRANSALTA CORPORATION M57

Management’s Discussion and Analysis
Power-Generating Portfolio Capital
We monitor availability closely as a key metric to achieving our financial targets. We adjust our maintenance and sustaining capital expenditures to optimize financial returns on our investments and to align with our strategic intentions.
 
Availability and Production
We achieved 85 per cent (2019 - 89 per cent, 2018 -93 per cent) availability in Alberta Thermal, a decrease from the prior year due to planned outages. North American Gas achieved 97 per cent (2019 - 95 per cent, 2018 - 93 per cent) and Wind and Solar achieved 95 per cent (2019 - 95 per cent, 2018 - 95 per cent). Australian Gas achieved 94 per cent (2019 - 91 per cent, 2018 - 94 per cent), with the increase being the result of unplanned outages in 2019.

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Our availability for the entire fleet in 2020, after adjusting for dispatch optimization at Centralia, was 90 per cent (2019 - 90 per cent, 2018 - 91 per cent), consistent with last year. Lower planned and unplanned outages and derates within the generation segments were offset by the planned outages at Alberta Thermal for the Sundance Unit 6 turnaround and conversion to gas outage.

Production for the year ended Dec. 31, 2020, decreased 4,091 GWh compared to 2019. Of the total decrease, 2,822 GWh was primarily due to planned outages, curtailments and dispatch optimization reducing merchant production for Alberta Thermal. In addition, Centralia experienced reduced production of 2,021 GWh due to lower merchant pricing, timing of dispatch optimization, and both Centralia units being taken out of service for the majority of the first half of 2020.


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Sustaining Capital
We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital that ensures our facilities operate reliably and safely over a long period of time.
Year ended Dec. 31 2020 2019 2018
Routine capital 52  50  50 
Mine capital 7  23  42 
Planned major maintenance 98  68  58 
Total sustaining capital expenditures 157  141  150 
Productivity capital 4  9  21 
Total sustaining and productivity capital expenditures 161  150  171 
Insurance recoveries of sustaining capital expenditures —  (10) (7)
Net amount 161  140  164 

Lost production as a result of planned major maintenance is as follows:
Year ended Dec. 31 2020 2019 2018
GWh lost(1)
980  935  381 
(1) Lost production excludes periods of planned major maintenance at Centralia, which occur during periods of dispatch optimization.

Total sustaining capital expenditures were $16 million higher compared to 2019 and total productivity capital was $5 million lower in 2020 compared to 2019. The increased focus on sustaining capital expenditures related to the planned major maintenance at Alberta Thermal for Sundance Unit 6 and conversion to gas outage. In addition, Wind and Solar had sustaining capital expenditures for the Kent Hills foundation work.





TRANSALTA CORPORATION M58

Management’s Discussion and Analysis
Other Consolidated Analysis
Asset Impairment Charges and Reversals
As part of the Corporation’s monitoring controls, long-range forecasts are prepared for each cash-generating unit ("CGU"). The long-range forecast estimates are used to assess the significance of potential indicators of impairment and provide criteria to evaluate adverse changes in operations. The Corporation also considers the relationship between our market capitalization and our book value, among other factors, when reviewing for indicators of impairment. When indicators of impairment are present, the Corporation estimates a recoverable amount for each CGU by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Corporation’s long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices and useful lives of the assets extending to the last planned asset retirement in 2073.

2020
Sundance Unit 3
In the third quarter of 2020, the Corporation recognized an impairment charge on Sundance Unit 3 in the amount of $70 million in the Alberta Thermal segment due to the Corporation's decision to retire the unit. Previously, the Corporation had expected Sundance Unit 3 to remain mothballed until November 2021. As there were no estimated future cash flows from power generation expected to be derived from the unit, the unit was removed from the Alberta merchant CGU and immediately written down to the recoverable value of the scrap materials.

BC Hydro Facility
In the third quarter of 2020, the Corporation recorded an impairment of $2 million in the Hydro segment, due to a review of water resources that resulted in a revision to the forecasted production at a BC hydro facility. The impairment assessment was based on fair value less costs of disposal using discounted cash flow projections based on the Corporation's long-range forecasts. The resulting fair value measurement is categorized as a Level III fair value measurement. The key assumptions impacting the determination of fair value are electricity production and sales prices, which are subject to measurement uncertainty.

Centralia Land
In the fourth quarter of 2020, the Corporation recognized an impairment of $9 million (US$7 million) in the Centralia segment due to a decrease in the fair value of the land determined through a third-party appraiser. In addition to the asset impairments noted above, a net asset impairment of $3 million was recognized for changes in the decommissioning and restoration liabilities related to the Centralia mine and Sundance Unit 1, which are no longer operating and have reached the end of their useful lives.

2019
Centralia Thermal Facility
In 2012, the Corporation recorded an impairment of $347 million relating to the Centralia thermal facility CGU. As part of the annual impairment test, the Corporation considers possible indicators of impairment at the Centralia thermal facility CGU. In 2019, an internal valuation indicated the fair value less costs of disposal of the Centralia thermal facility CGU exceeded the carrying value, resulting in a full recoverability test in 2019. The updated fair value included sustained changes in the power price market and cost of coal due to contract renegotiations. As a result of the recoverability test an impairment reversal of $151 million was recorded in the Centralia segment.
The valuations are categorized as Level III fair value measurements and subject to measurement uncertainty based on the key assumptions outlined below, and on inputs to the Corporation’s long-range forecast, including changes to fuel costs, operating costs, capital expenses and the level of contractedness under the Memorandum of Agreement ("MOA") for coal transition established with the State of Washington. The valuation period includes cash flows until the decommissioning of the facility in 2025.

The Corporation utilized the Corporation's long-range forecast and the following key assumptions in 2019 compared with 2016 assumptions, which was the most recent detailed valuation:

2019 2016
Mid-Columbia annual average power prices US$30 to US$42 per MWh US$22 to US$46 per MWh
On-highway diesel fuel on coal shipments US$2.35 to US$2.40 per gallon US$1.69 to US$2.09 per gallon
Discount rates 5.2 to 6.4 per cent 5.4 to 5.7 per cent





TRANSALTA CORPORATION M59

Management’s Discussion and Analysis
During 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will occur as originally proposed. The Corporation's current best estimate of the decommissioning and restoration provision increased by $141 million. Since the Centralia mine is no longer operating and reached the end of its useful life in 2006, this adjustment results in the immediate recognition of the full $141 million through asset impairment charges in net earnings. Please refer to Note 3 and 23 of the consolidated financial statements for further details.

Assets Held for Sale
In the fourth quarter of 2019, the Corporation identified several trucks and associated inventory to be sold within the Alberta Thermal segment and accordingly wrote the assets down to net realizable value, resulting in an impairment charge of $15 million.

2018
 
Sundance Unit 2
In the third quarter of 2018, the Corporation recognized an impairment charge on Sundance Unit 2 in the amount of $38 million due to the Corporation’s decision to retire Sundance Unit 2. Previously, the Corporation had expected Sundance Unit 2 to remain mothballed for a period of up to two years and therefore remain within the Alberta Merchant CGU. The impairment assessment was based on value in use and included the estimated future cash flows expected to be derived from the unit until its retirement on July 31, 2018. Discounting did not have a material impact.
Lakeswind and Kent Breeze
On May 31, 2018, TransAlta Renewables acquired an economic interest in Lakeswind through the subscription of tracking preferred shares of a subsidiary of the Corporation and also purchased Kent Breeze. In connection with these acquisitions, the assets were fair valued using discount rates that average approximately seven per cent. Accordingly, the Corporation has recorded an impairment charge of $12 million using the valuation in the agreement as the indicator of fair value less cost of disposal in 2018. The impairment charge had an $11 million impact on PP&E and a $1 million impact on intangible assets.
Project Development Costs
During 2020, the Corporation wrote off nil (2019 - $18 million) in project development costs related to projects that are no longer proceeding.
Unconsolidated Structured Entities or Arrangements
Disclosure is required of all unconsolidated structured entities or arrangements such as transactions, agreements or contractual arrangements with unconsolidated entities, structured finance entities, special purpose entities or variable interest entities that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources. We currently have no such unconsolidated structured entities or arrangements.

Guarantee Contracts
We have obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. At Dec. 31, 2020, we provided letters of credit totalling $621 million (2019 - $690 million) and cash collateral of $49 million (2019 - $42 million). These letters of credit and cash collateral secure certain amounts included on our Consolidated Statements of Financial Position under risk management liabilities, defined benefit obligation and other long-term liabilities, and decommissioning and other provisions.





TRANSALTA CORPORATION M60

Management’s Discussion and Analysis
Commitments
Contractual commitments are as follows: 
  2021 2022 2023 2024 2025 2026 and thereafter Total
Natural gas, transportation and other contracts 141  149  137  134  134  1,353  2,048 
Transmission 8  8  8  5  5  1  35 
Coal supply and mining agreements 81  105  101  67  56  —  410 
Long-term service agreements 31  37  22  18  10  55  173 
Operating leases(1)
4  2  2  1  1  26  36 
Long-term debt(2)
96  626  277  119  136  2,010  3,264 
Exchangeable securities(3)
—  —  —  —  750  —  750 
Principal payments on lease liabilities(4)
(5) 6  5  5  5  118  134 
Interest on long-term debt and lease liabilities(4,5)
161  153  126  119  113  893  1,565 
Interest on exchangeable securities(3,5)
53  52  53  52  —  —  210 
Growth 509  411  93  —  —  —  1,013 
TransAlta Energy Transition Bill 6  6  6  —  —  —  18 
Total 1,085  1,555  830  520  1,210  4,456  9,656 
(1) Includes leases that have not yet commenced.
(2) Excludes impact of hedge accounting and derivatives.
(3) Assumes the exchangeable securities will be exchanged by Brookfield on Jan. 1, 2025. Please refer to the Significant and Subsequent Events section of this MD&A for further details.
(4) Lease liabilities include a lease incentive of $13 million, expected to be received in 2021.
(5) Interest on long-term debt is based on debt currently in place with no assumption as to refinancing on maturity.
(6) Not recognized as a financial liability on the Consolidated Statements of Financial Position.

As part of the TransAlta Energy Transition Bill signed into law in the State of Washington and the subsequent MoA, we have committed to fund US$55 million in total over the remaining life of the Centralia thermal facility to support economic and community development, promote energy efficiency and develop energy technologies related to the improvement of the environment. The MoA contains certain provisions for termination and in the event of the termination and certain circumstances, this funding or part thereof would no longer be required. At Dec. 31, 2020, the Corporation has funded approximately US$41 million of the commitment.

Contingencies 
Line Loss Rule Proceeding 
The Corporation has been participating in a line loss rule proceeding before the AUC. The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed AESO to recalculate loss factors for 2006 to 2016 and issue a single invoice charging or crediting market participants for the difference in losses charges. The AESO submitted a review and variance application of this decision to implement a “pay-as-you-go” invoicing scheme rather than issue a single invoice. The AUC ruled on AESO’s request and approved a three-period invoice process (2006-2009, 2010-2013 and 2014-2016). The total liability for the loss charges was $25 million; however, due to payments made (and received) for the first two invoices, only $8 million of the total liability remains outstanding. The AESO issued the first invoice on Oct. 22, 2020, for $6 million, which was paid by Dec. 30, 2020. The second invoice was issued on Dec. 21, 2020, for $11 million. The third invoice is expected in March 2021.

In November 2020, AESO sought direction from the AUC with respect to interest payments on the loss charges, and the AUC ruled in January 2021 that simple interest (rather than compound interest) would apply to the loss charges.

FMG Disputes
The Corporation is currently engaged in a dispute with Fortescue Metals Group Ltd. ("FMG") as a result of FMG's purported termination of the South Hedland PPA. TransAlta sued FMG, seeking payments of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated. This matter has been rescheduled to proceed to trial beginning May 3, 2021, instead of June 15, 2020.

The Corporation had a second dispute involving FMG's claims against TransAlta related to the transfer of the Solomon facility to FMG. FMG claimed certain amounts related to the condition of the facility while TransAlta claimed certain outstanding costs that should be reimbursed. The dispute was settled and discontinued in the Supreme Court of Western Australia on Sept. 9, 2020.




TRANSALTA CORPORATION M61

Management’s Discussion and Analysis

Mangrove Claim
On April 23, 2019, Mangrove commenced an action in the Ontario Superior Court of Justice, naming the Corporation, the incumbent members of the Board of Directors of the Corporation on such date and Brookfield BRP Holdings (Canada), as defendants. Mangrove is seeking to set aside the Brookfield Investment. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter has been rescheduled and the three-week trial will begin on April 19, 2021.

Keephills 1 Stator Force Majeure Appeal
The Balancing Pool and ENMAX Energy Corporation ("ENMAX") are seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench ("ABQB") dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX, however, sought leave to appeal the ABQB’s decision at the Court of Appeal, which was granted on Feb. 13, 2020. The appeal is scheduled to be heard on April 8, 2021. TransAlta believes that the Court of Appeal will affirm the ABQB decision that the arbitration proceeding was fair.

Keephills 1 Superheater Force Majeure
Keephills Unit 1 was taken offline March 17, 2015 to May 17, 2015 as a result of a large leak in the secondary superheater. TransAlta Generation Partnership claimed force majeure under the Keephills PPA. ENMAX, the PPA buyer under the PPA at the time, did not dispute the force majeure but the Balancing Pool did, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The Balancing Pool argued and won in the Courts that it has a right under the PPA to commence an arbitration, independent of the PPA buyer, ENMAX. An arbitration for this dispute has commenced and is set to be heard for seven days starting Dec. 6, 2021.

Sundance A Decommissioning
TransAlta filed an application with the AUC seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and the Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. Due to various factors, including the COVID-19 pandemic and significant information requests from the Balancing Pool, the application has been delayed. While a hearing date has not been set, the application will likely be heard in late 2021 or early 2022. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain.

Hydro Power Purchase Arrangement ("Hydro PPA") Emission Performance Credits Credits
The Balancing Pool claims to be entitled to emission performance credits ("EPCs"), valued at approximately $17 million per year, earned by the Hydro facilities under the Carbon Competitiveness Incentive Regulation from 2018-2020. The dispute is based on the ownership of the EPCs as a result of a change-in-law provision under the Hydro PPA and that TransAlta is benefiting from the purported change in law. TransAlta has not received any benefit from the EPCs and has not recognized any benefit from the EPCs within its financial statements. TransAlta believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and will be likely set down for a hearing sometime in early 2022.
Direct Assigned Capital Deferral Account ("DACDA") Application
AltaLink Management Ltd. ("AltaLink") filed an application before the AUC to recover its 2016-2018 DACDA costs (the "Proceeding") incurred for the 240 kV line upgrades project in the Edmonton region (the “Upgrades Project”). TransAlta is a secondary applicant in the Proceeding because it owns a portion of the 1043L Line located on Enoch Cree Nation (“ECN”) Reserve that was part of the Upgrades Project. AltaLink and TransAlta sought to have their costs ($91 million for AltaLink and $22 million for TransAlta) approved by the AUC as reasonable and prudent. The ECN and the Consumers Coalition of Alberta are registered participants in the Proceeding. The AUC rendered its decision in the Proceeding on Dec. 10, 2020, and disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta believes that the AUC made errors by disallowing 15 per cent of its costs and therefore filed a permission to appeal application with the Court of Appeal (the “PTA”) and a review and variance application with the AUC (the “R&V”). The PTA will be adjourned until the R&V process is completed.






TRANSALTA CORPORATION M62

Management’s Discussion and Analysis
Critical Accounting Policies and Estimates
The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as accounting rules and guidance have changed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules and the use of judgment relative to the circumstances existing in the business. Every effort is made to comply with all applicable rules on or before the effective date, and we believe the proper implementation and consistent application of accounting rules is critical.
 
However, not all situations are specifically addressed in the accounting literature. In these cases, our best judgment is used to adopt a policy for accounting for these situations. We draw analogies to similar situations and the accounting guidelines governing them, consider foreign accounting standards and consult with our independent auditors about the appropriate interpretation and application of these policies. Each of the critical accounting policies involves complex situations and a high degree of judgment either in the application and interpretation of existing literature or in the development of estimates that impact our consolidated financial statements.
 
Our significant accounting policies are described in Note 2 of the consolidated financial statements. The most critical of these policies are those related to revenue recognition, financial instruments, valuation of PP&E and associated contracts, project development costs, useful life of PP&E, valuation of goodwill, leases, income taxes, employee future benefits, decommissioning and restoration provisions, other provisions and joint arrangements. Each policy involves a number of estimates and assumptions to be made about matters that are uncertain at the time the estimate is made. Different estimates, with respect to key variables used for the calculations, or changes to estimates, could potentially have a material impact on our financial position or results of operations.
 
We have discussed the development and selection of these critical accounting estimates with our Audit, Finance and Risk Committee ("AFRC") and our independent auditors. The AFRC has reviewed and approved our disclosure relating to critical accounting estimates in this MD&A. These critical accounting estimates are described as follows:

Revenue Recognition
Revenue from Contracts with Customers
 
The majority of our revenues from contracts with customers are derived from the sale of generation capacity, electricity, thermal energy, environmental attributes and byproducts of power generation. The Corporation evaluates whether the contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an ongoing basis if there is an indication of significant changes in facts and circumstances. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using the invoice practical expedient, if such amount corresponds directly with the Corporation’s performance to date. The Corporation excludes amounts collected on behalf of third parties from revenue.

Identification of Performance Obligations
Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Corporation’s contracts may contain more than one performance obligation. Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether goods or services constitute distinct goods or services or a series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of the contract and the economic and operating environment of the contract in determining whether the goods or services in a contract are distinct.

Transaction Price
The Corporation allocates the transaction price in the contract to each performance obligation. Transaction price allocated to performance obligations may include variable consideration. Variable consideration is included in the transaction price for each performance obligation when it is highly probable that a significant reversal of the cumulative variable revenue will not occur. Variable consideration is assessed at each reporting period to determine whether the constraint is lifted. The consideration contained in some of the Corporation's contracts with customers is primarily variable, and may include both variability in quantity and pricing, such as: revenues can be dependent upon future production volumes that are driven by customer or market demand or by the operational ability of the facility; revenues can be dependent upon the variable cost of producing the energy; revenues can be dependent upon market prices; and revenues can be subject to various indices and escalators.





TRANSALTA CORPORATION M63

Management’s Discussion and Analysis
In determining the transaction price and estimates of variable consideration, management considers past history of customer usage and capacity requirements when estimating the goods and services to be provided to the customer. The Corporation also considers the historical production levels and operating conditions for its variable generating assets.

Allocation of Transaction Price to Performance Obligations
When multiple performance obligations are present in a contract, transaction price is allocated to each performance obligation in an amount that depicts the consideration the Corporation expects to be entitled to in exchange for transferring the good or service.

The Corporation’s contracts generally outline a specific amount to be invoiced to a customer associated with each performance obligation in the contract. Where contracts do not specify amounts for individual performance obligations, the Corporation estimates the amount of the transaction price to allocate to individual performance obligations based on their standalone selling price, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.

Satisfaction of Performance Obligations
The satisfaction of performance obligations requires management to use judgment as to when control of the underlying good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of revenue recognition. Management considers both customer acceptance of the good or service, and the impact of laws and regulations such as certification requirements, in determining when this transfer occurs. Management also applies judgment in determining whether the invoice practical expedient permits recognition of revenue at the invoiced amount, if that invoiced amount corresponds directly with the entity's performance to date.

The Corporation recognizes a significant financing component where the timing of payment from the customer differs from the Corporation’s performance under the contract and where that difference is the result of the Corporation financing the transfer of goods and services.

Revenue from Other Sources
Lease Revenue
In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where we retain the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract.

Revenue from Derivatives
Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options that are used to earn revenues and to gain market information. These derivatives are accounted for using fair value accounting. The initial recognition and subsequent changes in fair value affect reported net earnings in the period the change occurs and are presented on a net basis in revenue. The fair values of instruments that remain open at the end of the reporting period represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position as risk management assets or liabilities.
 
The determination of the fair value of commodity risk management contracts and derivative instruments is complex and relies on judgments concerning future prices, volatility and liquidity, among other factors. Some of our derivatives are not traded on an active exchange or extend beyond the time period for which exchange-based quotes are available, requiring us to use internal valuation techniques or models described below.

Financial Instruments
 
The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for instruments in active markets to which we have access. In the absence of an active market, we determine fair values based on valuation models or by reference to other similar products in active markets.
 
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, we look primarily to external readily observable market inputs. However, if not available, we use inputs that are not based on observable market data.





TRANSALTA CORPORATION M64

Management’s Discussion and Analysis
Level Determinations and Classifications
 
The Level I, II and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value.

Level I
 
Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to access at the measurement date. In determining Level I fair values, we use quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.

Level II
 
Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.
 
Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation and location differentials. Our commodity risk management Level II financial instruments include over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and interpolation formulas, where the inputs are readily observable.
 
In determining Level II fair values of other risk management assets and liabilities, we use observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, we rely on similar interest or currency rate inputs and other third-party information such as credit spreads.
 
Level III
 
Fair values are determined using inputs for the asset or liability that are not readily observable.
 
We may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as mark-to-forecast and mark-to-model. For mark-to-model valuations, derivative pricing models, regression-based models and historical bootstrap models may be employed. The model inputs may be based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatilities and correlations between products derived from historical price relationships. We also have various contracts with terms that extend beyond a liquid trading period. As forward market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III.
 
Our Commodity Exposure Management Policy governs both the commodity transactions undertaken in our proprietary trading business and those undertaken to manage commodity price exposures in our generation business. This Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as well as the nature and frequency of required reporting of such activities.
 
Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by our risk management department. Level III fair values are calculated within our energy trading risk management system based on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.
 
The effect of using reasonably possible alternative assumptions as inputs to valuation techniques for contracts included in the Level III fair value measurements at Dec. 31, 2020, is an estimated total upside of $68 million (2019 - $79 million upside) and total downside of $94 million (2019 - $172 million) impact to the carrying value of the financial instruments. Fair values are stressed for volumes and prices. The amount of $35 million upside (2019 - $46 million upside) and $59 million downside (2019 - $139 million downside) in the stress values stems from a long-dated power sale contract in the Pacific Northwest that is designated as a cash flow hedge utilizing assumed power prices ranging from US$24 to US$32/MWh (Dec. 31, 2019 - US$20-US$28/MWh) for the period beyond the liquid period, while the remaining amounts account for the rest of the portfolio. The variable volumes are stressed up and down one standard deviation from




TRANSALTA CORPORATION M65

Management’s Discussion and Analysis
historically available production data. Prices are stressed for longer-term deals where there are no liquid market quotes using various internal and external forecasting sources to establish a high and a low price range.

In addition to the Level III fair value measurements discussed above, the Brookfield Investment allows Brookfield the option to exchange all of the outstanding exchangeable securities into an equity ownership interest of up to a maximum of 49 per cent in an entity formed to hold TransAlta’s Alberta Hydro Assets after Dec. 31, 2024. The fair value of the option to exchange is considered a Level III fair value measurement, with an estimated downside of $33 million (2019 - $27 million downside) potential impact to the carrying value of nil as at Dec. 31, 2020 (2019 - nil). The sensitivity analysis has been prepared using the Corporation’s assessment that a change in the implied discount rate of the future cash flow of one per cent is a reasonably possible change.

Inventory
The Corporation’s inventory balance is comprised of coal and natural gas used as fuel, which is measured at the lower of weighted average cost and net realizable value. At the end of each reporting period, we assess whether our inventory should be written down to its net realizable value as a result of reduced movement in inventory, lower commodity prices or other events and circumstances that might indicate the cost of the inventory is no longer recoverable.

Determining the amount of the net realizable value requires significant judgment and can vary based on the estimates such as estimated production levels, consumption and sales prices.

Valuation of PP&E and Associated Contracts
 
At the end of each reporting period, we assess whether there is any indication that PP&E and finite life intangible assets are impaired or whether a previously recognized impairment may no longer exist or may have decreased. Impairment exists when the carrying amount of the asset or CGU to which it belongs exceeds its recoverable amount, which is the higher of fair value less costs of disposal and value in use.
 
Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used or in our overall business strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where we are not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

Our operations, the market and business environment are routinely monitored, and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the asset or CGU to which the asset belongs. The recoverable amount is the higher of an asset’s fair value less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. In determining fair value less costs of disposal, information about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the current use and present condition of the asset. In estimating either fair value less costs of disposal or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, capital expenditures, retirement costs and other related cash inflows and outflows over the life of the facilities, which can range from 30 to 60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the facility operates, anticipated production levels, planned and unplanned outages, changes to regulations and transmission capacity or constraints for the remaining life of the facilities.

Discount rates are determined by employing a weighted average cost of capital methodology that is based on capital structure, cost of equity and cost of debt assumptions based on comparable companies with similar risk characteristics and market data as the asset, CGU or group of CGUs subject to the test. These estimates and assumptions are susceptible to change from period to period and actual results can, and often do, differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.
 
The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets, and goodwill is allocated to each CGU or group of CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of




TRANSALTA CORPORATION M66

Management’s Discussion and Analysis
goodwill is reassessed upon changes in the composition of segments, CGUs or groups of CGUs. In respect of determining CGUs, significant judgment is required to determine what constitutes independent cash flows between power facilities that are connected to the same system. We evaluate the market design, transmission constraints and the contractual profile of each facility, as well as our commodity price risk management plans and practices, in order to inform this determination. With regard to the allocation or reallocation of goodwill, significant judgment is required to evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring activities. We evaluate synergies with regard to opportunities from combined talent and technology, functional organization and future growth potential, and we consider our own performance measurement processes in making this determination. No changes arose in our CGUs in 2020.

Impairment charges can be reversed in future periods if circumstances improve. No assurances can be given if any reversal will occur or the amount or timing of any such reversal. As a result of our review in 2020 and other specific events, various analyses were completed to assess the significance of possible impairment indicators. Please refer to the Other Consolidated Analysis section of this MD&A for further details.

Project Development Costs
 
Project development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. These costs are recognized in operating expenses until construction of a facility or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will result in future value to us, at which time the costs incurred subsequently are included in PP&E or other assets. The appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no longer probable of occurring are charged to net earnings.
 
Useful Life of PP&E
 
Each significant component of an item of PP&E is depreciated over its estimated useful life. A component is a tangible asset that can be separately identified as an asset and is expected to provide a benefit of greater than one year. Estimated useful lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence and regulations. The useful lives of PP&E and depreciation rates used are reviewed at least annually to ensure they continue to be appropriate.
 
In 2020, total depreciation and amortization expense was $798 million (2019 - $709 million; 2018 - $710 million), of which $144 million (2019 - $119 million; 2018 - $136 million) relates to mining equipment and is included in fuel, carbon compliance and purchased power.

As a result of the Clean Energy Investment Plan described in the Corporate Strategy section of this MD&A, we will convert our existing Alberta coal assets to natural gas and therefore the useful lives of the PP&E and amortizable intangibles associated with some of our Alberta coal assets were updated to reflect these changes. For certain Wind and Solar PP&E we identified additional components for parts with shorter useful lives than originally estimated and revised the useful lives accordingly. See the Accounting Changes section of this MD&A for further details.

Valuation of Goodwill
 
We evaluate goodwill for impairment at least annually, or more frequently if indicators of impairment exist. If the carrying amount of a CGU or group of CGUs, including goodwill, exceeds the unit’s fair value, the excess represents a goodwill impairment loss.
 
For purposes of the 2020, 2019 and 2018 annual goodwill impairment reviews, the Corporation determined the recoverable amounts of the CGUs by calculating the fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair value measurement is categorized within Level III of the fair value hierarchy.
 
We reviewed the carrying amount of goodwill prior to year-end and determined that the fair values of the related CGUs or groups of CGUs to which goodwill relates, based on estimates of future cash flows, exceeded their carrying amounts, and no goodwill impairments existed.






TRANSALTA CORPORATION M67

Management’s Discussion and Analysis
Determining the fair value of the CGUs or group of CGUs is susceptible to changes from period to period as management is required to make assumptions about future cash flows, production and trading volumes, margins, and fuel and operating costs. No reasonably possible change in the assumptions would have resulted in an impairment of goodwill.

Leases
 
In determining whether our contracts contain, or are, leases, management must use judgment in assessing whether the contract provides the customer with the right to substantially all of the economic benefits from the use of the asset during the lease term and whether the customer obtains the right to direct the use of the asset during the lease term. For those agreements considered to contain, or be, leases, further judgment is required to determine the lease term by assessing whether termination or extension options are reasonably certain to be exercised. Judgment is also applied in identifying in-substance fixed payments (included) and variable payments that are based on usage or performance factors (excluded) and in identifying lease and non-lease components (services that the supplier performs) of contracts and in allocating contract payments to lease and non-lease components.

For leases where we are a lessor, judgment is required to determine if substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with us, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how we classify amounts related to the arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position, and therefore the amount of certain items of revenue and expense are dependent upon such classifications.
 
Income Taxes
 
In accordance with IFRS, we use the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis (temporary differences). A deferred income tax asset may also be recognized for the benefit expected from unused tax credits and losses available for carryforward, to the extent that it is probable that future taxable earnings will be available against which the tax credits and losses can be applied.
 
Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which we operate. The process also involves making an estimate of taxes currently payable and income taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that our future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. The reduction of the deferred income tax asset can be reversed if the estimated future taxable income improves. No assurances can be given if any reversal will occur or the amount or timing of any such reversal. Management must exercise judgment in its assessment of continually changing tax interpretations, regulations, and legislation to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than our estimates could materially impact the amount recognized for deferred income tax assets and liabilities. Our tax filings are subject to audit by taxation authorities. The outcome of some audits may change our tax liability, although we believe that we have adequately provided for income taxes in accordance with IFRS based on all information currently available. The outcome of pending audits is not known nor is the potential impact on the consolidated financial statements determinable.
 
A net deferred income tax liability of $345 million (2019 - $454 million) has been recorded on the Consolidated Statements of Financial Position as at Dec. 31, 2020. This primarily relates to income tax deductions in excess of related depreciation of PP&E of $717 million (2019 - $828 million) and taxes on unrealized gains from risk management transactions of $107 million (2019 - $141 million), partially offset by temporary differences related to future decommissioning and restoration costs of $140 million (2019 - $122 million) and net operating loss carryforwards of $222 million (2019 - $252 million). We believe there will be sufficient taxable income that will permit the use of these loss carryforwards in the tax jurisdictions where they exist. Additional US tax losses are available for use for which no deferred income tax assets have been recognized.
 





TRANSALTA CORPORATION M68

Management’s Discussion and Analysis
Employee Future Benefits
 
We provide selected pension and other post-employment benefits to employees, such as health and dental benefits. The cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and assumptions about future experience.
 
The liabilities for pension, other post-employment benefits and associated pension costs included in annual compensation expenses are impacted by employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets.
 
Changes to the provisions of the plans may also affect current and future pension costs. Pension costs may also be significantly impacted by changes in key actuarial assumptions, including, for example, the discount rates used in determining the defined benefit obligation and the net interest cost on the net defined benefit liability. The discount rate used to estimate our obligation reflects high-quality corporate fixed income securities currently available and expected to be available during the period to maturity of the pension benefits.
 
The plan assets are comprised primarily of equity and fixed income investments. Fluctuations in the return on plan assets as a result of actual equity market returns and changes in interest rates may result in increased or decreased pension costs in future periods.

Decommissioning and Restoration Provisions
 
We recognize decommissioning and restoration provisions for generating facilities and mine sites in the period in which they are incurred if there is a legal or constructive obligation to remove the facilities and restore the site. The amount recognized as a provision is the best estimate of the expenditures required to settle the provision. Expected values are probability weighted to deal with the risks and uncertainties inherent in the timing and amount of settlement of many decommissioning and restoration provisions. Expected values are discounted at the current market-based risk-free interest rate adjusted to reflect the market’s evaluation of our credit standing.
 
As at Dec. 31, 2020, the decommissioning and restoration provisions recorded on the Consolidated Statements of Financial Position was $608 million (2019 - $501 million). During 2020, the Corporation adjusted the Highvale mine decommissioning and restoration provision to reflect the mine closure advancement, an updated mine plan and current mining activity, including increased volume of material movement. As at Dec. 31, 2020, the decommissioning and restoration provision for Highvale mine was $153 million (2019 - $91 million) for reclamation work anticipated through 2046. The majority of the reclamation work is expected to be complete by 2040. Please refer to the Accounting Changes section of this MD&A for further details. This increase was partially offset by a decrease in the Sarnia decommissioning and restoration provision as a result of an updated engineering study. In addition, due to volatility within the market as a result of COVID-19, we have seen movement within the discount rates as a result of changes in credit spreads. As a result, on average, these rates decreased by approximately 0.3 to 0.9 per cent.

During 2019, we adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will be completed as originally proposed. As at Dec. 31, 2020, the decommissioning and restoration provision for Centralia mine was $174 million (2019 - $178 million) for reclamation work anticipated through 2035. Please refer to the Accounting Changes section of this MD&A for further details. In addition, as a result of the changes in estimated useful lives, described in the Accounting Changes section, the discount rates used for the Alberta Thermal and mining operations decommissioning provisions were changed due to the change in useful life.

We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is approximately $1.4 billion, which will be incurred between 2021 and 2073. The majority of these costs will be incurred between 2025 and 2050.
 
Sensitivities for the major assumptions are as follows:
Factor Increase or
decrease (%) 		Approximate impact
on net earnings
Discount rate 1  6 
Undiscounted decommissioning and restoration provision 10  3 
 





TRANSALTA CORPORATION M69

Management’s Discussion and Analysis
Other Provisions
 
Where necessary, we recognize provisions arising from ongoing business activities, such as interpretation and application of contract terms, ongoing litigation and force majeure claims. These provisions, and subsequent changes thereto, are determined using our best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized.

During the fourth quarter of 2020, an onerous contract provision of $29 million was recognized as a result of a decision to accelerate the plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. The last coal shipment is expected to be received during the first quarter of 2021, while payments required under the contract will continue until 2025.

Classification of Joint Arrangements
Upon entering into a joint arrangement, the Corporation must classify it as either a joint operation or joint venture, and the classification affects the accounting for the joint arrangement. In making this classification, the Corporation exercises judgment in evaluating the terms and conditions of the arrangement to determine whether the parties have rights to the assets and obligations or rights to the net assets. Factors such as the legal structure, contractual arrangements and other facts and circumstances, such as where the purpose of the arrangement is primarily for the provision of the output to the parties and when the parties are substantially the only source of cash flows for the arrangement, must be evaluated to understand the rights of the parties to the arrangement.

Accounting Changes
Current Accounting Changes
 
 
I. Amendments to IAS 1 and IAS 8 Definition of Material
The Corporation adopted the amendments to IAS 1 and IAS 8 as of Jan. 1, 2020. The amendments provide a new definition of material that states “information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.”

The amendments clarify that materiality will depend on the nature or magnitude of information, either individually or in combination with other information, in the context of the financial statements. A misstatement of information is material if it could reasonably be expected to influence decisions made by the primary users. These amendments had no impact on the consolidated financial statements of, nor is there expected to be any future impact to, the Corporation.

II. Amendments to IFRS 7 and 9 Interest Rate Benchmark Reform
In September 2019, the IASB issued amendments to reporting standards relating to Interest Rate Benchmark Reform by amending IFRS 9, IAS 39 and IFRS 7. These amendments provide temporary relief during the period of uncertainty from applying specific hedge accounting requirements to hedging relationships directly affected by the ongoing interest rate benchmark reforms. These amendments are mandatory for annual periods beginning on or after Jan. 1, 2020. The Corporation adopted these amendments as of Jan. 1, 2020. There were no hedging relationships that were directly affected on Jan. 1, 2020.

During the first quarter of 2020, the Corporation entered into cash flow hedges of interest rate risk associated with a future forecasted debt issuance using derivative instruments based on the London Interbank Offered Rate ("LIBOR"). As a temporary relief, provided by the IFRS 9 amendments, the Corporation has assumed that the LIBOR interest rate on which the cash flows of the interest rate swaps are based is not altered by interbank offered rates ("IBOR") reform when assessing if the hedge is highly effective.

Note 2 and 3 of the consolidated financial statements include a more detailed discussion of our accounting policies.

Change in Estimates
Alberta Thermal
During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021 and accordingly the useful life of the related assets was adjusted to align with the Corporation's conversion to gas plans. As at Dec. 31, 2020, the carrying value of the Highvale mine, including PP&E, right-of-use assets and intangible assets, was $373 million.

As a result of the Clean Energy Investment Plan described in the Corporate Strategy section of this MD&A, we adjusted the useful lives of certain coal assets, effective Sept. 1, 2019. Assets used only for coal-burning operations were adjusted to shorten their useful lives whereas other asset lives were extended as they were identified as being used after the




TRANSALTA CORPORATION M70

Management’s Discussion and Analysis
conversion to gas or combined-cycle conversions. Due to the impact of shortening the lives of the coal assets, overall depreciation expense for the year ended Dec. 31, 2020, increased by approximately $15 million.

Wind and Solar
During 2019, we reviewed the allocation of the costs recognized for the components of the Wind and Solar PP&E and the useful lives for these identified components. As a result of the review, additional components were identified for parts where the useful lives are shorter than the original estimate. The useful life of each of these components was reduced from 30 years to either 15 years or 10 years. Accordingly, depreciation expense for the year ended Dec. 31, 2019, increased by approximately $11 million.

Sheerness
In 2019, we adjusted the useful life of the Sheerness coal-fired facility assets to align with the dual-fuel conversion plans. As a result, the assets used for coal-burning operations as well as the other asset lives were extended and depreciation expense for the year ended Dec. 31, 2019, decreased by approximately $8 million.

The useful lives may be revised or extended in compliance with the Corporation's accounting policies, dependent upon future operating decisions and events.

Sarnia
In the fourth quarter of 2020, the Corporation adjusted the Sarnia decommissioning and restoration provision to reflect an updated engineering study. The Corporation's current best estimate of the decommissioning and restoration provision decreased by $15 million. This resulted in a decrease in the related assets in PP&E.

Highvale
In the third quarter of 2020, the Corporation adjusted the Highvale mine decommissioning and restoration provision to reflect the mine closure advancement, an updated mine plan and current mining activity, including increased volume of material movement. The Corporation's current best estimate of the decommissioning and restoration provision increased by $75 million. This resulted in an increase in the related assets in PP&E.

Centralia
In 2019, we adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will be completed as originally proposed. The Corporation's current best estimate of the decommissioning and restoration provision increased by $141 million. Since the Centralia mine is no longer operating and reached the end of its useful life in 2006, this adjustment results in the immediate recognition of the full $141 million, through asset impairment charges in net earnings.

TransAlta estimates that the undiscounted amount of cash flow required to settle this additional obligation is approximately $222 million, which will be incurred between 2021 and 2035. The provision may be revised in compliance with the Corporation's accounting policies, dependent upon future operating decisions and as more information becomes available.

For further details and changes in estimates relating to prior years, please refer to the Other Consolidated Analysis section of this MD&A and Note 3 of the consolidated financial statements.

Future Accounting Changes
Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use
The Corporation plans to early adopt the Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use on Jan. 1, 2021. The amendment has a mandatory effective date of Jan. 1, 2022. The amendments prohibit deducting from the cost of an item of PP&E any proceeds from selling items produced while bringing the asset to the location and condition necessary for it to be capable of operating. No adjustments are expected from early adopting the amendments.

IFRS 7 Financial Instruments - Disclosures - Interest Rate Benchmark Reform
The IASB issued Interest Rate Benchmark Reform - Phase 2 in August 2020, which amends IFRS 9 Financial Instruments, IAS 39 Financial Instruments: Recognition and Measurement, IFRS 7 Financial Instruments: Disclosures and IFRS 16: Leases. The amendments are effective Jan. 1, 2021, and will be adopted by the Corporation in 2021, no financial impact is expected upon adoption.

Comparative Figures
 
Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications did not impact previously reported net earnings.






TRANSALTA CORPORATION M71

Management’s Discussion and Analysis
Financial Instruments
Financial instruments are used for proprietary trading purposes and to manage our exposure to interest rates, commodity prices and currency fluctuations, as well as other market risks. We may currently use physical and financial swaps, forward sale and purchase contracts, futures contracts, foreign exchange contracts, interest rate swaps and options to achieve our risk management objectives. Some of our physical commodity contracts have been entered into and are held for the purposes of meeting our expected purchase, sale, or usage requirements (“own use”) and as such, are not considered financial instruments and are not recognized as a financial asset or financial liability. Other physical commodity contracts that are not held for normal purchase or sale requirements and derivative financial instruments are recognized on the Consolidated Statements of Financial Position and are accounted for using the fair value method of accounting. The initial recognition of fair value and subsequent changes in fair value can affect reported earnings in the period the change occurs if hedge accounting is not elected. Otherwise, changes in fair value will generally not affect earnings until the financial instrument is settled.
 
Some of our financial instruments and physical commodity contracts qualify for, and are recorded under, hedge accounting rules. The accounting for those contracts for which we have elected to apply hedge accounting depends on the type of hedge. Our financial instruments are mainly used for cash flow hedges or non-hedges. These categories and their associated accounting treatments are explained in further detail below.
 
For all types of hedges, we test for effectiveness at the end of each reporting period to determine if the instruments are performing as intended and hedge accounting can still be applied. The financial instruments we enter into are designed to ensure that future cash inflows and outflows are predictable. In a hedging relationship, the effective portion of the change in the fair value of the hedging derivative does not impact net earnings, while any ineffective portion is recognized in net earnings.

We have certain contracts in our portfolio that, at their inception, do not qualify for, or we have chosen not to elect to apply, hedge accounting. For these contracts, we recognize in net earnings mark-to-market gains and losses resulting from changes in forward prices compared to the price at which these contracts were transacted. These changes in price alter the timing of earnings recognition, but do not necessarily determine the final settlement amount received. The fair value of future contracts will continue to fluctuate as market prices change. The fair value of derivatives that are not traded on an active exchange, or extend beyond the time period for which exchange-based quotes are available, are determined using valuation techniques or models.
 
Cash Flow Hedges
Cash flow hedges are categorized as project, foreign exchange, interest rate or commodity hedges and are used to offset foreign exchange, interest rate and commodity price exposures resulting from market fluctuations.

Foreign currency forward contracts may be used to hedge foreign exchange exposures resulting from anticipated contracts and firm commitments denominated in foreign currencies, primarily related to capital expenditures, and currency exposures related to US-denominated debt.

Physical and financial swaps, forward sale and purchase contracts, futures contracts and options may be used primarily to offset the variability in future cash flows caused by fluctuations in electricity and natural gas prices. Foreign exchange forward contracts and cross-currency swaps may be used to offset the exposures resulting from foreign-denominated long-term debt. Interest rate swaps may be used to convert the fixed interest cash flows related to interest expense at debt to floating rates and vice versa.

In a cash flow hedge, changes in the fair value of the hedging instrument (a forward contract or financial swap, for example) are recognized in risk management assets or liabilities, and the related gains or losses are recognized in other comprehensive income ("OCI"). These gains or losses are subsequently reclassified from OCI to net earnings in the same period as the hedged forecast cash flows impact net earnings, and offset the losses or gains arising from the forecast transactions. For project hedges, the gains and losses reclassified from OCI are included in the carrying amount of the related PP&E.

Hedge accounting follows a principles-based approach for qualifying hedges, which is aligned with an entity's approach to risk management. When we do not elect hedge accounting or when the hedge is no longer effective and does not qualify for hedge accounting, the gains or losses as a result of changes in prices, interest or exchange rates related to these financial instruments are recorded in net earnings in the period in which they arise.





TRANSALTA CORPORATION M72

Management’s Discussion and Analysis
Net Investment Hedges
Foreign-denominated long-term debt is used to hedge exposure to changes in the carrying values of our net investments in foreign operations that have a functional currency other than the Canadian dollar. Our net investment hedges using US-denominated debt remain effective and in place. Gains or losses on these instruments are recognized and deferred in OCI and reclassified to net earnings on the disposal of the foreign operation. We also manage foreign exchange risk by matching foreign-denominated expenses with revenues, such as offsetting revenues from our US operations with interest payments on our US-dollar debt.

Non-Hedges
Financial instruments not designated as hedges are used for proprietary trading and to reduce commodity price, foreign exchange and interest rate risks. Changes in the fair value of financial instruments not designated as hedges are recognized in risk management assets or liabilities, and the related gains or losses are recognized in net earnings in the period in which the change occurs.

Fair Values
The majority of fair values for our project, foreign exchange, interest rate, commodity hedges and non-hedge derivatives are calculated using adjusted quoted prices from an active market or inputs validated by broker quotes. We may enter into commodity transactions involving non-standard features for which market-observable data is not available. These transactions are defined under IFRS as Level III instruments. Level III instruments incorporate inputs that are not observable from the market, and fair value is therefore determined using valuation techniques. Fair values are validated by using reasonably possible alternative assumptions as inputs to valuation techniques, and any material differences are disclosed in the notes to the consolidated financial statements. At Dec. 31, 2020, Level III instruments had a net asset carrying value of $582 million (2019 - $686 million). Please refer to the Critical Accounting Policies and Estimates section of this MD&A for further details regarding valuation techniques. Our risk management profile and practices have not changed materially from Dec. 31, 2019.




TRANSALTA CORPORATION M73

Management’s Discussion and Analysis
Environment, Social and Governance (“ESG”)
Sustainability or ESG management and performance is a priority at TransAlta. Sustainability is one of our core values, which means it is part of our corporate culture. We perpetually strive to further integrate sustainability into our governance, decision-making, risk management and day-to-day business processes, while enabling our growth strategy. The ultimate outcome of our sustainability focus is continuous improvement on key, material ESG issues and ensuring our economic value creation is balanced with a value proposition for the environment and our stakeholders. Over time, we have set ourselves apart with actions that demonstrate ESG leadership:

▪We have reported on sustainability for over 25 years, and 2020 reporting marks our sixth year of integrating financial and sustainability disclosure;
▪Today, we are proud to be one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta - we have grown our renewable energy capacity from approximately 900 MW in 2000 to over 2,500 MW in 2020;
▪Through the period 2002 to 2025 and by way of retirements, gas conversions and expected gas conversions or repowerings, we are on track to transition over 5,000 MW of coal capacity. In 2026, we will be completely off of coal power generation;
▪We have reduced our annual emissions by over 25 million tonnes of carbon dioxide equivalent ("CO2e") since 2005, which is approximately a 61 per cent reduction over the time period and highlights our decarbonization track record: this is the equivalent annual GHG emissions of a small country;
▪Our 2030 GHG reduction target supports further reductions and in 2021, we have established a new company-wide target to achieve carbon neutrality by 2050;
▪In 2020, CDP (the global disclosure system for environmental impacts known formerly as Carbon Disclosure Project) recognized TransAlta with an A- score, ranking us among industry leaders on climate change management;
▪We continue to evolve our leading sustainability target setting process that links targets to sustainability and financial materiality, sets macro targets that are both year-over-year and long term, and involves executive team and Board approval;
▪In 2020, TransAlta formed an Equity, Diversity and Inclusion Council and empowered this Council to develop a long-term equity, diversity and inclusion strategy. TransAlta also adopted a Equity, Diversity and Inclusion Pledge unanimously supported by our Board and executive team;
▪In 2021, TransAlta was once again added to the Bloomberg Gender-Equality Index — recognition of our focus on equity, diversity and inclusion;
▪In 2020, the Globe and Mail reported that we moved from a ranking of 48 to a ranking of 14 in their annual "Board Games" report. Board Games assesses the work of Canada’s largest boards of directors against a rigorous set of governance criteria (well beyond the minimum set by regulators), covering board composition, compensation, shareholder rights and disclosure. The Board Games are undertaken by the Globe and Mail in collaboration with the University of Toronto;
▪Our Indigenous youth education target ensures ongoing Indigenous youth education support and, in 2021, we are establishing a new company-wide Indigenous cultural education and awareness target; and
▪We participate in and are members of key sustainability organizations and working groups such as the EXCEL Partnership, the Canadian Business for Social Responsibility, the Energy Sector Sustainability Leadership Initiative, Canadian Electricity Association Sustainable Electricity Steering Committee and Future-Fit, which all provide validation and support of our sustainability strategy.






TRANSALTA CORPORATION M74

Management’s Discussion and Analysis
Sustainability Strategy
Our business is electricity. We keep the lights on, our technology charged and critical infrastructure running. We support commercial and industrial customers across three countries. In total, we own 75 power-generating facilities across Australia, Canada and the US. We are invested in a mix of wind, solar, hydro, energy storage, natural gas and coal assets for a total of approximately 8,000 MW of owned generating capacity.

Our key strategic sustainability pillars build on our corporate strategy and weave through our business. Some of these focus areas are already part of our DNA, and our track record in these areas illustrates our commitment to sustainability (including climate change leadership and safety). In other areas where we have set new goals in recent years (including, equity, diversity and inclusion), we believe the focus will only strengthen our corporate strategy and support value creation into the future. Our pillars include:

1.Clean, Reliable and Sustainable Electricity Production
2.Safe, Healthy, Diverse, and Engaged Workplace
3.Positive Indigenous, Stakeholder and Customer Relationships
4.Progressive Environmental Stewardship
5.Technology and Innovation

Sustainability Governance
In order for an organization to truly integrate sustainability, it requires accountability at the Board and executive level. It requires an understanding of ESG issues and associated corporate actions to address these issues, while continuing to balance operations and growth.

Sustainability is overseen by TransAlta's Governance, Safety and Sustainability Committee (“GSSC”) of the Board. The GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Corporation’s monitoring of environmental, health and safety regulations, public policy changes and the establishment and adherence to environmental, health and safety practices, procedures and policies. For additional details on our governance, please refer to the Governance and Risk Management section of this MD&A.

Sustainability Reporting: Disclosure Guidance and Materiality
The following outlines material environmental and social considerations in respect of our operated facilities.

Key elements of the following disclosure are guided by our sustainability materiality assessment. Our materiality assessment is developed through evaluation of key sector-specific research on materiality issues and supported by internal and external engagement on key sustainability issues. To provide context on how ESG affects our business (including material focus areas), our content is guided by leading ESG reporting frameworks, including the Global Reporting Initiative ("GRI"), Sustainability Accounting Standards Board ("SASB") and the Task Force on Climate-related Financial Disclosures ("TCFD"). We continue to increase our alignment with SASB and TCFD. Our ESG content is integrated within this MD&A. Content is structured using non-traditional capital (this includes natural, human, social and relationship, intellectual and manufactured capital) as per guidance from the International Integrated Reporting Framework. This approach ensures we inform investors on how management and performance on non-traditional capitals contribute to financial value.

Environmental and Social Risk and Materiality
Our materiality assessment informs our focus on major environmental and social risks. Our major environmental risk factors include weather, environmental disasters, climate change, exposure to the elements, environmental compliance risk, and current and emerging environmental regulation. Our major social risk factors include public health and safety, employee and contractor health and safety, local communities, employee retention, reputation management, and Indigenous and stakeholder relationships.

For further guidance on our risk factors, please refer to the Risk Management section of this MD&A.







TRANSALTA CORPORATION M75

Management’s Discussion and Analysis
Reliable, Low-Cost and Sustainable Energy Production:
Natural, Intellectual and Social Capital Management
Business and Economic Model Resilience
TransAlta has been powering economies and communities for over 109 years. Our mission is to provide safe, low-cost and reliable clean electricity to our customers. To achieve this goal, in today's evolving economy and increasingly electrified world, our strategy focuses on renewable electricity, natural gas and a deep commitment to sustainability. Our business model is primarily focused on providing power to industrial and commercial customers. This model has stood the test of time and we continue to focus our efforts on the customer and adapting to meet customer needs. As customers increasingly adopt ESG and sustainability goals, we are well positioned to support their sustainability objectives. We developed our first sustainability report in 1994. In the early 2000s, we were an early adopter of wind. Our expertise in renewable energy spans 109 years: we began hydro operations in the early 1900s and today we are a leading hydro and wind producer. We believe we are uniquely positioned as the world continues to electrify and adopt sustainability practices.

Brand Recognition
Our business resilience is enhanced by a purpose-based, long-term and sustainable business strategy: growth in renewable electricity and natural gas and a commitment to sustainability. TransAlta has operated power-generation assets for over 109 years, which reflects this approach to long-term and sustainable business practices. A long-term commitment to business and partnerships lends itself to goodwill and brand recognition, something we value and do not take for granted. We believe our low-cost and clean electricity strategy, supported by our internal values and sustainable approach to business, will help reinforce and continue to increase our positive brand recognition.

Intellectual Capital
At TransAlta, we define intellectual capital as our knowledge-based assets. Measuring these assets serves two purposes. First, we seek to understand them so we can improve their management and performance. Second, we seek to understand these assets to communicate their real value. The following highlights some of our knowledge-based assets, which we believe provide us with a competitive advantage and contribute to shareholder value.

Diversified Knowledge
The experience and acumen of our employees enhances our value creation. Our experience in developing and operating power-generation technologies extends to over 109 years, and many of our employees have worked with us for over 30 years. Our energy marketing business complements our knowledge of operating power-generation assets.

Our experience in developing and operating power-generation technologies is highlighted below:

Power-Generation Type Operating Experience (years)
Hydro 109
Natural Gas 70
Coal 70
Wind 18
Solar 5


For further details, please refer to Customers in this section of this MD&A.






TRANSALTA CORPORATION M76

Management’s Discussion and Analysis
Grid Resiliency
As a large electricity generator, we work diligently to ensure the power we provide our customers is reliable, affordable and has low environmental impact. We provide decentralized power solutions to industrial customers and we supply power to centralized power systems.

In all of the jurisdictions where we operate, we work closely with the system operators to ensure overall supply adequacy and reliability of the grid. In Alberta, where we are also a transmission facility owner, we own grid infrastructure that addresses system reliability. We consider a myriad of factors in our planning and operation decisions that could put grid resiliency at risk, including renewable energy intermittency, cyberattacks, extreme weather events and natural disasters.

One solution to support renewable energy intermittency includes investment in battery storage technology. Our first battery storage project began commercial operations in 2020. For more information, please refer to Renewable Energy and Battery Storage in our Natural Capital Management section of this MD&A. For more information on cyberattacks, please refer to Public Health and Safety in the Social and Relationship Capital section of this MD&A. For more information on extreme weather events and natural disasters, please refer to Weather in the Natural Capital Management section of this MD&A.

Customers
TransAlta serves industrial and commercial customers with power and energy services across its fleet in Canada, the US and Australia. As one of the largest electricity generators in Alberta, our team serves businesses with:

▪Energy consumption and cost management solutions;
▪Market price risk and volume exposure mitigation;
▪Sustainability initiatives such as self-generated electricity and environmental attributes such as EPCs; and
▪Monitoring of energy market design changes, price signals and applicable and available incentives.

The customer solutions team at TransAlta has maintained a large portfolio of customers in Alberta across a broad range of industry segments, including commercial real estate, municipal, manufacturing, industrial, hospitality, finance, and oil and gas. TransAlta is proud of the service we provide to our customers, which is evidenced by the achievement of over 90 per cent customer retention for the last three years.

Across our business in Canada, the US and Australia, we are focused on helping our customers achieve their sustainability goals. One example is through TransAlta’s fleet of on-site cogeneration facilities. Cogeneration is the process of generating electricity and steam simultaneously. When constructed on-site, the construction of additional transmission lines is not required, which avoids disruption to the environment. It also reduces the natural gas required for some industrial processes by using high-efficiency steam production rather than boilers. Examples of industrial processes that utilize cogeneration include gas processing, steam-assisted gravity drainage oil sands extraction, chemical manufacturing, and pulp and paper production. Cogeneration is recognized by regulatory bodies for its efficient generation of power when compared to other forms of natural gas power generation, and thus can potentially produce EPCs that can be used to satisfy our customers' regulatory obligations or sold for additional revenue.

We provide on-site generation for large mining and industrial customers. This requires us to be continually engaged with these customers ensuring that current electricity requirements are provided safely, reliably and cost-effectively with the benefit of lower GHG emissions.

Another way we contribute to our customers’ sustainability goals is through the development of renewable energy and the use of environmental attributes. We continue to develop renewable energy facilities to support customers achieving their sustainability goals and targets, such as 100 per cent renewable power targets and/or GHG reduction targets. Recent examples include our Skookumchuck wind project in Washington, which has a 137 MW capacity and is subject to a PPA with a single offtaker and our Big Level wind project in Pennsylvania, which has a 90 MW capacity and is subject to a PPA with Microsoft Corporation.






TRANSALTA CORPORATION M77

Management’s Discussion and Analysis
We have the ability to generate, trade, purchase and sell: EPCs; Alberta carbon offset credits; Renewable Energy Credits ("RECs"); and emission offsets. Alberta carbon offsets can be voluntarily generated by Alberta projects, which meet Alberta carbon offset system qualification protocols. Our Alberta wind facilities generate Alberta carbon offset credits or EPCs. EPCs are credits generated by regulated facilities that reduce GHG emissions below their specified reduction targets in the Alberta-based carbon market. RECs are produced from our renewable energy assets (wind, hydro and solar) and can be traded in voluntary carbon markets or sold to customers. RECs can be used to meet regulatory requirements when a target for renewable energy generation is set by a jurisdiction or can be used to voluntarily "green" electricity procurement. Emissions offsets are produced from voluntary projects that reduce emissions in sectors of the economy not covered by carbon reduction regulations. The optimization of environmental attributes can be used as a cost-effective way, for the Corporation or our customers, to lower compliance costs attributed to carbon policies or renewable portfolio standards, or utilized to achieve voluntary corporate sustainability or carbon reduction goals.

Energy Affordability
TransAlta focuses on assisting commercial and industrial customers in managing their cost of energy. TransAlta has a full suite of procurement strategies and products with various terms available to our customers to assist in understanding and reducing their energy costs.

For customers interested in making a long-term commitment to obtain predictable costs, TransAlta has the experience to develop cogeneration facilities or long-term offtake agreements from its existing and future gas fired and renewable facilities.

End-Use Efficiency and Demand
TransAlta’s commercial and industrial customers have access to an extensive set of monthly reports providing detailed tracking of customer usage, allowing for corrective action as required, as well as cost-saving recommendations.

Our Power Factor Report advises the customer of sites that operate at less than a 90 per cent power factor so they can consider installing energy-efficient equipment. By reducing the customer’s power system demand charge through power factor correction, the customer’s site puts less strain on the electricity grid and reduces its carbon footprint. TransAlta’s Site Health Report advises customers of a site whose peak demand has been permanently reduced for a variety of reasons from its initial in-service date. The customer may be paying a higher demand charge each month to the distribution company based on the original peak demand expected at the site. TransAlta collaborates with the customer and determines the new peak demand based on the customer’s operation. The customer, working with the distribution company, may find it economic to buy down the distribution contract to reduce the monthly distribution costs going forward.





TRANSALTA CORPORATION M78

Management’s Discussion and Analysis
Progressive Environmental Stewardship: Natural Capital Management
We continue to increase financial value from natural or environmental capital-related business activities, while minimizing our environmental footprint and potential risk factors related to environmental impacts. Comparable EBITDA from renewable energy generation in 2020 was $353 million (2019 - $341 million). Our revenue in 2020 from environmental attribute sales was $25 million (2019 - $28 million). In addition, in 2020 the sale of coal byproducts and waste-related recycling generated financial value in the range of $15 million to $20 million. This is lower than our range reported in 2019 of $25 million to $35 million due to our ongoing transition away from coal-fired generation.

The following are key trends in our natural capital:
Year ended Dec. 31 2020 2019 2018
Renewable energy comparable EBITDA 353 341 342
Environmental attribute sales revenue 25 28 22
GHG emissions (million tonnes CO2e)
16.4 20.6 20.8

Environmental Strategy
All energy sources used to generate electricity have some impact on the environment. While we are pursuing a business strategy that includes investing in renewable energy resources such as wind, hydro and solar, we also believe that natural gas will continue to play an important role in meeting energy needs as part of a clean electricity transition. Natural gas provides low-emission baseload and peaking generation to support system demands and intermittent renewable generation. TransAlta operates simple and combined-cycle natural gas units and cogeneration facilities. Since 2002, we have retired over 2,000 MW of coal and converted approximately 420 MW of coal to gas. Our conversion to gas transition is ongoing, and we plan to convert or repower Alberta coal units to natural gas in the 2020 to 2023 timeframe while retiring our Washington State coal facility by the end of 2025. In 2026, our generation mix will be made up of natural gas and renewable energy only.

Regardless of the fuel type, we place significant importance on environmental compliance and continued environmental impact mitigation, while seeking to deliver low-cost and reliable electricity. The Corporation strives to be environmentally responsible and recognizes that the competitive pressures for economic growth and cost efficiency must be integrated with sound sustainability management, including environmental stewardship.

We are subject to environmental laws and regulations that affect aspects of our operations, including air emissions, water quality, wastewater discharges and the generation, transport and disposal of waste and hazardous substances. The Corporation’s activities have the potential to damage natural habitat, impact vegetation and wildlife, or cause contamination to land or water that may require remediation under applicable laws and regulations. These laws and regulations require us to obtain and comply with a variety of environmental registrations, licenses, permits and other approvals. The environmental regulations in the jurisdictions in which we operate are robust. Both public officials and private individuals may seek to enforce environmental laws and regulations against the Corporation. We interact with a number of regulators on an ongoing basis, including but not limited to: Alberta Environment and Parks; Ministry of the Environment, Conservation and Parks in Ontario; Ministry of Natural Resources and Forestry in Ontario; Ministry of Forest Lands, Natural Resource Operations and Rural Development in British Colombia; Environment and Climate Change Canada; Fisheries and Oceans Canada; Michigan Department of Environment, Great Lakes, and Energy; Southwest Clean Air Agency in Washington; Washington State Department of Ecology; Washington State Department of Health; US Environmental Protection Agency (EPA); and the Department of Agriculture, Water and the Environment in Australia; and the Clean Energy Regulator in Australia.

Currently, the most material natural or environmental capital impacts to our business are GHG emissions, air emissions (pollutants, metals) and energy use. Other material impacts that we manage and track performance on via our environmental management systems include land use, water use and waste management.

Environmental Governance
The GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Corporation’s monitoring of environmental, health and safety regulations, public policy changes, the establishment and adherence to environmental, health and safety practices, procedures and policies in response to legal/regulatory and industry compliance or best practices. The importance of environmental protection is outlined under our Total Safety Management Policy as a corporate responsibility for TransAlta, and the personal responsibility of each employee and contractor working on TransAlta's behalf. This policy is approved by our President and Chief Executive Officer ("CEO").

For more details on governance, please refer to the Governance and Risk Management section of this MD&A.




TRANSALTA CORPORATION M79

Management’s Discussion and Analysis
Environmental Management Systems
All of our 75 facilities have Environmental Management Systems (“EMS”) in place, the majority of which closely align with the internationally recognized ISO 14001 EMS standard. We have operated our facilities in line with ISO 14001 for over 20 years, and our systems and knowledge of management systems are therefore mature. Only two facilities do not have ISO 14001 aligned EMS in place, although these facilities do have a comparable EMS in place. This is due to commercial arrangements (TransAlta is not the operator of those two sites). Aligning with ISO 14001 provides assurance that our systems are designed to continuously improve performance.

Environmental Performance
Reducing the environmental impact of our activities benefits not only our operations and financial results, but also the communities in which we operate. We have a proactive approach to minimizing environmental risks and we anticipate this strategy will benefit our competitive position as stakeholders and society place an increasing emphasis on successful environmental management.

Renewable Energy and Battery Storage
Since 2005, we have added over 1,500 MW in renewable electricity capacity. We operate over 900 MW of hydro energy and our experience with hydro operations spans over 109 years. We were an early adopter of wind energy and today operate 1,500 MW of wind power. In 2015, we made our first solar investment in a 21 MW solar facility in Massachusetts, and we continue to look for opportunities to develop and operate solar energy. In 2020, we commissioned the first utility-scale battery storage project in Alberta, located at our Summerview II wind facility. The project uses Tesla battery technology and has a capacity of 10 MW.

Our production from renewable electricity in 2020 offset the equivalent of approximately 2.9 million tonnes of CO2e, or the removal of approximately 630,000 cars from North American roads. The estimated GHG offset is calculated using production data (MWh) from each renewable facility multiplied by the regional (provincial or state) grid emissions intensity. This supports our customers in achieving their renewable energy procurement and/or GHG emissions reduction goals. For more details on the types of environmental attributes we generate for customers, please refer to the Customers section of this MD&A.

Natural Gas
Natural gas plays an important role in the electricity sector, providing low-emission baseload and peaking generation to support system demands and intermittent renewable generation as part of a clean electricity transition. TransAlta operates simple-cycle, combined-cycle, and cogeneration facilities in Canada, the US and Australia. Natural gas facilities provide highly efficient electricity and, in the case of cogeneration, steam production, directly for customers and for the wholesale markets. TransAlta is a significant operator of natural gas electricity in Canada and Australia. We have started converting or repowering Alberta coal units to natural gas. We continue to see a role for natural gas in the future to support system demands and increasing demand for power from customers.

Coal Transition
Our conversion to gas transition plan in Alberta is expected to significantly reduce our environmental footprint. As a result of our coal retirements, conversion to gas and repowerings, our energy use, GHG emissions, air emissions, waste generation and water usage will significantly decline. Transitioning off coal will eliminate all of our mercury emissions, the majority of particulate matter and sulphur dioxide emissions ("SO2"), as well as significantly reduce our NOx emissions. The coal retirements eliminate significant GHGs, and the conversion of our Alberta coal facilities to natural gas reduces GHG emissions by 40-60 per cent and supports system reliability, affordability and the growth of renewable electricity in Alberta. Our converted or repowered facilities will also use lower carbon natural gas, compared to facilities in other jurisdictions, as new methane reduction regulations in Alberta and Canada will reduce GHGs in the production and processing phase with respect to flaring and venting of methane (fugitive GHG emissions).

In 2020, TransAlta announced plans to fast-track away from coal mining and coal-fired power generation in Canada by the end of 2021. At our Centralia coal facility in Washington State, one unit was retired in 2020 and the second unit will retire by the end of 2025. In 2022, our coal capacity will be 670 MW, a significant reduction from coal capacity of approximately 5,000 MW in 2015. Coal will be entirely eliminated from our operations by the end of 2025.






TRANSALTA CORPORATION M80

Management’s Discussion and Analysis
Energy Use
TransAlta uses energy in a number of different ways. We burn gas, diesel and coal (to the end of 2021 in Canada and the end of 2025 at Centralia) to generate electricity. We harness the kinetic energy of water and wind to generate electricity. We also generate electricity from the sun. In addition to combustion of fuel sources, we also track combustion of gasoline or diesel in our vehicles and the electricity use and fuel use for heating (such as natural gas) in the buildings we occupy. Knowledge of how much energy we use allows us to optimize and create energy efficiencies. As an electricity generator, we continually and consistently look for ways to optimize and create efficiencies related to the use of energy. For example, in 2019, we supported a study conducted by Stanford University to understand how to improve wind production. The research showed that angling turbines slightly away from the wind can boost energy produced and even out variable supply.

The following table captures our energy use (millions of gigajoules). Energy use declined by 19 per cent in 2020 over 2019, primarily as a result of reduced coal use. Minor revisions were made to our energy use data in 2020 as a result of accrual adjustments from 2019 and 2018. Historical 2019 total energy use was revised from 345 million gigajoules to 346 million gigajoules as a result of these changes. Due to rounding, there was no impact to our reported 2018 total.

Year ended Dec. 31 2020 2019 2018
Hydro — — — 
Wind & Solar — — — 
North American Gas 30 30  28 
Australia Gas 21 20  20 
Alberta Thermal 135 168  203
Centralia 93 128  107 
Corporate and Energy Marketing —  —  — 
Total energy use (million gigajoules) 279 346 358

Air Emissions
Our coal facilities emit air emissions that we track, analyze and report to regulatory bodies. We also work on mitigation solutions depending on the type of air emission. We report our major air emissions from coal, which includes NOx, SO2, particulate matter and mercury. We will continue reducing air emissions in our existing fleet through our conversion and retirement of coal units in Alberta and Washington State. In 2020, we accelerated our target of 95 per cent SO2 and 50 per cent NOx emission reductions over 2005 levels by moving the target date from 2030 to 2026. In addition, we increased the stringency of our reduction levels for NOx to 80 per cent. Since 2005, we have reduced SO2 emissions by 83 per cent and NOx by 68 per cent. We continue to capture 80 per cent of mercury emissions at our coal facilities and, by the end of 2025, mercury emissions will be eliminated following the conversions to gas, Sundance Unit 5 repowering and the retirement of the Centralia facility. Particulate matter and SO2 emissions will also be virtually eliminated or considered negligible.

None of our Alberta coal facilities are located within 50 kilometres of dense or urban populations, but our Centralia thermal facility in Washington State is 40 kilometres from a dense or urban population. As per guidance from SASB, “a facility is considered to be located near an area of dense population if it is located within 49 kilometres of an area of dense population” (being deemed to be a "minimum population of 50,000 persons"). The Centralia thermal facility has two units and we retired one unit in 2020 and will retire the additional unit by the end of 2025, at which time air emissions from our coal facilities will be eliminated.

Our gas facilities emit low levels of NOx that trigger reporting obligations to national regulatory bodies. These gas facilities also produce trace amounts of SO2 and particulate matter, but at levels that are deemed negligible and do not trigger any reporting requirements or compliance issues. Many of our gas facilities are located in very remote and unpopulated regions, away from dense urban areas. Our Sarnia, Windsor, Ottawa and Fort Saskatchewan gas facilities are our only facilities with air emissions within 49 kilometres of dense or urban environments.

Our total air emissions in 2020 decreased compared with 2019 levels. Specifically, NOx was reduced 19 per cent, particulate matter was reduced 36 per cent and SO2 was reduced 26 per cent over 2019 levels. Mercury emissions also decreased by 12 per cent over 2019 levels (which is not reflected in the table below due to rounding). Reductions in emissions were largely due to an increase in co-firing (gas and coal) at our Alberta thermal facilities and a reduction in production from our Centralia coal facility. Historical NOx incurred minor revisions in 2020 to include NOx emissions from our Highvale mine. The revision increased 2018 NOx from 28,000 to 29,000 tonnes. There was no change to reported 2019 tonnes as the revision was minor and, with rounding, the volume remains consistent.





TRANSALTA CORPORATION M81

Management’s Discussion and Analysis
The following table represents our material air emissions. Figures have been rounded to the nearest one thousand with the exception of mercury, which are rounded to the nearest ten as totals are considerably lower:

Year ended Dec. 31 2020 2019 2018
Sulphur dioxide (tonnes) 12,000  16,000  19,000 
Nitrogen oxides (tonnes) 21,000  26,000  29,000 
Particulate matter (tonnes) 5,000  8,000 8,000 
Mercury (kilograms) 60 60 70

Water
Our principal water use is for cooling and steam generation in our coal and gas facilities but our hydro operations also require water flow for operations. Water for coal and gas operations is withdrawn primarily from rivers where we hold permits to withdraw water and must adhere to regulations on the quality of discharged water. The difference between withdrawal and discharge, representing consumption, is due to several factors, which include evaporation loss and steam production for customers. Typically, TransAlta withdraws in the range of 220-240 million m3 of water across our fleet. In 2020, we withdrew approximately 240 million m3 (2019 - 260 million m3) and returned approximately 200 million m3 (2019 - 220 million m3) or 85 per cent. Overall, water consumption was approximately 40 million m3 (2019 - 40 million m3). Water withdrawal and consumption was lower in 2020 primarily due to decreased production from our Alberta thermal and Centralia thermal facilities.
Centralia 2019 water data were revised in 2020 as a result of identified discrepancies, which resulted in overreported raw water intake or water withdrawal for sustainability reporting. The issue was specific to 2019 data only. Water from our Centralia facility is also reported to the Department of Ecology (“DOE”) in Washington State. There were no issues with our data submitted to the DOE, as the information generated for sustainability reporting followed a separate data collection process. As a result, Centralia 2019 water withdrawal was revised from approximately 52 million m3 to 26 million m3. The Centralia business unit has performed a full review of its water reporting process and our corporate function will review its internal assurance process to support avoidance of any future reoccurrence of this event.

Our 2019 company-wide water withdrawal, total water consumption and water intensity were also revised as a result of this change. Overall water withdrawal reduced from approximately 290 million m3 to 260 million m3 (result of rounding), total water consumption reduced from 70 million m3 to 40 million m3 (result of rounding) and our company-wide water intensity reduced from 2.48 m3/MWh to 1.55 m3/MWh.

In 2020, we established a new water consumption reduction target to reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m3 or 40 per cent in 2026 over a 2015 baseline. Water consumption in 2015 was 45 million m3. This target is in line with the UN's Sustainable Development Goals ("SDGs"), specifically "Goal 6: Clean Water and Sanitation." Our water consumption will fluctuate somewhat over the period of 2020-2025 as we transition off coal, convert and repower gas facilities and ramp production upwards.

The following represents our total water consumption (million m3) over the last three years. Figures below have been rounded to the nearest 10 million m3:

Year ended Dec. 31 2020 2019 2018
Water withdrawal 240 260 250
Water discharge 200 220 210
Total water consumption (million m3)
40 40 40


Our largest water withdrawal and discharge occurs at our Sarnia gas cogeneration facility (which produces both electricity and steam for our customer). The facility operates as a once-through, non-contact cooling system for our steam turbines. Despite large withdrawals from the adjacent St. Clair River to support our Sarnia operations, we return approximately 93 per cent of the water withdrawn. Water from this source is currently at "low risk" as per analysis from the SASB-endorsed Aqueduct Water Risk Atlas tool.






TRANSALTA CORPORATION M82

Management’s Discussion and Analysis
The Aqueduct Water Risk Atlas tool highlights that water risk is high at our interior and southern Western Australia facilities due to high interannual variability in the region. Interannual variability refers to wider variations in regional water supply from year to year. Our water supply at these facilities is provided at no cost under PPAs with our mining customers, hence our risk is significantly mitigated. In addition, our customers have developed conservation and re-use strategies aimed at recycling water for mining operational needs. All water used in the region is sourced from scheme water, and with respect to gas and diesel turbine water use, water wash techniques and frequency of activities are continually modified to minimize consumption and environmental impact. Water used in our operations is returned to our customers, who repurpose this water for vegetation and dust suppression in their mining operations.

At the South Hedland facility in Western Australia, water risk is also high due to the risk of flooding in the region. The South Hedland facility was built above normal flood levels to mitigate potential risk from flooding. During a category 4 cyclone event in the area and associated flooding in the region in 2019, the South Hedland facility stayed dry and continued to generate power for the region. In addition, the South Hedland facility has developed a Water Efficiency Management Plan with Water Corporation WA, the principal supplier of water, wastewater and drainage services in Western Australia. Initiatives are aimed at reducing water consumption and costs through innovative technology and efficiencies identified through facility management.

In southern Alberta, our hydroelectric facilities have played an increasingly important water management role following the flood of 2013. In 2016, we signed a five-year agreement with the Government of Alberta to manage water on the Bow River at our Ghost Reservoir facility to aid in potential flood mitigation efforts, as well as at our Kananaskis Lakes System (which includes Interlakes, Pocaterra and Barrier) for drought mitigation efforts.

Waste
The importance of environmental protection and managing waste is outlined in our Total Safety Management Policy as a corporate responsibility for TransAlta, and a responsibility of each employee and contractor working on TransAlta's behalf. Our waste data is reported annually to a number of different regulatory bodies.

In 2020, our operations generated approximately 1.1 million tonnes equivalent of waste (2019 - 1.5 million tonnes). Of total waste generated, 98 per cent was non-hazardous waste and two per cent was hazardous waste. In 2020, only 0.1 per cent of total waste generated was directed to landfill. From the remaining 99.9 per cent, 45 per cent was returned to the mine (ash from coal combustion), 47 per cent was reused or sold to third parties, three per cent was recycled and five per cent was stored.

In 2020, we established a new waste reduction target that by 2022 TransAlta will reduce total waste generation by 80 per cent over a 2019 baseline of 1.5 million tonnes equivalent of waste generation. This is in line with the UN's SDGs, specifically, "Goal 12: Responsible Consumption and Production."

Our reuse waste or byproduct waste is generally sold to third parties. Byproduct sales and associated annual revenue generation typically ranges from $15 million to $20 million. Our operating teams are diligent at not only minimizing waste, but also maximizing recoverable value from waste. We have invested in equipment to capture byproducts from the combustion of coal, such as fly ash, bottom ash, gypsum and cenospheres, for subsequent sale. These non-hazardous materials add value to products like cement and asphalt, wallboard, paints and plastics.

Given our transition off coal, we will no longer produce fly ash waste in Canada past the end of 2021 and past the end of 2025 in the US. The Corporation is looking at recovering fly ash that was returned to its original source at Highvale mine to replace this supply, which is used extensively in the concrete industry. By turning the recovered product into something marketable, it will continue to aid in reducing the amount of cement produced and consequent emissions while offering new job and economic growth opportunities. This innovative technology contributes to a circular economy and will reduce reclamation liabilities for TransAlta.






TRANSALTA CORPORATION M83

Management’s Discussion and Analysis
Biodiversity
The importance of environmental protection and biodiversity is outlined in our Total Safety Management Policy as a corporate responsibility for TransAlta, and a responsibility of each employee and contractor working on TransAlta's behalf. We consider the biodiversity impact at all of our existing operations (with greater focus being given to mining operations) and the biodiversity impacts of all new growth projects are evaluated in line with regulatory compliance and with respect to TransAlta's focus on biodiversity, which is to support biodiversity health.

Growth
Each new TransAlta development project must complete an in-depth environmental assessment (as prescribed by the local regulation and in line with our own assessment practices) describing baseline environmental conditions, identifying potential effects and developing mitigation for identified environmental sensitivities prior to construction and operation. These assessments have been specifically designed to meet the environmental information requirements of the respective regions in which we operate while identifying alignment with the intent of the standards and/or regulations applicable to these jurisdictions (e.g., Wildlife Directive for Alberta Wind Energy Projects, US Fish & Wildlife Service Land-Based Wind Energy Guidelines, etc.). Typically, our renewable projects are greenfield development projects that require a higher level of evaluation compared to a number of our gas projects, which integrate into existing industrial facilities.

In addition, TransAlta provides a detailed wildlife mitigation plan to environmental regulators outlining specific measures that will be employed to mitigate the effects that project construction and operation activities may have on wildlife, wildlife habitat and specific wildlife features identified during environmental studies completed during the development stage.

Each greenfield development project has a detailed stakeholder consultation plan designed to ensure all potentially impacted host landowners, stakeholders, agencies, businesses, non-governmental organizations ("NGOs"), environmental NGOs and Indigenous communities understand the nature of the projects, have multiple and varied opportunities for engagement and feedback, and are able to engage in meaningful dialogue and discussion with TransAlta and its representatives. The ultimate goal is addressing, solving and mitigating stakeholder or Indigenous community biodiversity concerns before filing major permit applications for all of our projects.

Day-to-Day Operations
At our Alberta thermal operations, we have a Wildlife Monitoring Program designed to monitor wildlife abundance and species diversity in the study area over time. Based on these surveys, TransAlta has seen primarily stable or increasing biodiversity in the area, with various new bird species being detected over the years and incidents of vehicle collisions decreasing due to lower speed limit restrictions. Some animal population sizes fluctuate in the area based on weather conditions and available ground cover.

Our natural gas operations have a relatively limited impact on biodiversity. The facilities are frequently constructed adjacent to existing industrial operations, and TransAlta may not always be the holder of the environmental permits. The land area these facilities occupy is also generally relatively small. One exception is our Sarnia cogeneration facility. This facility is made up of 260 acres of brownfield industrial land, some of which contains areas with tall grasses and potential wildlife. Care will be taken at the time of redevelopment of this land to minimize impact to species at risk through the completion of species-at-risk surveys as well as performing certain construction activities outside of nesting periods. For all sites that are under our environmental scope, we adhere to all relevant environmental compliance permits.

At our hydro facilities, a major focus is on reducing the impact on fish and fish habitat. We adhere to provincial and federal regulations and operate in accordance to facility approvals. We continue to work towards operational improvement and regularly review our Environmental Operational Management Plans to ensure our operating parameters are met.

At our wind and solar operations, the business unit has established the WiSPER (Wind Stewardship Planning and Environmental Reporting) Program. The goal of the program is to provide continuous improvement and ongoing environmental monitoring programs beyond TransAlta’s regulatory requirements. This is achieved through periodic audit and inspection programs, and through collaboration with industry and the scientific community to address environmental concerns and impacts. An Operational Environmental Management Plan has been developed for each renewable asset to ensure that our facilities use environmentally sound and responsible practices that are based on a philosophy of continuous improvement of environmental protection through a program of inspection, monitoring and review.






TRANSALTA CORPORATION M84

Management’s Discussion and Analysis
Examples of WiSPER initiatives to support our biodiversity focus include our Avian Protection Program (installation of covers to protect birds from possible electrocution), a bird and bat mortality database (records all injuries and mortalities), environmentally sensitive resource monitoring (monitoring sensitive wildlife features in and around our operating wind facilities such as raptor nests and sharp-tailed grouse leks), long-term dataset collections (e.g., wildlife studies pre-construction and post-construction) and community wind education programs.

For further details on our environmental strategy, please refer to the Environmental Incidents and Spills discussion and the Land Use discussion of this MD&A.

Land Use
The largest land use associated with our operations is for surface mining of coal. Of the three mines we have operated, the Whitewood mine in Alberta is completely reclaimed and the land certification process is ongoing. Our Centralia mine in Washington State is currently in the reclamation phase and we have adopted a target to fully reclaim this mine by 2040.

Our Highvale mine in Alberta is actively mined with certain sections undergoing reclamation. The Highvale mine will close at the end of 2021 as part of discontinuing coal-fired power generation in Canada at the end of 2021. In 2020, our reclamation team updated our mine reclamation plans. The updated plans align with community priorities for the reclaimed land. These reclamation plans were submitted to the regulator and we are seeking approval on these plans. The regulator timeline for approval can be anywhere from one to three years. Our reclamation plans at Highvale are set out on a life-cycle basis and include contouring disturbed areas, re-establishing drainage, replacing topsoil and subsoil, re-vegetation and land management. Our mining practice incorporates progressive reclamation where the final end use of the land is considered at all stages of planning and development. Associated with our plans, we have recently announced a target to have the Highvale mine fully reclaimed by 2046.

In 2020, the Centralia mine planted 81,000 Douglas Fir trees on land that was reclaimed in previous years. However, further reclamation work at our Centralia was paused in 2020 due to the COVID-19 pandemic. At our Highvale mine, approximately 25 acres (10 hectares) were reclaimed in 2020.

Across our mining operations, to date we have reclaimed approximately 12,000 acres (4,800 hectares), which is approximately 38 per cent of land disturbed. Since 1991, we have planted approximately 2.5 million trees as part of this reclamation work.

Incidents and Spills
Protecting and minimizing our impact on the environment supports healthy ecosystems and mitigates our environmental compliance risk and reputational risk. We maintain procedures for environmental incidents similar to our safety practices, with tracking, analyzing and active management to minimize occurrences. With respect to biodiversity management (management of ecosystems, natural habitats and life in the areas we operate) we seek to establish robust environmental research and data collection to establish scientifically sound baselines of the natural environment around our facilities to ensure we can accurately evaluate the level of significance to biodiversity following an incident. We closely monitor the air, land, water and wildlife in these areas to identify and curtail potential impacts.

In 2020, environmental incidents were separated into two categories: significant environmental incidents and regulatory non-compliance environmental incidents. We define regulatory non-compliance environmental incidents as events involving a non-compliance event that did not have an impact on the environment. For example, a technical issue with a computer system for gathering real-time data could cause us to be out of compliance with local regulation or our EMS, but there is no direct consequence for the physical environment. All other events are captured as significant environmental incidents if there is some level of impact to the environment. In 2020, we recorded six significant environmental incidents (2019 - three incidents). Our six significant environmental incidents (all bird and bat strikes — further details below) will not cause any long-term impacts on the environment and the associated ecosystem and did not trigger any enforcement action. The Corporation is working to ensure our classification is accurate as a true significant environmental incident is one that causes harm to the environment and poses a long-term impact on a local ecosystem. In 2020 we note that we did not experience an incident with such an impact. We recorded two regulatory non-compliance environmental incidents in 2020 (2019 – six incidents). Both of these incidents occurred at our Sarnia facility and were related to an exceedance of discharge from our sumps during water treatment. Both incidents had negligible environmental impact.

Our six significant environmental incidents in 2020 occurred at our Summerview (Alberta), Antrim (New Hampshire) and Big Level (Pennsylvania) wind facilities. Four New Hampshire state-listed bat carcasses were found during the post-construction biological survey in Antrim (three little brown bats and one eastern small-footed bat). One Pennsylvania state-listed bird (yellow-bellied flycatcher) was found during the post-construction biological survey at Big Level. A ferruginous hawk, a listed species in Alberta, was found during an ongoing inspection during normal operation. In each




TRANSALTA CORPORATION M85

Management’s Discussion and Analysis
case, root cause analysis investigations were performed, and we found no causal factors or root causes related to human behaviour or equipment failure being involved in the incidents. For all incidents, we collaborated with authorities and there were no enforcement actions with respect to the mortalities. Despite inconclusive findings, smart bat curtailment optimization is contemplated in Antrim and the biological monitoring studies continues at relevant sites.

Significant environmental incidents by business segment follow:
Year ended Dec. 31 2020 2019 2018
Hydro — — — 
Wind & Solar 6 3 — 
North American Gas — —  — 
Australia Gas — —  — 
Alberta Thermal — —  1
Centralia — —  — 
Corporate and Energy Marketing — — —
Total significant environmental incidents 6 3 1


Regulatory non-compliance environmental incidents by business segment follow:
Year ended Dec. 31 2020 2019 2018
Hydro — —  — 
Wind & Solar — 1 — 
North American Gas 2 2  2 
Australia Gas — —  — 
Alberta Thermal — 2  2
Centralia — 1  2 
Corporate and Energy Marketing — —  —
Total regulatory non-compliance environmental incidents 2 6 6

Some examples of mitigation measures TransAlta has taken include:

▪Installation of artificial nest platforms to increase breeding opportunities for endangered ferruginous hawks in southern Alberta;
▪Installation of bluebird nest boxes to increase breeding habitat for this sensitive species found at some of our southern Alberta wind facilities;
▪Bobolink Management Plan at the Wolfe Island wind facility – creation of 50 acres of breeding habitat for bobolink (a sensitive bird species in Ontario) to offset the potential impacts of the Wolfe Island wind facility on this species; and
▪Implementing operational bat curtailment at the Antrim, Big Level, Summerview and Kent Breeze wind facilities during the fall bat migration period (July to September) to reduce bat mortality at these sites by increasing the cut-in speed.

For 2021, we are removing our target for environmental incidents. This is because we do not tend to experience environmental incidents that have a large or lasting impact on the environment and an ecosystem, and we believe it is prudent to instead focus on other environmental areas that are more material for the Corporation. This will not change our internal focus on mitigation of environmental incidents. We continue to track and manage all environmental incidents, including all non-reportable (minor) environmental incidents, which helps us identify what causes an incident. Understanding the root cause of incidents helps with incident prevention planning and education.

Regarding spills and releases, typical spills that could occur at our operation sites are hydrocarbon-based. Spills generally happen in low environmental impact areas and are almost always contained and fully recovered. It is extremely rare for large spills to occur. Efforts are placed on providing a quick response to all spills to ensure assessment, containment and recovery of spilled materials result in minimal risk to the environment.





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Management’s Discussion and Analysis
There is a potential that ash ponds associated with our coal facilities could fail. The probability of this occurring is low, but the impact could be significant. We follow applicable environmental regulations with respect to our ash ponds and satisfy ourselves that management is adequate given the robust regulations in the jurisdictions where we operate. Management includes periodic inspections and appropriate mitigation if issues are uncovered. An inspection in 2020 noted cracks in one of our ponds. In response, a restoration plan was developed to fix the issue. The total cost of mitigation was $1 million.

The estimated volume of spills in 2020 was 4 m3 (2019 - 530 m3). Spill volumes in 2019 were higher due to a 527 m3 spill at our Sarnia cogeneration facility. This was not a traditional product spill and was a wastewater effluent limit exceedance from a sump. There was no enforcement action associated with this spill.

Weather
Abnormal weather events can impact our operations and give rise to risks. Due to the nature of our business, our earnings are sensitive to weather variations from period to period. Variations in winter weather affect the demand for electrical heating requirements. Variations in summer weather affect the demand for electrical cooling requirements. These variations in demand translate into spot market price volatility. Variations in precipitation also affect water supplies, which in turn affect our hydroelectric assets. Also, variations in sunlight conditions can have an effect on energy production levels from our solar facility. Variations in weather may be impacted by climate change resulting in sustained higher temperatures and rising sea levels, which could have an impact on our generating assets. Ice can accumulate on wind turbine blades in the winter months. The accumulation of ice on wind turbine blades depends on a number of factors, including temperature and ambient humidity. Accumulated ice can have a significant impact on energy yields and could result in the wind turbine experiencing more downtime. Extreme cold temperatures can also impact the ability of wind turbines to operate effectively and this could result in more downtime and reduced production. In addition, climate change could result in increased variability to our water and wind resources.

Our generation facilities and their operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g., floods, high winds, fires and earthquakes), equipment failures and other events beyond our control. Climate change can increase the frequency and severity of these extreme weather events. The occurrence of a significant event that disrupts the operation or ability of the generation facilities to produce or sell power for an extended period, including events that preclude existing customers from purchasing electricity, could have a material adverse effect. Our generation facilities could be exposed to effects of severe weather conditions, natural or man-made disasters and other potentially catastrophic events such as a major accident or incident at our sites. In certain cases, there is the potential that some events may not excuse us from performing our obligations pursuant to agreements with third parties. The fact that several of our generation facilities are located in remote areas may make access for repair of damage difficult. Please refer to the Governance and Risk Management section of this MD&A for further discussion on weather-related risks.

During the past three years, we have experienced no significant impacts to annual financial results due to deviations from expected weather patterns.





TRANSALTA CORPORATION M87

Management’s Discussion and Analysis
Progressive Environmental Stewardship: Climate Change Management
We believe in open and transparent reporting on material impacts relating to climate change. Our climate change reporting is structured as per guidance from the Financial Stability Board's TCFD recommendations. The following highlights our management, performance and leadership of impacts related to climate change.

TransAlta Climate Change Action - Highlights

▪The GSSC includes in its mandate that it will review guidelines and practices relating to environmental protection and the Corporation's plans with respect to environmental impact;
▪Our strategy involves moving away from GHG-intensive coal and achieving a 100 per cent mix of renewables and natural gas by the end of 2025;
▪Our business is showing resilience to mitigation of global warming by reducing GHG emissions — we have a target to reduce annual emissions by 19.7 million tonnes of CO2e by 2030 over 2015 levels and a new goal to be carbon neutral by 2050. Since 2015, we have reduced our annual emissions by 15.8 million tonnes of CO2e or approximately 80 per cent of required GHG reductions to meet this target;
▪We have reduced our annual emissions by approximately 25 million tonnes of CO2e since 2005, which is a 61 per cent reduction over the time period and highlights our decarbonization track record - this is the equivalent annual GHG emissions of a small country;
▪As a leader in North American renewable energy, and on-site generation development and production, we are well positioned to build renewable energy facilities and lower-carbon gas facilities to support customer sustainability goals to decarbonize; and
▪In 2020, CDP (the global disclosure system for environmental impacts known formerly as Carbon Disclosure Project) recognized TransAlta with an A- score, ranking the Corporation among industry leaders on climate change management.

Climate Change Governance
The highest level of oversight on business impacts related to climate change is at our Board level, specifically by the GSSC and the AFRC. Macro issues and opportunities such as coal GHG emissions and the phase-out of coal power generation, cost-competitiveness of renewable energy and customer preferences toward lower carbon energy have been at the forefront of strategic discussions with our executive and Board. These deliberations resulted in our actions to move away from coal, establish 2030 and 2050 GHG emissions reduction targets and grow our generation capacity with renewable energy and gas.

The GSSC has oversight of climate-related issues. Meeting on a quarterly basis, the GSSC's charter includes "monitoring and assessing climate change risks and compliance with associated legislation and public reporting." The charter also directs that the GSSC "at least annually, review guidelines and practices relating to environmental protection, including the mitigation of pollution and climate change; consider whether TransAlta’s policies and practices relating to the environment are being effectively implemented, and discuss and advise regarding the development of policies and practices regarding climate change, greenhouse gas and other pollutants."

In addition to the GSSC, climate risks are reviewed through the AFRC. For example, climate policy considerations are factored into decision-making with respect to conversion of coal facilities to gas facilities. In addition, many of our new projects, including clean energy projects, are reviewed by other committees of the Board and climate risk and opportunity is factored into those committee deliberations. As a result, climate change related capital expenditures, acquisitions and budgets are also reviewed at the Board level on a case-by-case basis.

Notably, five of our Board members have identified Environment and Climate Change as being among their top four relevant competencies. We have noted this in our skills matrix section of our 2020 Management Proxy Circular on page 33.

The highest level of oversight on climate change at our executive level is with the President and CEO. Climate change related risks are monitored and actively managed through our TransAlta-wide risk management processes. Climate change risks and opportunities are identified and reviewed at the Board level and all levels of the Corporation. The business units and corporate functions work closely together and flow risks and opportunities upwards to the executive and the Board. Risks and opportunities are reviewed by our CEO and executive team quarterly and are reported to the GSSC and the AFRC.

A significant component of executive compensation is tied to achieving our strategic goals, which include growing renewable energy, reducing GHG emissions through our conversion to gas transition and supporting our customer sustainability goals to decarbonize through on-site low carbon generation. Our corporate executive annual incentive plans (short-term incentive or annual bonus and long-term share incentives) are linked to TransAlta's performance (i.e.,




TRANSALTA CORPORATION M88

Management’s Discussion and Analysis
"pay for performance"). These incentives are linked to execution of strategic goals and our compensation philosophy is designed to drive the right actions to achieve our strategic goals. The long-term incentive plan for the period 2018 to 2020 included a strategic goal to Transition to Renewable Energy. This goal was measured against the performance of the Corporation, which included: advancing and executing our conversion to gas (which results in significant GHG reductions); deliver growth in our renewables fleet (zero or very low carbon assets); expand our presence in the US renewables market (zero or very low carbon assets); advance and grow our on-site generation and cogeneration business (decentralized and low carbon/high energy-efficiency assets); continue to improve our already strong financial position; and remain disciplined with our capital investment strategy. As such, our incentive program is tied to reducing GHG emissions and climate change management.

Climate Change Strategy
TransAlta, and the electricity sector in general, are at the forefront of reducing GHG emissions, pursuing innovative lower-carbon and zero-carbon solutions (e.g., renewable energy, natural gas, distributed power generation, energy storage, etc.) and are showing a path to resiliency in a low-carbon world. Our investments and growth in renewable energy are highlighted by our diverse portfolio of renewable energy-generating assets. We currently operate approximately 2,500 MW of hydro, wind and solar power. In 2020, we completed construction and commercial operation of an additional 136 MW (net 67 MW) of wind generation in the US (2019 - 119 MW). Today, our diversified renewable fleet makes us one of the largest renewable producers in North America, one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta.

In addition to climate resiliency, TransAlta remains focused on reliability of electricity supply and affordability for customers. To support our own path to reduce our GHG footprint and ensure climate resiliency, we have a corporate goal to reduce our GHG emissions by 60 per cent by 2030 over 2015 levels, while growing renewable energy and natural gas. We believe natural gas plays a strong role in supporting grid reliability and supporting customer goals of affordability. In 2021, we have adopted a target to be carbon neutral by 2050. We believe carbon neutrality provides flexibility as we shape our strategy over the coming decades and we believe our clean electricity strategy has us well positioned to support us achieving this.

In 2021, we are conducting scenario analysis to further inform our understanding of risks, opportunities, technologies and pathways with respect to a number of future climate scenarios. This process will help inform us as we evaluate strategic GHG reduction pathways with respect to achieving our target of carbon neutrality by 2050. This target aligns us with efforts in the countries where we operate and broader global efforts under the Paris Agreement.

All our business units and operations consistently seek energy-efficiency improvements, opportunities to integrate clean combustion technologies and development of emissions offset portfolios to achieve emissions reductions at competitive costs. We seek investment in climate change related mitigation solutions, such as renewable energy development, where we can maximize value creation for our shareholders, local communities and the environment. Conversion of our large coal fleet to gas-fired generation highlights this approach, which will allow us to run our assets longer than the federally mandated coal retirement schedule. Our goals for undertaking such actions are to enhance value for our shareholders, ensure low-cost and reliable power, and reduce our GHG footprint.

With respect to our customers, we note that we are shifting our product offering from a GHG-intensive product to a low-carbon product to meet the need to decarbonize and mitigate associated societal risks, but also to meet the changing goals of our customers. We continue to build renewable projects for customers seeking to meet their own sustainability goals, such as carbon neutrality on Scope 2, RE100 goals or net zero. We continue to support customers with on-site power-generation goals, where collectively there is an opportunity to reduce GHG impacts through on-site cogeneration, where power and steam production replace existing higher GHG-intensive boilers. Our conversion of coal facilities to gas will significantly reduce the GHG intensity of the Alberta grid, supporting Scope 2 emission reductions for our customers and Alberta commercial and industrial loads.

Another way we can contribute to our customers’ sustainability goals is through the use of environmental attributes. We have the ability to generate, trade, purchase and sell environmental attributes that include Alberta EPCs, Alberta carbon offsets, RECs and emission offsets. Production from renewable electricity in 2020 resulted in avoidance of approximately 2.9 million tonnes of CO2e for our customers, which is equivalent to removing over 630,000 vehicles from North American roads over the same year. As previously noted, we seek to commoditize carbon through trading and the generation and sale of environmental attributes from renewable energy. Annual revenue generation from the sale of environmental attributes (Alberta carbon offsets and RECs) in 2020 was $25 million.






TRANSALTA CORPORATION M89

Management’s Discussion and Analysis
Climate Change Risk Management
Climate change risks are monitored and actively managed through our TransAlta-wide risk management processes. Although we do not have a formal process to review specific climate change risk, climate change risks and opportunities are identified at the Board level, executive and management level, business unit level (coal, gas, wind, solar and hydro) and through our corporate function (e.g., government relations, regulatory, emissions trading, sustainability, commercial, customer relations and investor relations). The business units and corporate functions work closely together and provide information on risks and opportunities to management, the executive team and the Board. One area that is constantly monitored is climate policy, including the impacts on cost, growth and compliance.

Climate change risks at the asset or business unit level are identified through our EMS, asset management function and systems, our energy and trading business, active monitoring, active participation/communication with stakeholders, liaison with our corporate function, active participation in working groups and more. All identified material risks are added to our Enterprise Risk Management risk register. These risks are assessed and scored based on likelihood and impact (what could have "substantive financial impact," "strategic impact," "stakeholder or reputational impact" or "environment, health and safety impact"). Risks are not considered in isolation. Major risks are the focus of management response and mitigation plans.

Our climate change risks are divided into two major categories as per guidance from the TCFD, which include: (1) risks related to the transition to a lower-carbon economy and (2) risks related to the physical impacts of climate change.

1.    Transition Risks to a Lower-Carbon Economy

We seek to understand the impact on our business as the world shifts to a lower-carbon society. We participate in ongoing decisions related to climate policy and regulation.

Policy and Legal Risks
Ongoing and Recently Passed Environmental Legislation
Changes in current environmental legislation do have, and will continue to have, an impact upon our operations and our business. For further details, please refer to the Governance and Risk Management section of this MD&A.

Canadian Federal Government
Federal Climate Plan
On Dec. 11, 2020, the Government of Canada released its “A Healthy Environment and a Healthy Economy” climate plan that outlines how the federal government intends to use policies, regulations and funding to achieve Canada’s Paris Agreement emission reduction target of 30 per cent reduction from 2005 greenhouse gas emission levels. The three major aspects of the plan include increased carbon prices and obligations, increased funding for clean technology and the implementation of the Clean Fuel Regulation ("CFR"). The government stated that it will consult with provinces and industry regarding many elements of the plan so significant uncertainty remains regarding the final form of the related regulations and other initiatives.

Key proposed elements of the federal plan:
▪Carbon price for the carbon tax and the larger emitters program is to rise $15 per tonne CO2e per year from 2023 until reaching $170 per tonne by 2030;
▪Carbon obligations to rise as performance standards (benchmarks) under large emitter regulations tighten;
▪Over $10 billion of funding will be made available for the energy transition, including support for electric vehicles and clean energy development to battery storage and improved grid technology; and
▪Implementation of the CFR on liquid fuels, but no CFR obligations for gaseous and solid fuels.

TransAlta intends to continue to engage with governments to mitigate risks and identify opportunities within the new federal plan.

Clean Fuel Regulation
In 2016, the Canadian federal government announced plans to consult on the development of a CFR to reduce Canada’s GHGs through the increased use of lower carbon fuels, energy sources and technologies. The objective of the regulation is to achieve 30 million metric tonnes of annual reductions in GHG emissions by 2030.

On Dec. 19, 2020, the Canadian federal government published its draft version of the CFR with the accompanying supporting documents. As a result of gaseous fuels no longer being regulated by the CFR, the CFR will have a limited impact on the electricity sector. Consultation on the regulation will conclude on March 4, 2021. The CFR is scheduled to be finalized in December 2021 and come into force on Dec. 1, 2022.





TRANSALTA CORPORATION M90

Management’s Discussion and Analysis

Federal Carbon Pricing on GHGs
On June 21, 2018, the Canadian federal Greenhouse Gas Pollution Pricing Act ("GGPPA") came into force. Under the GGPPA, the federal government implemented a national price on GHG emissions. On Jan. 1, 2019, the GGPPA's backstop mechanisms came into force in provinces and territories that did not have an independent carbon pricing program or where the existing program was not deemed equivalent to the federal system. The backstop mechanism has two components: a carbon levy for small emitters ("Carbon Tax") and regulation for large emitters called the Output-Based Pricing Standard ("OBPS"). The Carbon Tax sets a carbon price per tonne of GHG emissions related to transportation fuels, heating fuels and other small emission sources.

As noted above, in the "Healthy Environment and a Healthy Economy" plan, the federal government proposed escalating the national price on carbon by $15 per tonne each year from 2023 until it reaches $170 per tonne in 2030.

The OBPS regulates large emitters' carbon intensity by setting a sectoral benchmark of GHG emissions per unit of production (e.g., tonnes CO2e/MWh) for electricity generators. Emitters exceeding the benchmark generate carbon obligations and those emitters that perform below the benchmark generate EPCs. Emitters can meet their obligations by reducing their emission intensity, buying carbon credits from others (offsets or EPCs) or making compliance payments to the government.

As discussed in the provincial sections below, the OBPS does not apply in Alberta and Ontario is in the process of transitioning out of the OBPS and into a provincial industrial carbon pricing system. As a result, TransAlta's Canadian thermal fleet will be regulated by provincial systems moving forward. However, the federal government compares provincial carbon pricing systems against the OBPS when deciding whether provinces have achieved equivalency with the federal government's carbon price under the GGPPA. On Feb. 12, 2021, the federal government began planning for a 2022 review of the OBPS and other aspects of the GGPPA. TransAlta will actively engage in this process as any changes to the OBPS will influence provincial carbon pricing systems in the future.

Gas Regulation
On Dec. 18, 2018, the federal government published the Regulations Limiting Carbon Dioxide Emissions from Natural Gas-fired Generation of Electricity. Under the regulations, new and significantly modified natural-gas-fired electricity facilities with a capacity greater than 150 MW must meet a standard of 420 tonnes CO2e/GWh to operate. For units with a capacity between 25 MW and 150 MW, their standard was set at 550 tonnes CO2e/GWh. Facilities with a capacity less than 25 MW have no standard.

Under the regulations, conversions to gas will also eventually have to meet a standard of 420 tonnes CO2e/GWh. If the first-year performance test after conversion meets certain emission standards it will not have to meet the 420 tonnes CO2e/GWh standard for several additional years past the end of its useful life.

As part of the Healthy Environment and a Healthy Economy Plan, the federal government signalled an interest in exploring a new emissions performance standard for the Canadian electricity sector. There are few details available regarding the potential new standard and TransAlta is engaging the federal government to understand the intent of the proposal.

Coal Regulation
On Dec. 18, 2018, amendments to the Reduction of Carbon Dioxide Emissions from Coal-Fired Generation of Electricity Regulations came into force under the Canadian Environmental Protection Act, 1999. The amended regulations will require coal units to meet an emission level of 420 tonnes CO2e/GWh by the earlier of end-of-life under the 2012 regulations or Dec. 31, 2029.






TRANSALTA CORPORATION M91

Management’s Discussion and Analysis
Alberta
Large Emitter Greenhouse Gas Regulations
On Jan. 1, 2020, the Government of Alberta replaced the previous Carbon Competitiveness Incentive Regulation ("CCIR") with a new regulation called the Technology Innovation and Emissions Reduction ("TIER") Regulation. For the electricity sector, there were negligible changes between CCIR and TIER with renewable facilities continuing to receive crediting. The carbon price for TIER in 2021 will be $40/tonnes CO2e aligned with the GGPPA requirements. The performance standard benchmark remained at 0.370 tonnes CO2e/MWh. A review of TIER is not expected until 2023.

Facilities with emissions above the set benchmark comply with TIER by: a) paying into the TIER Fund (a government-controlled fund that invests in emissions reduction in the province) at the current carbon price; b) making reductions at their facility; c) remitting EPCs from other facilities; or d) remitting emission offset credits.

As required by the GGPPA, the Alberta government files annual reports on TIER program details with the federal government. The federal government reviewed TIER and found it compliant with the GGPPA for 2021. The Corporation will continue to receive offsets and EPCs for its renewable facilities under TIER, ensuring expected revenues are realized.

British Columbia
Beginning April 1, 2018, the British Columbia government increased its carbon tax price to $35 per tonne CO2e and committed to raise the price $5 per year until it reaches $50 per tonne in 2021. Upon review, the government has determined that the carbon tax rate will remain at its current level of $40 per tonne CO2e until April 2021, when it will increase from $40 to $45 per tonne CO2e. The carbon tax will increase to $50 per tonne CO2e in April 2022. The tax has a negligible cost impact for the Corporation as the tax applies primarily to our transportation fuel use, which is negligible in BC.

Ontario
Large Emitter Greenhouse Gas Regulations
On July 4, 2019, the Government of Ontario released its final regulations for the provincial Greenhouse Gas Emissions Performance Standards ("EPS"). On Sept. 21, 2020, the federal government accepted the Ontario government's EPS as meeting the requirements of the GGPPA. In December 2020, the Ontario government published amendments to align the EPS with the GGPPA requirements. The Ontario government also announced its intention to transition from the OBPS to the EPS starting on Jan. 1, 2021. Therefore, Ontario's large emitters were covered by the OBPS for 2019 and 2020 compliance years and will subsequently be covered by the EPS.

This requires TransAlta's Ontario natural-gas-fired assets to track and make compliance filings annually and to meet the carbon emission obligations of the applicable government. There are minor differences between the EPS and OBPS. Compliance requirements will be met through payments and alternative compliance units under the OBPS and EPS. However, change-of-law provisions in the contracts with Sarnia, Windsor and Ottawa allow TransAlta to flow carbon-regulation-related costs to customers, resulting in negligible cost increases to the Corporation.

Michigan
Michigan has air permit requirements related to the Clean Air Interstate Regulation with respect to NOx and SO2 emissions. There are currently no GHG emission compliance requirements other than to report these emissions annually. The Ada cogeneration facility is in compliance with all environment requirements and there have been no recent changes to regulations that would increase costs at the facility.

Washington
In 2010, the Washington Governor's office and State Department of Ecology negotiated agreements with TransAlta related to the operation of Centralia’s two coal-fired electricity generating units. TransAlta agreed to retire its two Centralia coal units: one in 2020 and the other in 2025. This agreement is formally part of the state’s climate change program. We currently believe that there will be no additional GHG emissions regulatory burden on Centralia given these commitments. The related TransAlta Energy Transition Bill was signed into law in 2011 and provides a framework to transition from coal to other forms of generation in the State of Washington.






TRANSALTA CORPORATION M92

Management’s Discussion and Analysis
Massachusetts
The Solar Renewable Electricity Credit I ("SREC I") program carved out from Massachusetts’ Renewable Portfolio Standard ("RPS") an initial quantity of 400 MW from small solar facilities of 10 MW or less. The initial SREC I program size was expanded and replaced by a lower-valued SREC II program. In 2018, the solar incentive program evolved into the current Solar Massachusetts Renewable Target Program that further reduced the incentive levels.

The initial SREC I program’s volume target was achieved, and qualified projects under SREC I continue to generate SREC I credits for their first 10 years post-commercial operation date. SREC I facilities then generate Class 1 RECs under the Massachusetts RPS for the remainder of their operational life.

Under Massachusetts' net metering program, qualified facilities connect with the local utility and generate net metering credits. Net metering credits offset the delivery, supply and customer charges and can be sold to customers from remote or on-site qualifying facilities. In 2016, the net metering program was updated to reduce the value of the net metering credits by reducing the offset to only energy costs. New projects are impacted once the net metering program volume reaches 1,600 MW. Existing facilities were grandfathered and continue to receive the full, original cost offset treatment for a period of 25 years from initial commercial operation.

Le Nordais receives value from the sale of RECs into the New England RPS markets. Massachusetts has proposed a lower compliance cost ceiling on its RPS standard that would effectively cap the value of RECs. This could have a negative impact on Le Nordais' REC sales price. The change in regulation is still being considered and has not yet been put into force.

Australia
On Dec. 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund (the "ERF"). The AU$2.55-billion ERF is the centrepiece of the Australian government's policy and provides a policy framework to cut emissions by five per cent below 2000 levels by 2020 and 26 to 28 per cent below 2005 emissions by 2030. The ERF's safeguard mechanism, commencing from July 1, 2016, is designed to ensure emissions reductions purchased by the Australian government through the ERF are not displaced by significant increases in emissions elsewhere in the economy. The ERF and its safeguard mechanism provide incentives to reduce emissions across the Australian economy.

In addition, on June 23, 2015, the federal Australian government also reformed the Renewable Energy Target ("RET") scheme. The RET is designed to add at least 33,000 GWh/year of renewable sources by 2020. The Australian government has advised there are now sufficient projects approved to meet and exceed the 2020 target of 33,000 GWh/year of additional renewable electricity. The annual target will remain at 33,000 gigawatt hours until the scheme ends in 2030. This would result in approximately 23.5 per cent of Australia's electricity generation being sourced from renewable projects.

The ERF is not expected to have a material impact on our Australian assets. In Australia, electricity has a single sectoral baseline applied to all electricity generators' emissions for units connected to one of Australia's five main electricity grids. The electricity sector baseline has been set at 198 million tonnes CO2e per year. In the most recent high emission years of 2015-2016, total emissions were 179 million tonnes CO2e per year.

If the baseline is exceeded, then all large emitter generation facilities will need to comply with individual facility baselines. The electricity sector should never exceed the sectoral emission target as no new coal generation is to be built and older coal facilities are retiring. The Corporation's gas facilities will not be subject to carbon costs under current regulations unless changes are made.

Technology Risks
Our conversion to gas strategy uses existing infrastructure and applicable technologies (natural gas turbines), which reduce the cost and GHG emissions related to new generation construction and material procurement.

Behind-the-fence generation and energy storage technology are emerging risks to the large-scale power-generation model. However, they are practical solutions for some customers, and TransAlta provides these technologies in addition to providing services to the grid.

We provide behind-the-fence generation or decentralized power to some of our industrial customers to supply on-site electricity generation. This generally can be in the form of a cogeneration system that provides steam for industrial processes in addition to power, or a renewable power system. These systems can either be tied to the grid or independent.





TRANSALTA CORPORATION M93

Management’s Discussion and Analysis
Battery storage has the ability to enable greater adoption of renewables and motivate a shift to a distributed power-generation model. We continue to evaluate battery storage for its financial viability, while monitoring the potential impact battery technology could have on natural gas power generation. TransAlta began commercial operations of Alberta’s first utility-scale lithium-ion battery storage facility, called WindCharger, on Oct. 15, 2020. This project is unique as it uses TransAlta’s existing Summerview II wind facility to charge the battery, allowing WindCharger to be a truly renewable battery energy storage system. The project uses Tesla technology and the potential exists for the expansion of this technology. We are investigating the viability of battery storage at our various wind facility locations and for use in developing customer-specific energy supply solutions.

We have demonstrated upside in growing renewables and gas-powered generation. From 2000 to 2020, we have grown renewables capacity from approximately 900 MW to over 2,500 MW.

Market Risks
TransAlta has taken significant steps since 2005 to reduce its GHG impact and has announced a full transition off coal by the end of 2025. TransAlta continues to operate hydro facilities and invest in, develop and construct on-site natural gas facilities for customers and new renewable energy from wind, solar, and battery technology.

Changing customer behaviour, reduced consumption and associated use of electricity could impact the demand for electricity; however, we believe this risk is mitigated somewhat by the global trend toward electrification of the economy. Our low-carbon business model supports this type of future.

Increased costs for natural gas supply due to carbon pricing can impact our operating costs. Further discussion can be found in the Governance and Risk Management section of this MD&A. Use of renewable resources, such as the wind and sun, remove associated risk related to cost of supply.

Our Corporate function applies regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks pertaining to uncertainty in the carbon market and as a safeguard to anticipate future impacts of regulatory changes on facilities. This information is directed to the business unit level for further integration. Identified climate change risks or opportunities and carbon pricing are recognized in the annual TransAlta long- and medium-range forecasting processes. We capture economic profit through generation of environmental attributes (such as carbon offsets and RECs) and through our emission trading function, which seeks to commoditize and profit from carbon trading.

Reputation Risks
Consumer trends appear to be moving in favour of renewable and cleaner electricity. We are invested in a diversified mix of renewable generation as well as natural gas, as it provides vital support to the electricity system.

2.    Physical Impact Risks of Climate Change

As we learn more about the physical risks associated with climate change and weather, we continue to consider both acute and chronic risk, which could materially impact value creation from our operations.

Acute Risks
We are continuing to evaluate the potential impact of an acute climate change related impact to our business and/or an operational facility or facilities. Our facilities, construction projects and operations are exposed to potential interruption and damage or partial or full loss resulting from environmental disasters (e.g., floods, high winds, fires, ice storms, earthquakes and public health crises, such as pandemics and epidemics). Climate change can increase the frequency and severity of extreme weather events. Further impacts of extreme weather and climate change could result in social unrest, war or terrorism. There can be no assurance that in the event of an earthquake, hurricane, tornado, tsunami, typhoon, or other natural, man-made or technical catastrophe, all or some parts of our generation facilities and infrastructure systems will not be disrupted. The occurrence of a significant event disrupting the ability of our power generation assets to produce or sell power for an extended period, including events that preclude existing customers under PPAs from purchasing electricity, could have a material negative impact on our business.

We seek to mitigate future impact where relevant with climate adaptation solutions. The TransAlta South Hedland facility in Western Australia was built with climate adaptation in mind. The facility is designed to withstand a category 5 cyclone. Category 5 is the highest cyclone rating. Floods, which can occur in the area, have been mitigated by constructing the facility above the normal flood levels. In 2019, when a category 4 cyclone hit this facility, operations were not impacted and we were able to continue generating electricity through the storm, despite widespread flooding and the shutdown of the nearby port and associated business activities.





TRANSALTA CORPORATION M94

Management’s Discussion and Analysis
Chronic Risks
We have not identified any chronic physical risks that could impact our operations. However, we continue to further our understanding and integration of climate modelling into our long-term planning.

Climate Change: Metrics and Targets
In 2020, we estimate that 16.4 million tonnes of GHGs with an intensity of 0.67 tonnes per MWh (2019 - 20.6 million tonnes of GHGs with an intensity of 0.75 tonnes per MWh) were emitted as a result of normal operating activities. This reduction of approximately 20 per cent or 4.2 million tonnes CO2e is primarily the result of co-firing with gas and lower production volumes at our merchant Alberta coal facilities and lower production from our Centralia coal facility. In 2020, our renewable energy facilities also offset approximately 2.9 million tonnes of CO2e for our customers. Because we sell the environmental attributes (offsets and RECs) generated from our renewable energy facilities, we do not net this amount from our total GHGs, but it should be noted that this offset is occurring and our customers are reporting net GHG reductions from TransAlta's renewable energy operating activities.

Our 2020 GHG data is reported to a number of different regulatory bodies throughout the year for regional compliance and, as a result, may incur minor revisions as we review and report data. Any historical revisions will be captured and reported in future disclosure. As per the Kyoto Protocol, GHGs include carbon dioxide, methane, nitrous oxide, sulphur hexafluoride, nitrogen trifluoride, hydrofluorocarbons and perfluorocarbons. Our exposure is limited to carbon dioxide, methane, nitrous oxide and a small amount of sulphur hexafluoride. The majority of our estimated GHG emissions result from carbon dioxide emissions from stationary combustion from coal and natural-gas-powered generation. Emissions data has been aligned with the “Setting Organizational Boundaries: Operational Control” methodology set out in The Greenhouse Gas Protocol: A Corporate Accounting and Reporting Standard developed by the World Resources Institute and the World Business Council for Sustainable Development. As per the methodology, TransAlta reports emissions on an operation control basis, which means that we report 100 per cent of emissions at facilities in which we are the operator. Emissions intensity is calculated by dividing total operational emissions by 100 per cent of production (MWh) from operated facilities, regardless of financial ownership.

Global warming potentials can vary with respect to regional compliance guidance. We compile our corporate GHG inventory using our business segment GHG calculations. The Clean Energy Regulator in Australia amended global warming potentials in August of 2020 and the use of global warming potentials in our Australia Gas GHG calculations differ from the rest of our fleet as a result of these amendments. Applying harmonized global warming potentials across our fleet would result in a minor variance to our overall calculated GHG totals.

The GHG Protocol Corporate Accounting and Reporting Standard classifies a company’s GHG emissions into three scopes. Scope 1 emissions are direct emissions from owned or controlled sources. Scope 2 emissions are indirect emissions from the generation of purchased energy. Scope 3 emissions are all indirect emissions (not included in Scope 2) that occur in the value chain of the reporting company, including both upstream and downstream emissions. Scope 1 emissions in 2020 were estimated to be 16.3 million tonnes CO2e and accounted for 99 per cent of emissions reported. All of our Scope 1 emissions (100 per cent) are reported to national regulatory bodies in the country in which we operate. This includes: Australia (National Greenhouse and Energy Reporting), Canada (Greenhouse Gas Reporting Program) and the US (EPA). Scope 2 emissions in 2020 were estimated to be 0.1 million tonnes CO2e. We estimate our Scope 3 emissions in 2020 to be in the range of six million tonnes, which is primarily attributed to our non-operating joint venture interests.

The following are our GHG emissions broken down by business segment, by Scope 1 and 2 and by country in million tonnes CO2e. In our business segment breakdown Hydro, Wind & Solar, Corporate and Energy Marketing are shown as 0.0 in million tonnes, but do have minor GHG emissions.

Year ended Dec. 31 2020 2019 2018
Hydro 0.0 0.0 0.0
Wind & Solar 0.0 0.0 0.0
North American Gas 1.5 1.5 1.4
Australia Gas 1.1 1.0 1.0
Alberta Thermal 7.9 10.1 12.3
Centralia 5.9 8.0 6.1
Corporate and Energy Marketing 0.0 0.0 0.0
Total GHG emissions 16.4 20.6 20.8





TRANSALTA CORPORATION M95

Management’s Discussion and Analysis

Year ended Dec. 31 2020 2019 2018
Scope 1 16.3 20.4 20.6
Scope 2 0.1 0.2 0.2
Total GHG emissions 16.4 20.6 20.8



Year ended Dec. 31 2020 2019 2018
Australia 1.1 1.0 1.0
Canada 9.4 11.6 13.7
United States 5.9 8.0 6.1
Total GHG emissions 16.4 20.6 20.8

All of our reported 2020 and historical GHG emissions are verified by Ernst & Young LLP to a level of limited assurance. An assurance statement can be found in the back of this Integrated Annual Report. In addition, GHG emissions are verified to a level of reasonable assurance in locations where we operate within a carbon regulatory framework. In Alberta, we verify GHG emissions through the TIER program and, as a result, 51 per cent of our total Scope 1 emissions are also verified to a level of reasonable assurance. Our GHG emissions are calculated using a number of different methodologies depending on the technologies available at our facilities.

We have a target to reduce 60 per cent or 19.7 million tonnes of our GHG emissions by 2030 over 2015 levels. In 2021, we set a new target to be carbon neutral by 2050. Our actions to reduce GHG emissions are aligned with the UN's SDGs, specifically "Goal 13: Climate Action." By 2030, we expect to have reduced close to 30 million tonnes over 2005 levels.

The following highlights our GHG emission reductions since 2005 and our targeted emissions in 2030 (in line with our GHG target). The actual GHG emissions for the Corporation in 2030 will vary from that presented below depending on, among other things, the growth of the Corporation, including its on-site generation business.

Year ended Dec. 31 2030 (forecast) 2020 2005
Total GHG emissions (million tonnes CO2e)
12.5 16.4 41.9


In 2020, TransAlta increased its scoring on the CDP Climate Change investor request. Our overall score was an A-, indicating that we are implementing current best practices. This ranks the Corporation among industry leaders on climate change management and places us as ahead of most companies in North America. The average CDP score for our peers was a B and the average score for reporting companies in North America was a D.





TRANSALTA CORPORATION M96

Management’s Discussion and Analysis
Healthy, Safe, Diverse and Engaged Workplace: Human Capital Management
Engaging our workforce, developing our employees, creating a diverse and inclusive work environment and minimizing safety incidents are the keys to human capital value creation at TransAlta and our most material areas for management.

As of Dec. 31, 2020, we had 1,476 (2019 - 1,543) active employees. This number has decreased by four per cent from 2019 levels, following a reduction in positions in our coal fleet as part of our conversion to gas transition.

With approximately 41 per cent of our employees being unionized, we strive to maintain open and positive relationships with union representatives and regularly meet to exchange information, listen to concerns and share ideas that further our mutual objectives. Collective bargaining is conducted in good faith, and we respect the rights of employees to participate in collective bargaining.

Organizational Culture and Structure
Our employees are central to value creation. Our corporate culture has evolved and adapted throughout our more than 109-year heritage. Our core values are safety, innovation, sustainability, respect and integrity. These five core values help provide clarity for our employees and guide our behaviour and decision-making. They also provide a foundation for leadership, collaboration, community support, personal growth and work/life balance. Through corporate initiatives and support throughout all levels of leadership, we encourage our employees to maximize their potential.

Our six-level organizational structure helps facilitate effective pace and decision-making in our organization. Our business operates as a business-centric model, with Alberta Thermal, Centralia, North American Gas, Australian Gas, Wind and Solar, and Hydro as our six generating segments. In addition, our Energy Marketing segment optimizes our asset fleet and trades electricity and other energy commodities. Our Corporate segment, including finance, legal, administrative, business development and investor relations functions, oversees our business and provides strategic alignment. The Corporation also includes a Shared Services division that oversees our information technology, supply chain, human resources, engineering and accounting functions. The consolidation and centralization of these functions has allowed us to streamline, standardize and, where appropriate, automate these functions while reducing costs and improving service delivery across the organization. Our operations portfolio is run by a single leadership team, which provides operational and financial synergies, enhancing our competitiveness.

TransAlta is committed to improving its internal work environment and the way that employees perceive their work and the Corporation. We track a broad number of factors to provide us insight into our progress and we use a third party to assist us in tracking our progress on an annual basis. We have made continual and notable improvements year-over-year and continue to target further improvements as we look forward.

Health and Safety
The safety of our people, communities and the environment is one of our core values. At TransAlta, we operate large and often complex facilities. The environments in which we work, including Canadian winters and the Australian outback, can add additional challenges to keeping our employees, contractors and visitors safe. Each year we invest significant resources into improving our safety performance, including positively enhancing our safety culture. At meetings of more than four people, we have a practice of starting the meeting with a “safety moment,” which helps share key safety learnings across the Corporation.

TransAlta's management systems underpin the delivery of safe, reliable and competitive electricity to our customers and partners. Our Total Safety Management System is a combination of recognized best practices in process safety, risk management, asset management, occupational health, safety and environmental management. Since expanding our Occupational Health and Safety program in 2015 to encompass Total Safety, we have transitioned from the development and implementation of this framework into continuous improvement, always striving to achieve our Target Zero vision to operate our business with zero unexpected asset failures and zero environmental, health and safety incidents.

In 2020, we continued to progress our safety culture transformation despite an unprecedented and extraordinary challenge due to COVID-19. Behavioural safety training tools and capabilities have been reinforced through leadership peer board sessions and effective safety interactions. We also focused on the development of tools and training to support hazard identification, including updates to Field Level Hazard Assessment cards and a fleet-wide app for Occupation Hazard Assessment. Emphasis on safety interactions, interventions and positive observations for both employees and contractors was also a particular focus in 2020.





TRANSALTA CORPORATION M97

Management’s Discussion and Analysis
In 2020, we achieved a Total Injury Frequency ("TIF") rate of 1.67 compared to 1.12 in 2019. TIF tracks the total number of injuries, including minor first aids, relative to exposure hours worked. The increase in 2020 was a result of increased first aids across our fleet. This may have been due to an increase in contractor presence during projects/construction at our Sundance and Windrise facilities. The COVID-19 pandemic may also have had an impact with a potential for distraction while our workers adjusted to changes in their professional and personal lives.

In addition to TIF, we are tracking Total Recordable Injury Frequency ("TRIF"). TRIF tracks the number of more serious injuries, and excludes minor first aids, relative to exposure hours worked. TRIF provides us with the opportunity to target and monitor our significant injuries. It is also an industry-recognized safety metric and allows us to compare and benchmark our safety performance to that of our peers. Our TRIF result for 2020 was 0.81 compared to 0.73 in 2019. Minor adjustments were made to historical exposure hours, but our reported injuries, TIF and TRIF reporting did not change.

Safety at TransAlta (employees and contractors) 2020 2019 2018
Lost-time injuries 5 5 1
Medical aids 9 7 12
Restricted work injuries 2 3 12
First aids 17 8 23
Total TIF injuries 33 23 48
Exposure hours 3,948,000  4,108,000  5,014,000 
Total Injury Frequency (TIF) 1.67 1.12 1.91
Total Recordable Injury Frequency (TRIF) 0.81 0.73 1.00

TRIF is our key safety metric for 2021. TRIF includes restricted work, medical aid and lost-time injuries. We are moving away from reporting TIF, which consists of the same injuries as TRIF, but also includes first aid incidents. We will continue to focus on overall injury reduction (including first aids) through our Significant Incident Communication process. This process ensures that incidents with high potential for loss are thoroughly investigated and lessons learned are shared across the fleet. Reporting TRIF also aligns with the SASB reporting framework.

In addition to TRIF, we have also introduced Total Safety Report Frequency as a key safety metric in 2021. This is a leading indicator that measures Total Safety Reports (hazard, near miss and positive observations) per worker per year. Total Safety Reports are proactive in nature and demonstrate the actions we are taking to identify and prevent an injury or loss from occurring. In this way, we not only manage incidents if they do occur, but methodically work to prevent them from arising in the first place.

As a demonstration to TransAlta’s commitment to safety, SunHills Mining LP was awarded the Safety Excellence Award from the Alberta Mine Safety Association. This award is for best safety performance of all Alberta mines under one million workforce hours based on 2019 performance.

Equity, Diversity and Inclusion
TransAlta’s commitment and focus on excellence in equity, diversity and inclusion (“ED&I”) is found in our workplace amongst our co-workers who at all levels advocate for the core values of equity and inclusion. We believe a strong focus on ED&I will drive performance in innovation, improve service to our customers and positively impact the communities that we all live in.

In 2020, TransAlta formed a ED&I Council and empowered the Council to develop a long-term ED&I strategy. TransAlta also committed to a ED&I Pledge approved by our Board and executive team. The Pledge embodies our vision to strengthen our ED&I practices, and sets out four goals: (a) making our workplaces trusting places by having complex, and sometimes difficult, conversations about ED&I; (b) expanding education in ED&I; (c) creating best practices on meaningful ED&I initiatives; and (d) driving accountability on our ED&I initiatives by transparently reporting to our co-workers, executive team and Board.

In 2020, we also expanded our ED&I training, offering employees a platform for a variety of training, education and awareness on ED&I such as webinars, employee engagement sessions, articles, videos and blogs. Moreover, we obtained diversity and inclusion data from our inaugural ED&I Census, delivered by a third party, which was sent to all employees to understand our demographics and our experiences in the workplace. These census results will inform ED&I action plans for 2021 and beyond.





TRANSALTA CORPORATION M98

Management’s Discussion and Analysis
In early 2021, we received market recognition for our ED&I efforts and were certified by Diversio for our commitment to measuring, tracking and improving ED&I. The Diversio assessment and certification process has set the global standard for inclusion and being certified means that we have measured and set targets to increase diversity, we regularly collect data on our co-workers’ experiences to identify bias and barriers faced by underrepresented groups, and we have implemented programs and policies designed to unlock specific challenges while tracking results.

Gender Diversity
A number of case studies have highlighted the link between gender diversity and additional business value. TransAlta is an active supporter of gender diversity as a driver for value, but also as an ethical business practice. Our commitment to gender diversity in our business is evidenced by our female participation rates on both our executive team and Board. As of Dec. 31, 2020, women made up 43 per cent of our executive officer team and 45 per cent of our Board. These percentages are higher than our peers in Canada. Industry research highlights that the percentage of Board seats held by women from all disclosing Canadian TSX-listed companies in Canada is 21.5 per cent and the average percentage of women on executive teams is 16.8 per cent.

To further support female advancement, we have set targets to: (a) maintain equal pay for women in equivalent roles, (b) achieve 50 per cent representation of women on our Board by 2030 and (c) achieve 40 per cent representation of women among all employees by 2030. Our goal to achieve 40 per cent women across the entire workforce by 2030 is ambitious considering the majority of the operational roles are currently male dominated. Currently, women employees represent 21 per cent of all employees.

TransAlta was once again added to the Bloomberg Gender-Equality Index in 2021. Inclusion in the index recognizes our comprehensive investment in workplace gender equality and our commitment to driving progress by developing inclusive policies and disclosing data using Bloomberg’s gender reporting framework. In 2020, TransAlta was also recognized on the Globe and Mail’s Women Lead Here inaugural survey and was included as an honoree for executive gender diversity in Canada.

Employee Retention & Recognition
Employee Retirement Savings Programs
TransAlta is an attractive employer in all three countries in which we operate. We provide compensation to our employees at levels that are competitive in relation to their respective location. We strive to be an employer of choice through our total rewards programs, which include various incentive plans designed to align performance with our annual and longer-term targets, as determined annually by the Board.

Retirement savings plans are an example of rewards we provide. We have registered pension and savings plans in Canada and the US. The plans cover substantially all employees of the Corporation, its domestic subsidiaries and specific named employees working internationally. These plans have defined benefit (“DB”) and defined contribution (“DC”) options, and in Canada there is an additional non-registered supplemental pension plan (“SPP”) for members whose annual earnings exceed the Canadian income tax limit. The DB SPP was closed as of Dec. 31, 2015, and a new DC SPP commenced for executive members hired after Jan. 1, 2016. The Corporation's executive officers as of Dec. 31, 2015, were grandfathered in the DB SPP.

The Canadian and US DB pension plans are closed to new entrants, with the exception of the Highvale mine (SunHills) pension plan acquired in 2013. The US DB pension plan was frozen effective Dec. 31, 2010. The plans are funded by the Corporation in accordance with governing regulations and actuarial valuations. In addition, in Canada, we provide some optional plans for employees to enhance their financial wellness and retirement savings, with group RRSP and TFSA plans.

In Australia, employees can nominate a superannuation fund for superannuation contributions. The Australian superannuation scheme is compulsory for employers with contributions required at a rate set by the government.

Other Employee Benefit Programs
TransAlta provides competitive benefit programs for most of our employees (options are dependent on the countries in which we operate). We also provide benefit programs based on negotiated union agreements in certain locations. Our flexible benefit plans provide employees and their families with choices of coverage including, among others, extended health, dental, vision, life insurance, critical illness, accident, disability and a health spending account.

In 2020, we added Telehealth benefits that include employee access to virtual doctor visits, remote chronic condition management, and online or telephone access to medical support and information. We provide other health and dental benefits for disabled members and retired members, typically up to the age of 65. The Canadian retiree benefits plan was closed for all new hired employees as of March 1, 2017.





TRANSALTA CORPORATION M99

Management’s Discussion and Analysis
In 2020, the BOLT Awards were launched to provide timely rewards and recognition for work on transformational initiatives and project work, as well as to recognize above-and-beyond performance. The BOLT Awards have acted as an umbrella program whereby individual performance can be recognized in one place, frequently and in a consistent manner.

On an annual basis, TransAlta recognizes our top achievements through the President’s Awards. During 2020, we added an additional award for Leadership Excellence. This award recognizes a people leader who consistently demonstrates TransAlta’s values in their decision-making and actions, has a bias to action that achieves key business outcomes and is recognized by their team as a trusted advisor and mentor.

TransAlta’s focus on organizational health resulted in top quartile results in 2020 benchmarked against 823 surveys and a total of 2.8 million respondents. This was accomplished by identifying eight priority practices and incorporating those practices into all facets of the organization.

Lastly, a Remote Work Program was developed in 2020 to provide employees with alternative permanent remote work options. This program allowed eligible employees to choose between working from home or within a TransAlta location.

Talent and Employee Development
Talent and employee development is viewed as a key pillar of organizational health. Investing in our employee development enhances employees’ skills and improves productivity and engagement. This contributes to a strong corporate culture that provides value for TransAlta.

In 2020, we continued with the Leadership Development Program that was launched the previous year. This program provided 143 leaders or future leaders with fundamental leadership skills and tools. Training programs focused on a variety of leadership competencies for participants with various years of management experience. In December 2019, we launched a Professional Development Library that contains over 600 articles on professional development and leadership and is updated on a monthly basis. We created this library with a Master Executive Coach and it is accessible to all employees. Since the creation of the library, we have had over 5,000 hits and we have over 375 regular users.

During 2020, TransAlta partnered with BetterUp, a consultancy providing professional coaching, to provide 1:1 coaching for 30 leaders. This was offered to people leaders as part of the Leadership Development initiative. BetterUp coaching is tailored to the individual’s needs to allow them to work with their personal coach on areas that are important for them. Over the summer of 2020, 80 leaders were offered the Franklin Covey All Access Pass — this resource was packaged with our 7 Habits of Highly Effective People training and expanded on the training with articles, videos and activities. The Senior Leadership also completed The Good Fight training, which focused on reframing perceptions on conflict and how to stop conflict avoidance. Remote work training was offered to all leaders and employees to help them work effectively in a remote setting.

During 2020, Alberta Merchant Market Training was developed internally by stakeholders in Operations, and Trading and Marketing. This training consisted of three modules, including power market fundamentals, the Alberta power market, generation portfolio and portfolio optimization, among other topics. This training was available to all employees to enhance their knowledge of the Alberta merchant market.

Partnering with Blue Ocean Brain, a micro-learning consultancy, TransAlta implemented compulsory ED&I training for all employees. This training included five modules on topics such as unconscious bias and allyship. In addition, Blue Ocean Brain was also engaged to provide 200 leaders with access to their learning library in 2021.

We launched the New Grad Program in 2020 with new graduates rotating through Corporate Finance, Trade Finance and HR. Each graduate participates in three rotations, each lasting eight months. This program is intended to develop knowledge and skills through work experience within multiple business units.

During 2020, TransAlta has had 17 intern and co-op placements with students in various areas of study including business, communications, finance and engineering. To assist in subsidizing the internship and co-op programs, TransAlta continues to partner with Electricity Human Resources Canada to access government funding. In 2020, TransAlta received wage subsidies of $120,000. In 2020, TransAlta also participated in the Canada Alberta Job Grant, which reimburses employers two-thirds of the cost of approved external training. TransAlta is currently approved to receive $56,000 to cover approved training costs.






TRANSALTA CORPORATION M100

Management’s Discussion and Analysis
Positive Indigenous, Stakeholder and Customer Relationships:
Social and Relationship Capital Management
We strive to create shared value for our stakeholders through social and relationship value creation at TransAlta. The most material impacts on our social and relationship performance are public health and safety, anti-competitive behaviour and fostering positive relationships with Indigenous neighbours, communities, stakeholders, governments, industry and landowners in the areas where we operate.

Human Rights
We operate in Canada, the US and Australia. All of these countries have high human rights standards. TransAlta respects the fundamental human rights of all its employees, contractors, suppliers, partners, Indigenous partners and other stakeholders. We abide by human rights legislation in all the jurisdictions in which we operate. We have a zero tolerance approach to discrimination based on age, disability, gender, race, religion, colour, national origin, political affiliation or veteran’s status or any other prohibited ground as defined by human rights legislation in the jurisdictions in which we operate. We afford equal opportunities for men and women, support the right to freedom of association and the right to organize unions and bargain collectively. We do not conduct operational human rights reviews or impact assessments, but we do continue to operate aligned with the highest ethical standards, such as ISO 14001 and ISO 18001.

Indigenous Relationships and Partnerships
At TransAlta, we value our relationships and partnerships with stakeholders and our Indigenous partners. Our Indigenous Relations team focuses on community engagement, employment, economic development and community investment. We ensure that TransAlta’s principles for engagement are upheld and that the Corporation fulfils its commitments to Indigenous communities. Efforts are focused on building and maintaining solid relationships and establishing strong communication channels that enable TransAlta to share information regarding operations and growth initiatives, gather feedback to inform project planning and understand priorities and interests from communities to better address concerns.

Methods of engagement include:

▪Relationship building through regular communication and in-person meetings with representatives at various levels within Indigenous community organizations;
▪Hosting company-community activities that share both business information and cultural lessons;
▪Maintaining consistent communications with each community and following appropriate community protocols and procedures;
▪Participating in community events such as pow wows and blessing ceremonies; and
▪Providing both monetary and in-kind sponsorships for community initiatives.

TransAlta is proactive with initiating engagement early on in project development to allow concerns to be identified promptly and addressed, minimizing potential project delays. We conduct consultation primarily during project development and decommissioning and maintain engaged communication throughout the operation phase. We work with communities to build a relationship with a foundation of ongoing communication and mutual respect.

COVID-19 health measures posed challenges to how we engaged with Indigenous communities throughout 2020. However, we continued to have regular dialogue by telephone, email, video conference and whenever possible, in small group meetings while adhering to government health protocols. Our normal participation in Indigenous community events such as pow wows, blessing ceremonies, and school or recreational activities was not possible as social gatherings were not permitted during the pandemic. In response, our Indigenous Relations team determined it was important to reallocate funding for social events to support Indigenous communities and their expressed needs.

Support from TransAlta for Indigenous communities in response to the pandemic included the:

▪Purchase and distribution of 400 school backpacks filled with grade-specific school supplies delivered to First Nation schools in Alberta to help alleviate pressures on household and community resources;
▪Purchase of more than 200 Christmas gifts for school students at Mother Earth’s Children’s Charter School and Wihnemne School on Paul First Nation;
▪Purchase of Christmas gift cards for Elders per requests from Piikani and Siksika Nations; and
▪Funding for the purchase of COVID-19 testing equipment for the Alexis Nakota Sioux Nation.








TRANSALTA CORPORATION M101

Management’s Discussion and Analysis
Support for Indigenous Youth, Education and Employment
TransAlta recognizes the importance of investing in Indigenous students and our financial support helps students complete their education, become self-sufficient and give back to their communities. We are keen to help young Indigenous students reach their full potential and achieve their dreams. We also believe in providing financial support to Indigenous primary school students, helping to instill a passion for lifelong learning. In 2020, TransAlta provided more than $340,000 to support Indigenous youth, education and employment programs across Canada.

Highlights include:

▪Entered into an agreement with Mount Royal University Foundation in support of the Indigenous Housing Renovation Fund, which will feature an Indigenous family tipi in an outdoor space dedicated to Indigenous students and supporting Indigenous cultural programming;
▪Continued our partnership with Indspire, Canada’s national Indigenous registered charity, and through this program, 10 bursaries of $3,000 each were given to recipients from the following communities: Ermineskin Cree Nation, Paul First Nation, Sunchild First Nation, Piikani Nation and Aamjiwnaang First Nation;
▪Continued our support of Indigenous students with the Southern Alberta Institute of Technology ("SAIT") Gap program. This program provides critical financial support needed for aspiring Indigenous students who require high school upgrading in order to qualify for a trade program where there is a "gap" in available funding;
▪In partnership with the United Way of Calgary & Area, designated funding to the Diamond Willow Youth Lodge, a safe place for Calgary Indigenous youth to connect with peers and participate in a variety of programs that promote health and wellness, education and employment preparation;
▪Provided funding to the Lac Ste. Anne Métis Capacity Fund to support the training needs of community members including youth and women, and the provision of personal protective equipment for individuals entering the workforce; and
▪Continued our ongoing partnership with the Banff Centre for Arts and Creativity with scholarship funding allocated to Indigenous community members to participate in Indigenous Leadership programming.

Cultural Awareness for TransAlta Employees
Our Indigenous Relations team led two cultural awareness initiatives for TransAlta employees in 2020. The first program was launched in June in recognition of National Indigenous History Month and National Indigenous Peoples Day (June 21). TransAlta hosted a virtual Lunch and Learn session featuring an interview with a community member from Paul First Nation and TransAlta’s senior advisor for Indigenous & Stakeholder Relations, moderated by our Chief Legal, Regulatory, & External Affairs Officer. On Sept. 30, 2020, in recognition of Orange Shirt Day, TransAlta’s Executive Leadership Team encouraged all employees to wear orange to promote awareness in Canada about the Indian residential school system and the impact it has had on Indigenous communities for over a century. In addition, a comprehensive educational program was designed and delivered to Operations leaders providing information on Indigenous history, culture, consultation requirements and TransAlta’s relationship protocols and practices.

In 2021, we adopted a new sustainability target stating that all employees should complete Indigenous cultural awareness training by the end of 2023. We believe education is a key ingredient to ensure respectful and strong relationships into the future.

Stakeholder Relationships
Fostering relationships with our stakeholders is important to TransAlta. Driven by our values, we seek to maximize value creation for our stakeholders and the Corporation. We take a proactive approach to building relationships and understanding the impacts our business may have on local stakeholders.

TransAlta Stakeholders
To act in the best interests of the Corporation and to optimize the balance between financial, environmental and social value for both our stakeholders and TransAlta, we seek to:

▪Engage regularly with stakeholders about our operations, growth prospects and future developments;
▪Consider feedback and make changes to project designs and plans to resolve and/or accommodate concerns expressed by our stakeholders; and
▪Respond in a timely and professional manner to stakeholder inquiries and concerns and work diligently to resolve issues or complaints.

Our stakeholders are identified through stakeholder mapping exercises conducted for each facility and prospective project development or acquisition. Through decades of stakeholder relations in the areas of our facilities, we have developed a strong knowledge of who our stakeholders are and have gained understanding of our stakeholders' issues and concerns.





TRANSALTA CORPORATION M102

Management’s Discussion and Analysis
Our principal stakeholder groups are listed in the following table.

TransAlta Stakeholders
Non-governmental organizations (NGOs) Community associations and organizations Connecting transmission facility operators
Regulators Industry organizations Communities
Charitable organizations/Non-profit Standards organizations Retirees
All levels of government Media Residents/Landowners
Suppliers Business partners Investor organizations
Contractors Unions/Labour organizations Financial institutions
Government agencies Forest associations/Industry Mineral rights owners
System operators Oil & gas associations/Industry Railroad owners
Customers Think tanks Utility owners
Municipalities Academics


Engagement Framework
Our stakeholder engagement framework is modelled after and closely tied to the stakeholder engagement aspect of ISO 14001, which is an internationally recognized environmental management standard. This framework is a streamlined corporate-wide approach to ensure that engagement and relationship-building practices are consistent across TransAlta’s locations and types of work. Although we no longer certify under ISO 14001, we continue to operate within its established best practices.

Methods of Engagement
In order to run our business successfully, we maintain open communication channels with stakeholders. We commit to timely and professional resolution using values-based dialogue. We work internally and with each stakeholder to identify how to mitigate further issues.

Examples of our methods of engagement are listed in the following table.

Information & communication Dialogue & consultation Relationship building
Open houses, town halls and public information sessions In-person meetings with local groups and communities Community advisory bodies
Newsletters, telephone conversations, emails and letters Meetings with individual stakeholders (e.g., landowners and residents) Capacity agreements
Websites Targeted audience sessions Sponsorships and donations
Social media postings Tours of our facilities and sites Hosting events


A key focus of our work is to support business growth through proactive engagement with stakeholders in our geographic operating areas in Australia, Canada and the US to develop and maintain relationships, assess needs and fit, and seek out collaborative and sustainable value creation opportunities. This helps ensure any stakeholder concerns are identified and can be addressed early in the development process, thereby minimizing project delays. We conduct consultation primarily during project development and decommissioning and maintain engaged communication throughout operations. For example, we implemented our stakeholder engagement program with stakeholders and Indigenous groups in connection with the proposed repowering at the Sundance and Keephills facilities. We filed our regulatory applications in December 2019, and our stakeholder engagement program will continue for the entire life cycle of the facilities.

Engagement Tracking and Reporting
Our Stakeholder and Indigenous Relations tracking program functions as an enterprise-wide communication record-keeping tool managed by our Stakeholder and Indigenous Relations team. This capacity fulfils our requirements for consultation with stakeholders and Indigenous groups alike, and is capable of producing regulatory reports as proof of engagement and consultation efforts. The tool can store email conversations, documents and voicemail messages related to any project, event or issue, and display them in a report format. It can also produce an array of statistical reports showing frequency and volume of engagement based on project, stakeholder, stakeholder group or keywords. This tracking program decreases the time and cost required to submit proof of engagement to government agencies.




TRANSALTA CORPORATION M103

Management’s Discussion and Analysis

Engagement and Board Communication
The Board believes that it is important to have constructive engagement with its shareholders and other stakeholders and has established means for the shareholders of the Corporation and other stakeholders to communicate with the Board. For example, employees and other stakeholders may communicate with the Board through the AFRC by writing to the AFRC or by making submissions via the Corporation’s toll-free telephone or online Ethic Helpline (please refer to the "Governance and Risk Management - Risk Controls - Whistleblower System" section in this MD&A for more details). Shareholders are also invited to communicate directly with the Board under the Corporation’s Shareholder Engagement Policy, which outlines the Corporation’s approach to proactive director-shareholder engagement at and between the Corporation’s annual shareholders meetings. Under the Shareholder Engagement Policy, shareholders can submit questions or inquiries to the Board, to which the Corporation will respond. A copy of the Shareholder Engagement Policy is available on our website at www.transalta.com. Shareholders and other stakeholders may, at their option, communicate with the Board on an anonymous basis. In addition, the Board has adopted an annual non-binding advisory vote on the Corporation’s approach to executive compensation (say-on-pay). The Corporation is committed to ensuring continued good relations and communications with its shareholders and other stakeholders and regularly evaluates its practices in light of any new governance initiatives or developments in order to maintain sound corporate governance practices.

Throughout 2020, representatives of the Board engaged extensively with the Corporation's significant shareholders. Specifically, since Jan. 1, 2020, the Board has met with 11 shareholders representing approximately 37 per cent of the Corporation’s total issued and outstanding common shares.

Supply Chain – Sustainable Sourcing
We continue to seek solutions to advance supply chain sustainability. In 2020, we worked to optimize our global supply chain management operations by initiating the centralization and standardization of practices across our global operations. As we explore major projects, we assess vendors both at the evaluation stage and as part of information requests on such elements as safe work practices, environmental practices and Indigenous spend. This means, for example, getting information on:

▪Estimated value of services that will be procured though local Indigenous businesses;
▪Estimated number of local Indigenous persons that will be employed;
▪Understanding overall community spend and engagement; and
▪Understanding the state of community relations through interview processes and stakeholder work.

In 2019, the Board adopted a Supplier Code of Conduct that applies to all vendors and suppliers of TransAlta. Under this code, suppliers of goods and services to TransAlta are required to adhere to our core values, including as they pertain to health and safety, ethical business conduct and environmental leadership. The code also allows suppliers to report ethical or legal concerns via TransAlta’s Ethics Helpline.

In addition, we rolled out a Supplier Relationship and Performance Management program in 2020 with a few of our key and strategic suppliers. The goals of the program include ensuring alignment of our suppliers’ goals with those of TransAlta, streamlining communications while providing a platform to discuss how to elevate performance, creating value though access to innovative ideas and working closely with the suppliers on executing activities more cost-effectively.






TRANSALTA CORPORATION M104

Management’s Discussion and Analysis
Public Health and Safety
We seek to preserve public health and safety. It is our goal to maintain security for our employees and the peoples and communities where we operate.

We specifically look to minimize the following risks:

▪Harm to people;
▪Damage to property;
▪Operational liability; and
▪Loss of organizational reputation and integrity.

We work to prevent incidents and lower our risk by administering security controls such as restricting physical access around and into our operating facilities. The use of security technology such as surveillance cameras and electronic access is utilized to ensure the control of secure areas. Regular audits and security risk assessments are conducted to ensure continuous improvement of the Security Management Program. Our Security Management Program is focused on protection of people, property, information and reputation.

The Corporate Emergency Management Program prepares employees should an emergency incident occur. The program includes an emergency management policy and standard, which sets an expectation for employees to continuously prepare for emergencies. The program has executive sponsorship. It provides the overarching framework for each business unit to provide an Emergency Response Plan and Business Continuity Plan. We implement our Incident Command System, which is a standardized on-scene emergency and incident management system that provides an organizational structure able to respond to single or multiple incidents. Designed to aid in the management of resources during incidents, it combines facilities, equipment, personnel, procedures and communications operating within a common organizational structure. It is used as part of an all-hazards approach for incident management and is officially recognized for multi-agency response in emergency situations, however complex.

We develop strong relationships with local emergency responders. We periodically conduct multi-agency training events at our facilities. This ensures continuous improvement, familiarity with our assets and builds strong communication channels for emergency response.

Our processes designate how we communicate with stakeholders in the event of a crisis. This is managed by our Crisis Communications Team. The team has the responsibility and goal to provide a unified message on behalf of Corporation throughout the response and recovery, ensure all messaging is approved by the Incident Commander (the Chief Talent & Transformation Officer, or their designate), co-ordinate messaging with any applicable external agencies and, if necessary, deploy to an incident site.

Annual training requirements are adhered to by our employees operating at our facilities. The results are tracked, audited and presented at our annual executive review. The findings and recommendations assist in maintaining a sustainable program across the organization.

Data and Digital Asset Protection
We work hard to protect our digital assets, including our corporate data and our digital identities that give us access into line of business applications. Cybersecurity risks that work to compromise these assets include the manipulation of data integrity, system and network hacking, use of social engineering tactics through email phishing, compromise of operations and infrastructure through the use of ransomware, credential breaches, attacks introduced through unknowing third-party vendors and service providers, as a well as malware. Given the ever-evolving nature of cyberattacks, we are consistently adapting our cybersecurity program to focus on three key pillars: technology, processes and people. Each of these pillars can be reinforced independently to address specific cyber risks and threats through a comprehensive and multi-faceted program. Through this program, TransAlta continually implements measures and controls to proactively mitigate internal and external cybersecurity risks and threats posed to the organization, and to deal efficiently and effectively with threats.

Please refer to Cybersecurity Risk in the Governance and Risk Management section of this MD&A for further details.

Community Investments
In 2020, TransAlta contributed approximately $2.2 million in donations and sponsorships (2019 - $2.1 million). One of our significant community investments each year is to United Way campaigns across Canada and the US. This year, TransAlta employees, retirees, contractors and the Corporation raised over $1.3 million for the United Way. TransAlta has been supporting the United Way for over 30 years and has contributed more than $20 million dollars over that time.





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Management’s Discussion and Analysis
In 2020, we continued to focus our community investment on priority areas for TransAlta: youth and education, environmental leadership and community health and wellness. Some of our partnerships included:

▪Indspire, Canada’s national Indigenous registered charity, and through this program 10 bursaries of $3,000 each were given to recipients from the following communities: Ermineskin Cree Nation, Paul First Nation, Sunchild First Nation, Piikani Nation and Aamjiwnaang First Nation;
▪Mother Earth's Children's Charter School ("MECCS") - Located in Treaty 6 territory, near Stony Plain, Alberta, and our Alberta coal operations, MECCS has become an important part of TransAlta’s community investment program. MECCS offers education for students from Kindergarten to Grade 9 and is cited as Canada’s first and only Indigenous children’s charter school. The school was established in 2003 to help provide Indigenous students with an education based strongly on cultural context rather than a traditional western educational model. Approximately 95 per cent of MECCS students are of Indigenous ancestry, with students coming from Paul First Nation, Enoch Cree Nation, Alexis Nakota Sioux Nation, Alexander First Nation, Alberta Beach, Stony Plain and Edmonton. The student population is diverse and includes Métis, Cree, Nakota Sioux and Stoney. Beginning in 2014, TransAlta has made an annual $35,000 donation to the school. In addition, each year at Christmas, TransAlta staff purchase Christmas presents for the students. Volunteers from TransAlta travel to the school to deliver the gifts, providing both our employees and the students the opportunity to engage with each other. Due to the COVID-19 pandemic, this tradition needed to be conducted remotely. More than 200 Christmas gifts were purchased for students at Mother Earth’s Children’s Charter School and Wihnemne School on Paul First Nation;
▪The Calgary Stampede – Founded in 2017, the TransAlta Performing Arts Studio at Stampede Park continues to provide a year-round facility for the Calgary Stampede Foundation and Calgary’s youth performing arts groups to rehearse, train and celebrate the arts;
▪SAIT Gap program, which provides critical financial support needed for aspiring Indigenous students who require high school upgrading in order to qualify for a trade program where there is a "gap" in available funding;
▪TransAlta Tri-Leisure Centre - The TransAlta Tri-Leisure Centre is a sporting and recreation destination for many active and involved residents from the communities of Parkland County, Spruce Grove and Stony Plain in Alberta. At the facility, thousands of local residents and many of our employees participate in a wide range of sporting and cultural activities and join together in many community causes;
▪The Banff Centre for Arts and Creativity – We continued our ongoing partnership with the Banff Centre with scholarship funding allocated to Indigenous community members to participate in Indigenous leadership training;
▪Junior Achievement Southern Alberta – TransAlta continued to support the World of Choices program that gives students an opportunity to connect with mentors in a number of different careers. In 2020, this program was delivered online, allowing hundreds of students to connect with mentors and learn about different career opportunities;
▪Calgary Reads – TransAlta was proud to continue our support for this organization that is dedicated to improving literacy skills for children in Calgary; and
▪Energy Transition Support – On July 30, 2015, in Washington State, we announced a US$55 million community investment over 10 years to support energy efficiency, economic and community development, and education and retraining initiatives. The US$55 million community investment is part of the TransAlta Energy Transition Bill passed in 2011. This bill was an historic agreement between policymakers, environmentalists, labour leaders and TransAlta to transition away from coal in Washington State by closing the Centralia facility’s two units, one in 2020 and the other in 2025. Three funding boards were formed to invest the $55 million: the Weatherization Board ($10 million), the Economic & Community Development Board ($20 million) and the Energy Technology Board ($25 million). To date, the Weatherization Board has invested $7 million, the Economic & Community Development Board $14 million and the Energy Technology Board $9 million. Specific projects that the boards funded in 2020 include energy-efficiency projects at local fire stations and low income housing, funding to support COVID-19 personal protection equipment for local businesses and schools, and a project to deploy the first renewable hydrogen fuelling station in the Pacific Northwest, which benefits both the electricity and transportation sectors.

Customers
TransAlta serves industrial and commercial customers with power and energy services across its fleet (Australia, Canada and the US). For more information on our customer focus, please refer to page 79 of this MD&A.




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Management’s Discussion and Analysis
Technology Adoption and Innovation Focus: Manufactured Capital Management
Technology and innovation are an existing and increasing focus at TransAlta. As we navigate significant macro changes from energy transition, the impacts of climate change and decarbonization, and the continued rise of digital technology, automation and artificial intelligence, we are proactively applying technology solutions across our business. Our conversion of coal units to gas is an excellent example of utilizing useful manufactured capital or infrastructure. We also continue to adopt and apply innovative solutions to meet customer demand for power.

Innovation: Idea Generation and Project Management
Project Greenlight has been a key driver in ensuring the Corporation continues to provide year-over-year improvements in innovation. The program is focused on bottom-up innovation, which means ideas are generated by employees. Emphasizing bottom-up innovation across the Corporation has resulted in a strong culture of idea generation, where employee ideas are developed and advanced into business cases, adhering to project management best practices to ensure the delivery and success of the initiative.

Another initiative we promote is the Supplier Innovation Series, which brings in guest speakers from outside TransAlta to discuss innovation. This includes thought leaders on new technologies to discuss conceptual ideas that initiate creative thinking and suppliers that provide insight into commercial applications of evolving technologies. In 2020, the topics discussed included artificial intelligence, virtual and augmented reality, robotic welding, the connected workforce, design thinking and innovation in safety. Subsequent to each session, small employee-led workshops consolidate ideas to further flesh out and drive new Greenlight initiatives.

Key priority practices addressed by the Supplier Innovation Series:

▪Creativity and entrepreneurial thinking;
▪Bottom-up innovation;
▪Knowledge sharing; and
▪Capturing external ideas.

For further details on our investment in our workforce, please see the Talent and Employee Development section of this MD&A.

Innovation: Infrastructure Innovation
In 2015, the Government of Alberta introduced regulations designed to end coal-powered generation in the province by 2030. A number of our coal facilities had useful lives beyond 2030 and could be converted to use natural gas. We are planning to convert or repower Alberta coal units to natural gas in the 2020 to 2023 time frame. Our Sundance 6 facility has recently been converted to gas. Through our conversion to gas and the repowering of Sundance 5, our energy use, GHG emissions, air emissions, waste generation and water usage will significantly decline. Repurposing the facilities rather than decommissioning them supports the concept of reuse and aligns with the UN's SDGs, specifically "Goal 9: Industry, Innovation and Infrastructure."

Innovation: Applied Technologies
TransAlta has been at the forefront of innovation in the power-generation sector since the early 1900s when we developed hydro assets. We have been an early adopter and developer of wind technology in Canada and are now one of the largest wind generators in the country. Today we run a Wind Control Centre that monitors, to the second, every wind turbine we operate across North America. In 2015, we made our first investment in solar technology with the purchase of a 21 MW solar facility in Massachusetts and in 2020 we installed the first utility-scale battery in Alberta at our Summerview II wind facility. From 2000 to 2020, we have grown renewables capacity from approximately 900 MW to over 2,500 MW.

As we balance growth with decarbonization, we continue to seek solutions to innovate and create value for investors, society and the environment. This is evidenced by our continued execution of the accelerated conversion to gas plans, construction of the 207 MW Windrise wind project located in Alberta, and investment in the 137 MW Skookumchuck wind facility in Washington State. In 2020, we also acquired a contracted 29 MW cogeneration facility in Michigan. Cogeneration is recognized by regulatory bodies for its efficient generation of power when compared to other forms of natural gas power generation. It reduces the natural gas required by industrial processes by generating high-efficiency steam and power versus a boiler and grid supply approach. The distributed system also provides independence from the power grid and avoids the need to construct additional transmission lines.





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Management’s Discussion and Analysis
We are also investing in battery storage. TransAlta began commercial operations of Alberta’s first utility-scale lithium-ion battery storage facility, called WindCharger, on Oct. 15, 2020. This project is unique as it uses TransAlta’s existing Summerview II wind facility to charge the battery, allowing WindCharger to be a truly renewable battery energy storage system. The project uses Tesla technology and has a nameplate capacity of 10 MW with a total storage capacity of 20 MWh. TransAlta received co-funding for this project from Emissions Reduction Alberta. The potential exists for the expansion of this technology, and we are investigating the viability of battery storage at our various wind facility locations and for use in developing customer-specific energy supply solutions.

Our teams continuously explore the use of applied or new technologies to find solutions to expand or adapt our fleet in an ever-changing world. This helps protect our shareholder value and maintain delivery of reliable and affordable electricity. We know that new technologies will emerge over the next number of years as the industry continues to drive towards lower emissions while maintaining a reliable and affordable product for customers. Our teams continue to be involved in assessing emerging technologies such as hydrogen and carbon capture and storage as well as the development of bespoke behind-the-fence solutions for customers using a combination of technologies such as renewables and batteries. The following are further examples of how we have developed innovative solutions to optimize and maximize value from our fleet:

Operations Diagnostic Centre
TransAlta has run its Operations Diagnostic Centre (“ODC”) since 2008. The ODC monitors coal-fired, gas-fired and wind generating assets across Australia, Canada and the US. A centralized team of engineers and operations specialists remotely monitors our power facilities for emerging equipment reliability and performance issues. ODC staff are trained in the development and use of specialized equipment monitoring software and they apply their experience to power facility operations. If an equipment issue is detected, the ODC notifies facility operations to investigate and remedy the issue before there is an impact to operations. This support is critical to reliability and performance of our operations. By way of example, if a wind turbine starts to underperform compared to others, our operation team is notified and will work to investigate and remedy the issue. The monitoring, analysis and diagnostics completed by the ODC are focused on early identification of equipment issues based on longer-term trend analysis and complements day-to-day facility operations.

Data & Innovation
TransAlta created the Data & Innovation team in 2019 to modernize its data infrastructure to take advantage of new opportunities in analytics and artificial intelligence. The Data & Innovation team is cross-functional, composed of data architects, data scientists, data analysts, software developers, engineers, project managers, and financial and systems analysts. The team focuses its efforts on the delivery and enhancement of TransAlta’s Modern Data Architecture, the rapid delivery of data-driven applications, the design and implementation of machine learning and artificial intelligence models and the advancement of process automation through the Robotic Process Automation Centre of Excellence. In 2020, the Data & Innovation team worked with partners across the business to create new tools and processes that improve our financial position and return capacity to our people. A few of the highlights from this work include:

▪GenOS, an innovative new platform where data is used to drive the actions of our assets and the decisions of our people, piloted with Wind Operations. This pilot project combines data and analytics from a variety of sources into one central web application and creates new opportunities to drive further adoption of automation across our operations; and
▪Industry partnership with AltaML Applied AI Lab, a groundbreaking initiative that focuses on building and expanding local talent while improving our business through the application of machine learning and artificial intelligence.





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Management’s Discussion and Analysis
2020 Sustainability Targets Performance
Sustainability Targets and Results
 
Our sustainability goals and targets support the long-term success of our business. Goals and targets are established to manage key or emerging material sustainability issues and to improve our performance in these areas.

We establish our goals and targets with reference to the UN's SDGs and the Future-Fit Business Benchmark. This focus ensures our goals and targets are meaningful in the broader context of solving societal problems; support the ambition of achieving a more sustainable, safe and just planet in the future; and ensure TransAlta's competitiveness, both today and in the future.

ESG Alignment: Environment
TransAlta Sustainability Goal TransAlta Sustainability Target Results Comments
Minimize fleet-wide environmental incidents Keep annual significant environmental incidents below two and keep environmental regulatory non-compliance incidents below four Not achieved
In 2020, we recorded six significant environmental incidents. None of these incidents was large in terms of magnitude or impact, which is consistent with past performance and suggests these types of incidents are not a major risk for the Corporation or the environment. For 2021, we are removing our target for environmental incidents but continuing to report on these events in the Incidents and Spills section of the MD&A. We are making this change to focus our targets on environmental areas that are more material for the Corporation.
Reclaim land utilized for mining By 2040, complete full reclamation of our Centralia coal mine in Washington State On track Reclamation work at our Centralia and Highvale mines was paused in 2020 due to the COVID-19 pandemic.
Reduce air emissions
By 2030, achieve a 95 per cent reduction of SO2 emissions
On track
We are well on track to achieve our target of 95 per cent emission reductions of SO2 by 2030. Since 2005, we have reduced SO2 emissions by 83 per cent. In 2020, we reduced SO2 emissions by approximately 4,000 tonnes over 2019 levels.
By 2030, achieve a 50 per cent reduction of NOx emissions below 2005 levels from TransAlta coal facilities
Achieved
We have achieved our target of 50 per cent emission reductions of NOx by 2030 ahead of schedule. Since 2005, we have reduced NOx emissions by 68 per cent. In 2020, we reduced approximately 5,000 tonnes of NOx emissions over 2019 levels.
Reduce GHG emissions By 2030, achieve company-wide GHG reductions of 60 per cent below 2015 levels, in line with a commitment to the UN SDGs and prevention of 2ºC of global warming On track
We are well on track to achieve our target of 60 per cent GHG emissions reductions by 2030. Since 2015, we have reduced GHG emissions by 80 per cent. In 2020, we reduced approximately 4.2 million tonnes of CO2e over 2019 levels.
ESG Alignment: Social
TransAlta Sustainability Goal TransAlta Sustainability Target Results Comments
Reduce safety incidents Achieve a Total Injury Frequency rate below 1.17 Not achieved
In 2020, we achieved a TIF of 1.67 compared to 1.12 in 2019. The increase in 2020 was a result of increased first aids across our fleet. This may have been due to an increase in contractor presence during projects and construction at our Sundance and Windrise facilities. There was also potentially an effect from adjustments that all of our workforce had to make due to the COVID-19 pandemic.




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Management’s Discussion and Analysis
Support prosperous Indigenous communities Support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities Achieved Support in 2020 represented a total value of $340,000 and provided bursaries through a partnership with Indspire; funded academic upgrading programs through SAIT; supported an Indigenous Leadership Program; and maintained communication on employment opportunities through various mediums to support different access options for Indigenous communities.
ESG Alignment: Governance
TransAlta Sustainability Goal TransAlta Sustainability Target Results Comments
Strengthen gender equality Achieve a quota of 50 per cent female representation on the Board by 2030 On track As of Dec. 31, 2020, women made up 45 per cent of our Board.
Achieve at least 40 per cent female employment among all employees of the Corporation by 2030 On track As of Dec. 31, 2020, women made up 21 per cent of all employees, an increase over 2019 levels (20 per cent).
Maintain equal pay for women in equivalent roles as men Achieved Equal pay for women in the Corporation was maintained in 2020.
Demonstrate leadership on ESG reporting within financial disclosures Maintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworks Achieved In 2020, we increased our alignment with the SASB sustainability reporting framework and increased our CDP Climate Change Scoring to an A-.
ESG Alignment: Environment and Social
TransAlta Sustainability Goal TransAlta Sustainability Target Results Comments
Leading clean power company by 2025 By the end of 2025, convert coal facilities to gas through boiler conversions and combined-cycle repowering On track Our Sundance 6 coal facility began conversion to gas in 2020 and was completed in early 2021.
No further coal generation by the end of 2025 and 100 per cent of our owned net generation capacity will be from clean electricity (renewables and gas) On track In 2020, we retired our Sundance 3 and Centralia 1 coal facilities, converted our Sundance 6 coal facility to gas and announced the acceleration of our Highvale mine closure to the end of 2021.
Develop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductions Achieved In 2020, the Corporation purchased a 49 per cent interest in the 137 MW Skookumchuck wind project and continued development of our 207 MW Windrise wind project. Our 10 MW WindCharger battery storage project also began commercial operations.






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Management’s Discussion and Analysis
2021+ Sustainability Targets
 
Our 2021 and longer-term sustainability targets support the long-term success of our business. The following targets highlight our future ESG value proposition and paint a portrait of how the Corporation will continue to be positioned as an ESG leader in the future. Goals and targets are established to manage key and emerging material sustainability issues and to improve our performance in these areas. We continue to evolve and adapt our goals and targets to focus on anticipated key areas of sustainability materiality.

We establish our goals and targets with reference to the UN's SDGs and the Future-Fit Business Benchmark. This focus ensures our goals and targets are meaningful in the broader context of solving societal problems; support the ambition of achieving a more sustainable, safe and just planet in the future; and ensure TransAlta's competitiveness both today and in the future.

Targets are outlined below:

ESG Alignment: Environment
TransAlta Sustainability Goal TransAlta Sustainability Target Alignment with UN's SDG Target or Future-Fit Business Benchmark
Reclaim land utilized for mining By 2040, complete full reclamation of our Centralia coal mine in Washington State Future-Fit Business Benchmark - "Positive Pursuits 13: Ecosystems are restored"
By 2046, complete full reclamation of our Highvale coal mine in Alberta Future-Fit Business Benchmark - "Positive Pursuits 13: Ecosystems are restored"
Responsible water management
By 2026, reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m3 or 40 per cent over the 2015 baseline
UN's SDG Target 6.4: "By 2030, substantially increase water-use efficiency across all sectors and ensure sustainable withdrawals and supply of freshwater to address water scarcity and substantially reduce the number of people suffering from water scarcity."
Reduce operational waste By 2022, reduce total waste generation by 80 per cent over a 2019 baseline UN's SDG Target 12.5: "By 2030, substantially reduce waste generation through prevention, reduction, recycling and reuse."
Reduce air emissions
By 2026, achieve a 95 per cent reduction of SO2 emissions and an 80 per cent reduction of NOx emissions below 2005 levels
UN's SDG Target 9.4: "By 2030, upgrade infrastructure and retrofit industries to make them sustainable, with increased resource-use efficiency and greater adoption of clean and environmentally sound technologies and industrial processes"
Reduce GHG emissions By 2030, achieve company-wide GHG reductions of 60 per cent below 2015 levels, in line with a commitment to the UN's SDGs and prevention of 2ºC of global warming UN's SDG Target 13.2: "Integrate climate change measures into national policies, strategies and planning."
By 2050, achieve carbon neutrality
ESG Alignment: Social
TransAlta Sustainability Goal TransAlta Sustainability Target Alignment with UN's SDG Target or Future-Fit Target
Reduce safety incidents Achieve a Total Recordable Injury Frequency rate below 0.61 UN's SDG Target 8.8: "Protect labour rights and promote safe and secure working environments for all workers, including migrant workers, in particular women migrants, and those in precarious employment."




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Management’s Discussion and Analysis
Support prosperous Indigenous communities Support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities UN's SDG Target 4.5: "By 2030, eliminate gender disparities in education and ensure equal access to all levels of education and vocational training for the vulnerable, including persons with disabilities, Indigenous peoples and children in vulnerable situations."
Provide Indigenous cultural awareness training to all TransAlta employees by the end of 2023 UN's SDG Target 12.8: "By 2030, ensure that people everywhere have the relevant information and awareness for sustainable development and lifestyles in harmony with nature."
ESG Alignment: Governance
TransAlta Sustainability Goal TransAlta Sustainability Target Alignment with UN's SDG Target or Future-Fit Target
Strengthen gender equality Achieve a quota of 50 per cent female representation on the Board by 2030 UN's SDG Target 5.5: "Ensure women’s full and effective participation and equal opportunities for leadership at all levels of decision making in political, economic and public life."
Achieve at least 40 per cent female employment among all employees of the Corporation by 2030
Maintain equal pay for women in equivalent roles as men
Demonstrate leadership on ESG reporting within financial disclosures Maintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworks UN's SDG Target 12.6: "Encourage companies, especially large and transnational companies, to adopt sustainable practices and to integrate sustainability information into their reporting cycle."
ESG Alignment: Environment and Social
TransAlta Sustainability Goal TransAlta Sustainability Target Alignment with UN's SDG Target or Future-Fit Target
Coal transition No further coal generation by the end of 2025 and 100 per cent of our owned net generation capacity will be from clean electricity (renewables and gas) UN's SDG Target 7.1: "By 2030, ensure universal access to affordable, reliable and modern energy services."
Discontinue coal power generation in Canada by the end of 2021 UN's SDG Target 7.1: "By 2030, ensure universal access to affordable, reliable and modern energy services."
Clean energy solutions for customers Develop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductions UN's SDG Target 7.2: "By 2030, increase substantially the share of renewable energy in the global energy mix."








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Management’s Discussion and Analysis
Governance and Risk Management
Our business activities expose us to a variety of risks and opportunities including, but not limited to, regulatory changes, rapidly changing market dynamics and increased volatility in our key commodity markets. Our goal is to manage these risks and opportunities so that we are in a position to develop our business and achieve our goals while remaining reasonably protected from an unacceptable level of risk or financial exposure. We use a multilevel risk management oversight structure to manage the risks and opportunities arising from our business activities, the markets in which we operate and the political environments and structures with which we interface.
 
Governance
The key elements of our governance practices are:
▪Employees, management and the Board are committed to ethical business conduct, integrity and honesty;
▪We have established key policies and standards to provide a framework for how we conduct our business;
▪The Chair of our Board and all directors, other than our President and CEO, are independent within the meaning of National Instrument 58-101 - Disclosure of Corporate Governance Practices;
▪The Board is comprised of individuals with a mix of skills, knowledge and experience that are critical for our business and our strategy;
▪The effectiveness of the Board is achieved through robust annual evaluations and continuing education of our directors; and
▪Our management and Board facilitate and foster an open dialogue with shareholders and community stakeholders.
 
Commitment to ethical conduct is the foundation of our corporate governance model. We have adopted the following codes of conduct to guide our business decisions and everyday business activities:
▪Corporate Code of Conduct, which applies to all employees and officers of TransAlta and its subsidiaries;
▪Directors’ Code of Conduct;
▪Supplier's Code of Conduct;
▪Finance Code of Ethics, which applies to all financial employees of the Corporation; and
▪Energy Trading Code of Conduct, which applies to all of our employees engaged in energy marketing.
 
Our codes of conduct outline the standards and expectations we have for our employees, officers, directors, consultants and suppliers with respect to, among other things, the protection and proper use of our assets. The codes also provide guidelines with respect to securing our assets, avoiding conflicts of interest, respect in the workplace, social responsibility, privacy, compliance with laws, insider trading, environment, health and safety, and our commitment to ethical and honest conduct. Our Corporate Code of Conduct and Directors' Code of Conduct each goes beyond the laws, rules and regulations that govern our business in the jurisdictions in which we operate; they outline the principal business practices with which all employees and directors must comply.
 
Our employees, officers and directors are reminded annually about the importance of ethics and professionalism in their daily work, and must certify annually that they have reviewed and understand their responsibilities as set forth in the respective codes of conduct. This certification also requires our employees, officers and directors to acknowledge that they have complied with the standards set out in the respective code during the last calendar year.
 
The Board provides stewardship of the Corporation and ensures that the Corporation establishes key policies and procedures for the identification, assessment and management of principal risks and strategic plans. The Board monitors and assesses the performance and progress of the Corporation’s goals through candid and timely reports from the CEO and the senior management team. We have also established an annual evaluation process whereby our directors are provided with an opportunity to evaluate the Board, Board committees, individual directors and the Chair of the Board’s performance.
 
In order to allow the Board to establish and manage the financial, environmental, and social elements of our governance practices, the Board has established the AFRC, GSSC, the Human Resources Committee (the “HRC”) and the Investment Performance Committee ("IPC").
 
The AFRC, consisting of independent members of the Board, provides assistance to the Board in fulfilling its oversight responsibility relating to the integrity of our consolidated financial statements and the financial reporting process; the systems of internal accounting and financial controls; the internal audit function; the external auditors’ qualifications and terms and conditions of appointment, including remuneration, independence, performance and reports; and the legal and risk compliance programs as established by management and the Board. The AFRC approves our Commodity and Financial Exposure Management policies and reviews quarterly Enterprise Risk Management reporting.




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Management’s Discussion and Analysis
The GSSC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to the Corporation and for monitoring compliance with these principles. The GSSC is also responsible for Board recruitment, succession planning and for the nomination of directors to the Board and its committees. In addition, the GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Corporation’s monitoring of environmental, health and safety regulations and public policy changes and the establishment and adherence to environmental, health and safety practices, procedures and policies. The GSSC also receives an annual report on the annual codes of conduct certification process.
 
In regards to overseeing and seeking to ensure that the Corporation consistently achieves strong environment, health and safety (“EH&S”) performance, the GSSC undertakes a number of actions that include: a) receiving regular reports from management regarding environmental compliance, trends and TransAlta’s responses; b) receiving reports and briefings on management’s initiatives with respect to changes in climate change legislation, policy developments as well as other draft initiatives and the potential impact such initiatives may have on our operations; c) assessing the impact of the GHG policies implementation and other legislative initiatives on the Corporation’s business; d) reviewing with management the EH&S policies of the Corporation; e) reviewing with management the health and safety practices implemented within the Corporation, as well as the evaluation and training processes put in place to address problem areas; f) discussing with management ways to improve the EH&S processes and practices; and g) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further improve the Corporation’s EH&S culture.
 
The HRC is empowered by the Board to review and approve key compensation and human resources policies of the Corporation that are intended to attract, recruit, retain and motivate employees of the Corporation. The HRC also makes recommendations to the Board regarding the compensation of the CEO, including the review and adoption of equity-based incentive compensation plans, the adoption of human resources policies that support human rights and ethical conduct, and the review and approval of executive management succession and development plans.

The IPC is empowered by the Board to oversee management's investment conclusions and the execution of major, Board-approved capital expenditure projects that further the Corporation's strategic plans. The IPC undertakes a number of actions that include: a) reviewing and considering the substantive risks, returns, financing and other key elements relating to the Corporation's major capital projects; b) reviewing and assessing mitigation plans, expected outcomes, and implementation throughout the project life cycle with respect to substantive risks; c) reviewing and assessing cost-estimating methodologies employed throughout the project life cycle; d) reviewing and assessing progress reports including periodic updates on the project schedule, risks and costs at key milestones as projects advance through to execution; e) reviewing post-project look-backs; and f) reviewing and providing recommendations to the Board regarding capital expenditures associated with such capital projects.

The responsibilities of other stakeholders within our risk management oversight structure are described below:
 
The CEO and executive management review and report on key risks quarterly. Specific Trading Risk Management reviews are held monthly by the Commodity Risk and Compliance Committee, and weekly by the commodity risk team, the commercial managers in Trading and Marketing, and the Executive Vice-President, Finance & Trading and Chief Financial Officer.
 
The Investment Committee is chaired by our CEO and is comprised of the CEO, Executive Vice-President, Finance & Trading and Chief Financial Officer, Chief Operating Officer, Chief Development Officer, and Executive Vice-President, Legal, Commercial and External Affairs. It reviews and approves all major capital expenditures including growth, productivity, life extensions and major coal outages. Projects that are approved by the Investment Committee will then be put forward for approval by the Board, if required.
 
The Commodity Risk & Compliance Committee is chaired by our Executive Vice-President, Finance & Trading and Chief Financial Officer and is comprised of at least three members of senior management. It oversees the risk and compliance program in trading and ensures that this program is adequately resourced to monitor trading operations from a risk and compliance perspective. It also ensures the existence of appropriate controls, processes, systems and procedures to monitor adherence to policy.
 
The Hydro Operating Committee consists of two members who are Brookfield employees with expertise in hydro facility management, and two TransAlta members. This committee was formed in 2019 for the purpose of collaborating on matters in connection with the operation, and maximization of the value, of TransAlta's Alberta Hydro Assets. It is delivering on its objectives by thoroughly reviewing the operating, maintenance, safety and environmental aspects of TransAlta's Alberta Hydro Assets and, following that review, providing expert advice and recommendations to




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Management’s Discussion and Analysis
TransAlta’s hydro operational team. The Committee has an initial term of six years, which can be extended for an additional two years.

TransAlta is listed on the TSX and the New York Stock Exchange and is subject to the governance regulations, rules and standards applicable under both exchanges. Our corporate governance practices meet the following governance rules of the TSX and Canadian Securities Administrators: a) Multilateral Instrument 52-109 - Certification of Disclosure in Issuers’ Annual and Interim Filings; b) National Instrument 52-110 - Audit Committees; c) National Policy 58-201 - Corporate Governance Guidelines; and d) National Instrument 58-101 - Disclosure of Corporate Governance Practices. As a “foreign private issuer” under US securities laws, we are generally permitted to comply with Canadian corporate governance requirements. Additional information regarding our governance practices can be found in our most recent management information circular.

COVID-19
We have adopted a number of risk mitigation measures in response to the COVID-19 pandemic, including the formal implementation of TransAlta's business continuity plan on March 9, 2020. The Board and management have been monitoring the development of the outbreak and are continually assessing its impact on the Corporation's operations, supply chains and customers, as well as, more generally, to the business and affairs of the Corporation. Potential impacts of the pandemic on the business and affairs of the Corporation include, but are not limited to: potential interruptions of production, supply chain disruptions, unavailability of employees at TransAlta, potential delays in growth projects, increased credit risk with counterparties and increased volatility in commodity prices and the valuations of financial instruments. In addition, the broader impacts to the global economy and financial markets could have potential adverse impacts on the availability of capital for investment and the demand for power and commodity pricing.

To manage the risks resulting from COVID-19, we have taken a number of steps in furtherance of the Corporation's business continuity efforts:

Management Responses
▪Formed a COVID-19 emergency team run by our Chief Operating Officer, reporting to the CEO;
▪Regularly communicated with the Board and employees in regard to the Corporation's response to COVID-19;
▪Created a team to develop, implement and update COVID-19 safety protocols, including a back-to-office and site strategy that will remain in place until a vaccine has been distributed;
▪Established a committee to consider and respond to any claims of force majeure that may be received as a result of COVID-19; and
▪Developed leadership plans, including contingent authorities.

Policy Changes
▪Aligned all non-essential travel and quarantine requirements with local jurisdictional guidance for all TransAlta employees and contractors returning from air, bus, train or ship travel for all jurisdictions in which we operate.

Employee Changes
▪Provided assurances to employees that their employment with TransAlta would not be impacted by the COVID-19 pandemic;
▪Developed and implemented COVID-19-specific back-to-office protocols to ensure all TransAlta locations remain safe;
▪Requested and received an essential workers quarantine exemption approval from Alberta Health to minimize disruptions in the event international technical assistance is required for our Alberta assets;
▪Implemented health screening procedures, including questionnaires and temperature tests, enhanced cleaning measures and strict work protocols at the Corporation’s offices and facilities in accordance with our back-to-office and site strategy;
▪Implemented training and policies to seamlessly allow non-essential employees to work remotely, as appropriate; and
▪Provided COVID-19 related town halls and information sessions for employees featuring medical and infectious disease experts.





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Management’s Discussion and Analysis
Operational Changes
▪Modified our operating procedures and implemented restrictions to non-essential access to our facilities to support continued operations through the pandemic;
▪Reviewed the supply chain risk associated with all key power-generation process inputs and implemented weekly monitoring for changes in risk;
▪Reached out to key supply chain contacts to determine strategies and contingencies to ensure we are able to continue to progress our growth projects, wherever possible; and
▪Identified new cybersecurity risks associated with phishing emails and enhanced security protocols and increased awareness of potential threats.

Financial Oversight
▪Continued to maintain a comprehensive commodity hedging program for our merchant assets that can respond to changes in underlying market conditions;
▪Continued to monitor counterparties for changes in creditworthiness, as well as monitor their ability to meet obligations; and
▪Continued to monitor the situation and communicate with our key lenders on any foreseeable impacts and on our response to the crisis. We maintain a strong financial position and significant liquidity with our existing committed credit facilities.

Overall, we continue to actively monitor the situation and advice from public health officials with a view to responding to changing recommendations and adapting our response and approach as necessary.

Risk Controls
Our risk controls have several key components:

Enterprise Tone
We strive to foster beliefs and actions that are true to, and respectful of, our many stakeholders. We do this by investing in communities where we live and work, operating and growing sustainably, putting safety first and being responsible to the many groups and individuals with whom we work.

Policies
We maintain a comprehensive set of enterprise-wide policies. These policies establish delegated authorities and limits for business transactions, as well as allow for an exception approval process. Periodic reviews and audits are performed to ensure compliance with these policies. All employees and directors are required to sign a code of conduct on an annual basis.
 
Reporting
On a regular basis, residual risk exposures are reported to key decision-makers including the Board, the AFRC, senior management and/or the Commodity Risk & Compliance Committee, as applicable. Reporting to this latter committee includes analysis of new risks, monitoring of status to risk limits, review of events that can affect these risks and discussion and review of the status of actions to minimize risks. This monthly reporting provides for effective and timely risk management and oversight.

Whistleblower System
We have a process in place where employees, contractors, shareholders or other stakeholders may confidentially or anonymously report any potential legal or ethical concerns, including concerns relating to accounting, internal control accounting, auditing or financial matters or relating to alleged violations of any laws or our code of conduct. These concerns can be submitted confidentially and anonymously, either directly to the AFRC or through TransAlta’s toll-free telephone or online Ethics Helpline. The AFRC Chair is immediately notified of any material complaints and, otherwise, the AFRC receives a report at every quarterly committee meeting on all findings related to any material complaints or complaints relating to accounting or financial reporting or alleged breaches in internal controls over financial reporting.
 
Value at Risk and Trading Positions
Value at risk (“VaR”) is one of the primary measures used to manage our exposure to market risk resulting from commodity risk management activities. VaR is calculated and reported on a daily basis. This metric describes the potential change in the value of our trading portfolio over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations.
 
VaR is a commonly used metric that is employed by industry to track the risk in commodity risk management positions and portfolios. Two common methodologies for estimating VaR are the historical variance/covariance and Monte Carlo




TRANSALTA CORPORATION M116

Management’s Discussion and Analysis
approaches. We estimate VaR using the historical variance/covariance approach. An inherent limitation of historical variance/covariance VaR is that historical information used in the estimate may not be indicative of future market risk. Stress tests are performed periodically to measure the financial impact to the trading portfolio resulting from potential market events, including fluctuations in market prices, volatilities of those prices and the relationships between those prices. We also employ additional risk mitigation measures. VaR at Dec. 31, 2020, associated with our proprietary commodity risk management activities was $1 million (2019 - $1 million). Please refer to the Risk Factors – Commodity Price Risk section of this MD&A below for further discussion.
 
Risk Factors
Risk is an inherent factor of doing business. The following section addresses some, but not all, risk factors that could affect our future plans, performance, results or outcomes and our activities in mitigating those risks. These risks do not occur in isolation, but must be considered in conjunction with each other. For a further discussion of these and other risk factors affecting the Corporation, readers are encouraged to read the Risk Factors section of the AIF, available on our website at www.transalta.com and under our profile on SEDAR at www.sedar.com and on EDGAR at www.edgar.gov.

A reference herein to a material adverse effect on the Corporation means such an effect on the Corporation or its business, operations, financial condition, results of operations and/or its cash flows, as the context requires.
 
For some risk factors, we show the after-tax effect on net earnings of changes in certain key variables. The analysis is based on business conditions and production volumes in 2020. Each item in the sensitivity analysis assumes all other potential variables are held constant. While these sensitivities are applicable to the period and the magnitude of changes on which they are based, they may not be applicable in other periods, under other economic circumstances or for a greater magnitude of changes. The changes in rates should also not be assumed to be proportionate to earnings in all instances.

Volume Risk
Volume risk relates to the variances from our expected production. The financial performance of our hydro, wind and solar operations is highly dependent upon the availability of their input resources in a given year. Shifts in weather or climate patterns, seasonal precipitation and the timing and rate of melting and runoff may impact the water flow to our facilities. The strength and consistency of the wind resource at our facilities impacts production. The operation of thermal facilities can also be impacted by ambient temperatures and the availability of water and fuel. Where we are unable to produce sufficient quantities of output in relation to contractually specified volumes, we may be required to pay penalties or purchase replacement power in the market.
 
We manage volume risk by:
 
▪Actively managing our assets and their condition in order to be proactive in facility maintenance so that our facilities are available to produce when required; 
▪Monitoring water resources throughout Alberta to the best of our ability and optimizing this resource against real-time electricity market opportunities; 
▪Placing our facilities in locations we believe to have adequate resources to generate electricity to meet the requirements of our contracts. However, we cannot guarantee that these resources will be available when we need them or in the quantities that we require; and
▪Diversifying our fuels and geography to mitigate regional or fuel-specific events.

The sensitivity of volumes to our net earnings is shown below:
Factor Increase or
decrease (%) 		Approximate impact
on net earnings
Availability/production 1  $8 million
  
Generation Equipment and Technology Risk
There is a risk of equipment failure due to wear and tear, latent defect, design error or operator error, among other things, which could have a material adverse effect on the Corporation. Although our generation facilities have generally operated in accordance with expectations, there can be no assurance that they will continue to do so. Our facilities are exposed to operational risks such as failures due to cyclic, thermal and corrosion damage in boilers, generators and turbines, as well as other issues that can lead to outages and increased volume risk. If facilities do not meet availability or production targets specified in their PPA or other long-term contracts, we may be required to compensate the purchaser for the loss in the availability of production or record reduced energy or capacity payments. For merchant facilities, an outage can result in lost merchant opportunities. Therefore, an extended outage could have a material adverse effect on our business, financial condition, results of operations or our cash flows.




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Management’s Discussion and Analysis
 
As well, we are exposed to procurement risk for specialized parts that may have long lead times. If we are unable to procure these parts when they are needed for maintenance activities, we could face an extended period where our equipment is unavailable to produce electricity.

We manage our generation equipment and technology risk by:
 
▪Operating our facilities within defined industry standards that optimizes availability over their commercial operating life;
▪Performing preventive maintenance in accordance with applicable industry practices, major equipment supplier recommendations and our operating experience;
▪Adhering to comprehensive maintenance programs and regular turnaround schedules;
▪Adjusting maintenance plans by facility to reflect equipment type, age and commercial risk;
▪Having adequate business interruption insurance in place to cover extended forced outages;
▪Having clauses in our PPAs and other long-term contracts that allow us to declare force majeure in the event of an unforeseen failure;
▪Selecting and applying proven technology in our generating facilities, where practical;
▪Where technology is newer, ensuring service agreements with equipment suppliers include appropriate availability and performance guarantees;
▪Monitoring our fleet against industry performance to identify issues or advancements that may impact performance and adjusting our maintenance and investment programs accordingly;
▪Negotiating strategic supply agreements with selected vendors to ensure key components are readily available in the event of a significant outage;
▪Entering into long-term arrangements with our strategic supply partners to ensure availability of critical spare parts; and
▪Implementing long-term asset management strategies that optimize the life cycles of our existing facilities and/or identify replacement requirements for generating assets.

Commodity Price Risk
We have exposure to movements in certain commodity prices, including the market price of electricity and fuels used to produce electricity in both our electricity generation and proprietary trading businesses.
 
We manage the financial exposure associated with fluctuations in electricity price risk by:
 
▪Entering into long-term contracts that specify the price at which electricity, steam and other services are provided;
▪Maintaining a portfolio of short-, medium- and long-term contracts to mitigate our exposure to short-term fluctuations in commodity prices;
▪Purchasing natural gas coincident with production for merchant facilities so spot market spark spreads are adequate to produce and sell electricity at a profit; and
▪Ensuring limits and controls are in place for our proprietary trading activities.
 
In 2020, we had approximately 90 per cent (2019 – 90 per cent) of production under short-term and long-term contracts and hedges. In the event of a planned or unplanned outage or other similar event, however, we are exposed to changes in electricity prices on purchases of electricity from the market to fulfil our supply obligations under these short- and long-term contracts.
 
We manage the financial exposure to fluctuations in the cost of fuels used in production by:
 
▪Entering into long-term contracts that specify the price at which fuel is to be supplied to our facilities;
▪Hedging emissions costs by entering into various emission trading arrangements; and
▪Selectively using hedges, where available, to set prices for fuel.
 
In 2020, 89 per cent (2019 – 66 per cent) of our gas consumption used in generating electricity was contractually fixed or passed through to our customers and 78 per cent (2019 – 76 per cent) of our purchased coal was contractually fixed.
 
Actual variations in net earnings can vary from calculated sensitivities and may not be linear due to optimization opportunities, co-dependencies and cost mitigations, production, availability and other factors.





TRANSALTA CORPORATION M118

Management’s Discussion and Analysis
Coal Supply Risk
Having sufficient fuel available when required for generation is essential to maintaining our ability to produce electricity under contracts and for merchant sale opportunities. At our coal-fired facilities, input costs such as diesel, tires, the price and availability of mining equipment, the volume of overburden removed to access coal reserves, rail rates and the location of mining operations relative to the power facilities are some of the exposures in our operations. Additionally, the ability of the mines to deliver coal to the power facilities can be impacted by weather conditions and labour relations. At Centralia, interruptions at our supplier’s mine, the availability of trains to deliver coal and the financial viability of our coal suppliers could affect our ability to generate electricity.
 
We manage coal supply risk by:
 
▪Ensuring that the majority of the coal used in electrical generation in Alberta is from reserves permitted through coal rights we have purchased or for which we have long-term supply contracts, thereby limiting our exposure to fluctuations in the supply of coal from third parties;
 
▪Sourcing the coal used at Centralia from different mine sources to ensure sufficient coal is available at a competitive cost;

▪Contracting sufficient trains to deliver the coal requirements at Centralia;

▪Ensuring coal inventories on hand at Alberta Thermal and Centralia are at appropriate levels for usage requirements;

▪Ensuring efficient coal handling and storage facilities are in place so that the coal being delivered can be processed in a timely and efficient manner;
 
▪Monitoring and maintaining coal specifications, and carefully matching the specifications mined with the requirements of our facilities;
▪Co-firing natural gas with coal;

▪Monitoring the financial viability of Centralia suppliers; and

▪Hedging diesel exposure in mining and transportation costs.
 
Natural Gas Supply and Price Risk
Having sufficient natural gas and natural gas transportation services available so that we can blend natural gas in with coal at our Alberta thermal facilities, and for the ultimate conversion of those units to natural gas, is essential to maintaining the reliability and availability of those facilities. Using natural gas at our coal-fired facilities, and ultimately converting these facilities to natural gas, allows us to reduce overall carbon emissions and costs, reduce the risk of coal opacity issues, and improves our operating and sustaining capital costs. Ensuring adequate pipeline transportation service and natural gas supply for our Alberta thermal units may be impacted by, among other things, the timing of receiving regulatory and other approvals for firm transportation commitments, weather-related events, work stoppages, system maintenance, variability in pipeline hydraulics pressure and flows, and impacts due to other naturally created events. Pricing of natural gas is driven by market supply and demand fundamentals for natural gas in North America and globally. We are exposed to changes in natural gas prices, which may impact the profitability of our facilities and how the facilities are dispatched into the market.

We manage gas supply and price risk by:
▪Working to ensure that we have at least two pipelines supplying the gas used in electrical generation in Alberta;
▪Contracting for firm gas delivery and supply;
▪Monitoring the financial viability of gas producers and pipelines;
▪Hedging gas price exposure;
▪Monitoring pipeline maintenance schedules and transportation availability; and
▪Incorporating the ability to continue using coal in some of the units as the units transition from coal to 100 per cent natural gas.





TRANSALTA CORPORATION M119

Management’s Discussion and Analysis
Environmental Compliance Risk
Environmental compliance risks are risks to our business associated with existing and/or changes in environmental regulations. New emission reduction objectives for the power sector are being established by governments in Canada and the US. We anticipate continued and growing scrutiny by investors and other stakeholders relating to sustainability performance. These changes to regulations may affect our earnings by reducing the operating life of generating facilities and imposing additional costs on the generation of electricity through such measures as emission caps or taxes, requiring additional capital investments in emission capture technology or requiring us to invest in offset credits. It is anticipated that these compliance costs will increase due to increased political and public attention to environmental concerns.
 
We manage environmental compliance risk by:
 
▪Seeking continuous improvement in numerous performance metrics such as emissions, safety, land and water impacts, and environmental incidents;
▪ 
▪Having an International Organization for Standardization and Occupational Health and Safety Assessment Series-based environmental health and safety management system in place that is designed to continuously improve performance;
▪ 
▪Committing significant experienced resources to work with regulators in Canada and the US to advocate that regulatory changes are well-designed and cost-effective;
▪ 
▪Developing compliance plans that address how to meet or surpass emission standards for GHGs, mercury, SO2, and NOx, which will be adjusted as regulations are finalized;
▪ 
▪Purchasing emission reduction offsets;
▪ 
▪Investing in renewable energy projects, such as wind, solar and hydro generation; and
▪ 
▪Incorporating change-in-law provisions in contracts that allow recovery of certain compliance costs from our customers.
 
We are committed to remaining in compliance with all environmental regulations relating to operations and facilities. Compliance with both regulatory requirements and management system standards is regularly audited through our performance assurance policy and results are reported to the GSSC.

Credit Risk
Credit risk is the risk to our business associated with changes in the creditworthiness of entities with which we have commercial exposures. This risk results from the ability of a counterparty to either fulfil its financial or performance obligations to us or where we have made a payment in advance of the delivery of a product or service. The inability to collect cash due to us or to receive products or services may have an adverse impact upon our net earnings and cash flows.
     
We manage our exposure to credit risk by:
 
▪Establishing and adhering to policies that define credit limits based on the creditworthiness of counterparties, contract term limits and the credit concentration with any specific counterparty;
▪ 
▪Requiring formal sign-off on contracts that include commercial, financial, legal and operational reviews;
▪ 
▪Requiring security instruments, such as parental guarantees, letters of credit, and cash collateral or third-party credit insurance if a counterparty goes over its limits. Such security instruments can be collected if a counterparty fails to fulfil its obligation; and
▪ 
▪Reporting our exposure using a variety of methods that allow key decision-makers to assess credit exposure by counterparty. This reporting allows us to assess credit limits for counterparties and the mix of counterparties based on their credit ratings.
 
If established credit exposure limits are exceeded, we take steps to reduce this exposure, such as by requesting collateral, if applicable, or by halting commercial activities with the affected counterparty. However, there can be no assurances that we will be successful in avoiding losses as a result of a contract counterparty not meeting its obligations.
 
Amidst the current economic conditions resulting from the COVID-19 pandemic, TransAlta has implemented the following additional measures to monitor its counterparties for changes in their ability to meet obligations:
▪daily monitoring of events impacting counterparty creditworthiness and counterparty credit downgrades;
▪weekly oversight and follow-up, if applicable, of accounts receivables; and
▪review and monitoring of key suppliers, counterparties and customers (i.e., offtakers).





TRANSALTA CORPORATION M120

Management’s Discussion and Analysis
As needed, additional risk mitigation tactics will be taken to reduce the risk to TransAlta. These risk mitigation tactics may include, but are not limited to, immediate follow-up on overdue amounts, adjusting payment terms to ensure a portion of funds are received sooner, requiring additional collateral, reducing transaction terms and working closely with impacted counterparties on negotiated solutions.

Our credit risk management profile and practices have not changed materially from Dec. 31, 2019. We had no material counterparty losses in 2020. We continue to keep a close watch on changes and trends in the market and the impact these changes could have on our energy trading business and hedging activities, and will take appropriate actions as required, although no assurance can be given that we will always be successful.
 
The following table outlines our maximum exposure to credit risk without taking into account collateral held or right of set-off, including the distribution of credit ratings, as at Dec. 31, 2020:
Investment grade
 (%)
Non-investment grade
 (%)
Total
 (%)
Total
amount
Trade and other receivables(1)
92  8  100  583 
Long-term finance lease receivables 100  —  100  228 
Risk management assets(1)
93  7  100  692 
Loan receivable(2)
—  100  100  52 
Total       1,555 
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. 
(2) The counterparties have no external credit ratings.

The maximum credit exposure to any one customer for commodity trading operations, including the fair value of open trading positions net of any collateral held, is $22 million (2019 – $5 million).

Currency Rate Risk
 
We have exposure to various currencies as a result of our investments and operations in foreign jurisdictions, the earnings from those operations, the acquisition of equipment and services and foreign-denominated commodities from foreign suppliers, and our US-denominated debt. Our exposures are primarily to the US and Australian currencies. Changes in the values of these currencies in relation to the Canadian dollar may affect our earnings or the value of our foreign investments to the extent that these positions or cash flows are not hedged or the hedges are ineffective.
 
We manage our currency rate risk by establishing and adhering to policies that include:
 
▪Hedging our net investments in US operations using US-denominated debt;
▪ 
▪Entering into forward foreign exchange contracts to hedge future foreign-denominated expenditures including our US-denominated debt that is outside the net investment portfolio; and
▪ 
▪Hedging our expected foreign operating cash flows. Our target is to hedge a minimum of 60 per cent of our forecasted foreign operating cash flows over a four-year period, with a minimum of 90 per cent in the current year, 70 per cent in the next year, 50 per cent in the third year and 30 per cent in the fourth year. The US exposure will be managed with a combination of interest expense on our US-denominated debt and forward foreign exchange contracts and the Australian exposure will be managed with a combination of interest expense on our Australian-dollar denominated debt and forward foreign exchange contracts.
 
The sensitivity of our net earnings to changes in foreign exchange rates has been prepared using management’s assessment that an average $0.03 increase or decrease in the US or Australian currencies relative to the Canadian dollar is a reasonable potential change over the next quarter, and is shown below:
Factor Increase or decrease Approximate impact
on net earnings
Exchange rate $0.03 $12 million
 




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Management’s Discussion and Analysis
Liquidity Risk
 
Liquidity risk relates to our ability to access capital to be used to engage in trading and hedging activities, capital projects, debt refinancing and payment of liabilities, capital structure and general corporate purposes. Credit ratings facilitate these activities and changes in credit ratings may affect our ability and/or the cost of accessing capital markets, establishing normal course derivative or hedging transactions, including those undertaken by our Energy Marketing segment. Counterparties enter into certain electricity and natural gas purchase and sale contracts for the purposes of asset-backed sales and proprietary trading. The terms and conditions of these contracts require the counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may impact our ability to enter into these contracts or any ordinary course contract, decrease the credit limits granted and increase the amount of collateral that may have to be provided. Certain existing contracts contain credit rating contingent clauses, that, when triggered, automatically increase costs under the contract or require additional collateral to be posted. Where the contingency is based on the lowest single rating, a one-level downgrade from a credit rating agency with an originally higher rating may not, however, trigger additional direct adverse impact.
 
We continue to focus on maintaining our financial position and flexibility. Credit ratings issued for TransAlta, as well as the corresponding rating agency outlooks, are set out in the Financial Capital section of this MD&A. Credit ratings are subject to revision or withdrawal at any time by the rating organization, and there can be no assurance that TransAlta’s credit ratings and the corresponding outlook will not be changed, resulting in the adverse possible impacts identified above.
 
As at Dec. 31, 2020, we have liquidity of $2.1 billion comprised of amounts not drawn under our committed credit facilities and cash on hand that is available to draw on for projects in 2021.
 
We manage liquidity risk by:
 
▪Monitoring liquidity on trading positions;

▪Preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital;

▪Reporting liquidity risk exposure for commodity risk management activities on a regular basis to the Commodity Risk & Compliance Committee, senior management and the AFRC;

▪Maintaining a strong balance sheet; and

▪Maintaining sufficient undrawn committed credit lines to support potential liquidity requirements.
 
Interest Rate Risk
 
Changes in interest rates can impact our borrowing costs. Changes in our cost of capital may also affect the feasibility of new growth initiatives.
 
We manage interest rate risk by establishing and adhering to policies that include:
 
▪Employing a combination of fixed and floating rate debt instruments; and
▪Monitoring the mixture of floating and fixed rate debt and adjusting to ensure efficiency.
 
At Dec. 31, 2020, approximately seven per cent (2019 – 11 per cent) of our total debt portfolio was subject to changes in floating interest rates through a combination of floating rate debt and interest rate swaps.
 
The sensitivity of changes in interest rates upon our net earnings is shown below:
Factor Increase or
decrease (%) 		Approximate impact
on net earnings
Interest rate 30 $1 million before tax
 
IBOR reform could impact interest rate risk with respect to the Corporation's credit facilities and the Poplar Creek non-recourse bond held by a TransAlta subsidiary. The facility references LIBOR for US-dollar drawings and the Canadian Dollar Offer Rate ("CDOR") for Canadian-dollar drawings; in addition, the non-recourse bond references the three-month CDOR. To date, no US-dollar drawings have been made on the facility and there is currently a plan to discontinue the six- and 12-month CDOR, which does not impact the facility or the non-recourse bond.





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Management’s Discussion and Analysis
Outstanding forward starting interest rate swaps in both Canadian and US dollars should not be affected as they are set to settle in 2021 prior to any IBOR changes being made. The Corporation is monitoring the reform and does not expect any material impacts.

Project Management Risk
 
On capital projects, we face risks associated with cost overruns, delays and performance.
 
We manage project risks by:
 
▪Ensuring all projects follow established corporate processes and policies;
▪Identifying key risks during every stage of project development and ensuring mitigation plans are factored into capital estimates and contingencies;
▪Reviewing project plans, key assumptions and returns with senior management prior to Board of Director approvals;
▪Consistently applying project management methodologies and processes;
▪Determining contracting strategies that are consistent with the project scope and scale to ensure key risks, such as labour and technology, are managed by contractors and equipment suppliers;
▪Ensuring contracts for construction and major equipment include key terms for performance, delays and quality backed by appropriate levels of liquidated damages;
▪Reviewing projects after achieving commercial operation to ensure learnings are incorporated into the next project;
▪Negotiating contracts for construction and major equipment to lock-in key terms such as price, availability of long lead equipment, foreign currency rates and warranties as much as is economically feasible before proceeding with the project; and
▪Entering into labour agreements to provide security around labour cost, supply and productivity.

Human Resource Risk
 
Human resource risk relates to the potential impact upon our business as a result of changes in the workplace. Human resource risk can occur in several ways:
 
▪Potential disruption as a result of labour action at our generating facilities;

▪Reduced productivity due to turnover in positions;

▪Inability to complete critical work due to vacant positions;

▪Failure to maintain fair compensation with respect to market rate changes; and

▪Reduced competencies due to insufficient training, failure to transfer knowledge from existing employees or insufficient expertise within current employees.
 
We manage this risk by:
 
▪Monitoring industry compensation and aligning salaries with those benchmarks;
▪Using incentive pay to align employee goals with corporate goals;
▪Monitoring and managing target levels of employee turnover; and
▪Ensuring new employees have the appropriate training and qualifications to perform their jobs.
 
In 2020, 46 per cent (2019 – 46 per cent) of our labour force was covered by 10 (2019 – 10) collective bargaining agreements. In 2020, two (2019 – four) agreements were renegotiated. We anticipate the successful negotiation of three collective agreements in 2021.

Regulatory and Political Risk
 
Regulatory and political risk is the risk to our business associated with potential changes to the existing regulatory structures and the political influence upon those structures within each of the jurisdictions in which we operate. This risk can come from market regulation and re-regulation, increased oversight and control, structural or design changes in markets, or other unforeseen influences. Market rules are often dynamic and we are not able to predict whether there will be any material changes in the regulatory environment or the ultimate effect of changes in the regulatory environment on our business. This risk includes, among other things, uncertainties associated with the development of carbon pricing policies and funding.
 
We manage these risks systematically through our Legal and Regulatory groups and our Compliance program, which is reviewed periodically to ensure its effectiveness. We also work with governments, regulators, electricity system operators and other stakeholders to resolve issues as they arise. We are actively monitoring changes to market rules and market design, and we engage in industry- and government-agency-led stakeholder engagement processes.




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Management’s Discussion and Analysis
Through these and other avenues, we engage in advocacy and policy discussions at a variety of levels. These stakeholder consultations have allowed us to engage in proactive discussions with governments and regulatory agencies over the longer term.
 
International investments are subject to unique risks and uncertainties relating to the political, social and economic structures of the respective country and such country’s regulatory regime. We mitigate this risk through the use of non-recourse financing and insurance.
 
Transmission Risk
 
Access to transmission lines and transmission capacity for existing and new generation is key to our ability to deliver energy produced at our power facilities to our customers. The risks associated with the aging existing transmission infrastructure in markets in which we operate continue to increase because new connections to the power system are consuming transmission capacity faster than it is being added by new transmission developments.
 
Reputation Risk
 
Our reputation is one of our most valued assets. Reputation risk relates to the risk associated with our business because of changes in opinion from the general public, private stakeholders, governments and other entities.
We manage reputation risk by:
 
▪Striving as a neighbour and business partner in the regions where we operate to build viable relationships based on mutual understanding leading to workable solutions with our neighbours and other community stakeholders;
▪Clearly communicating our business objectives and priorities to a variety of stakeholders on a routine and transparent basis;
▪Applying innovative technologies to improve our operations, work environment and environmental footprint;
▪Maintaining positive relationships with various levels of government;
▪Pursuing sustainable development as a longer-term corporate strategy;
▪Ensuring that each business decision is made with integrity and in line with our corporate values;
▪Communicating the impact and rationale of business decisions to stakeholders in a timely manner; and
▪Maintaining strong corporate values that support reputation risk management initiatives, including the annual Code of Conduct sign-off.
 
Corporate Structure Risk
 
We conduct a significant amount of business through subsidiaries and partnerships. Our ability to meet and service debt obligations is dependent upon the results of operations of our subsidiaries and partnerships and the payment of funds by our subsidiaries and partnerships in the form of distributions, loans, dividends or otherwise. In addition, our subsidiaries and partnerships may be subject to statutory or contractual restrictions that limit their ability to distribute cash to us.
 
Cybersecurity Risk
 
We rely on our information technology to process, transmit and store electronic information and data used for the safe operation of our assets. In today's ever-evolving cybersecurity landscape, any attacks or other breaches of network or information systems may cause disruptions to our business operations. Cyberattackers may use a range of techniques, from exploiting vulnerabilities within our user-base, to using sophisticated malicious code on a single or distributed basis to try to breach our network security controls. Attackers may also use a combination of techniques in their attempt to evade safeguards that we have in place such as firewalls, intrusion prevention systems and antivirus software that exist on our network infrastructure systems. A successful cyberattack may allow for the unauthorized interception, destruction, use or dissemination of our information and may cause disruptions to our business operations.
 
We continuously take measures to secure our infrastructure against potential cyberattacks that may damage our infrastructure, systems and data. TransAlta’s cybersecurity model consists of three pillars: technology, processes and people. Each of these pillars can be reinforced independently to address specific cyber risks and threats that are confronting TransAlta. Significant cyber risks that could pose a threat to TransAlta include phishing, ransomware, social engineering, supplier chain, commodity hostage, state sponsored, artificial intelligence, machine learning attacks and a high risk of cybersecurity employee turnover. Proactive controls and safeguards to mitigate cybersecurity risk and threats posed to the organization include:
▪Leveraging in place technologies to restrict communication within TransAlta’s networks thus limiting the ability for adversaries to achieve their aim;
▪Partnering with a third-party cybersecurity specialty firm to outsource critical components of our cybersecurity program;
▪Enhancing our policies and processes through the use of periodic reviews and table-top exercises;




TRANSALTA CORPORATION M124

Management’s Discussion and Analysis
▪Maintaining an effective and robust cybersecurity awareness training and campaign;
▪Integrating cybersecurity into our business processes and performing robust cybersecurity risk assessments; and
▪Continuously improving our cybersecurity program to ensure it is effective in responding to and addressing cybersecurity risks.

While we have cyber insurance (as well as systems, policies, hardware, practices, data backups and procedures designed to prevent or limit the effect of the security breaches of our generation facilities and infrastructure and data), there can be no assurance that these measures will be sufficient or that such security breaches will not occur or, if they do occur, that they will be adequately addressed in a timely manner. We closely monitor both preventive and detective measures to manage these risks.
 
General Economic Conditions
 
Changes in general economic conditions impact product demand, revenue, operating costs, the timing and extent of capital expenditures, the net recoverable value of PP&E, financing costs, credit and liquidity risk, and counterparty risk.
 
Income Taxes
 
Our operations are complex and located in several countries. The computation of the provision for income taxes involves tax interpretations, regulations and legislation that are continually changing. Our tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes as required by IFRS, based on all information currently available.
 
The Corporation is subject to changing laws, treaties and regulations in and between countries. Various tax proposals in the countries we operate in could result in changes to the basis on which deferred taxes are calculated or could result in changes to income or non-income tax expense. There has recently been an increased focus on issues related to the taxation of multinational corporations. A change in tax laws, treaties or regulations, or in the interpretation thereof, could result in a materially higher income or non-income tax expense that could have a material adverse impact on the Corporation.

The sensitivity of changes in income tax rates upon our net earnings is shown below:
Factor Increase or
decrease (%) 		Approximate impact
on net earnings
Tax rate 1 
$3 million

Legal Contingencies
 
We are occasionally named as a party in various disputes, claims and legal or regulatory proceedings that arise during the normal course of our business. We review each of these claims, including the nature and merits of the claim, the amount in dispute or claimed, and the availability of insurance coverage. There can be no assurance that any particular dispute, claim or proceeding will be resolved in our favour or our liabilities with respect to such claims will not have a material adverse effect on us or our business, operations or financial results. Please refer to the Other Consolidated Analysis section of this MD&A for further details.
 
Other Contingencies
 
We maintain a level of insurance coverage deemed appropriate by management. There were no significant changes to our insurance coverage during renewal of the insurance policies on Dec. 31, 2020. Our insurance coverage may not be available in the future on commercially reasonable terms. There can be no assurance that our insurance coverage will be fully adequate to compensate for potential losses incurred. In the event of a significant economic event, the insurers may not be capable of fully paying all claims. All insurance policies are subject to standard exclusions. Cyber coverage is not currently purchased.





TRANSALTA CORPORATION M125

Management’s Discussion and Analysis
Disclosure Controls and Procedures
Management is responsible for establishing and maintaining adequate internal control over financial reporting (‘‘ICFR’’) and disclosure controls and procedures (“DC&P’’). For the year ended Dec. 31, 2020, the majority of our workforce supporting and executing our ICFR and DC&P worked remotely. There has been minimal impact to the design and performance of our internal controls. Management has reviewed the changes as a result of changes implemented in response to COVID-19 and is reasonably assured that adjustments to process have not materially affected, or are reasonably likely to materially affect, our ICFR or DC&P

ICFR is a framework designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with IFRS. Management has used the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) in order to assess the effectiveness of the Corporation’s ICFR.

DC&P refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under securities legislation is recorded, processed, summarized and reported within the time frame specified in applicable securities legislation. DC&P include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in our reports that we file or submit under applicable securities legislation is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding our required disclosure.

Together, the ICFR and DC&P frameworks provide internal control over financial reporting and disclosure. In designing and evaluating our ICFR and DC&P, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives and as such may not prevent or detect all misstatements, and management is required to apply its judgment in evaluating and implementing possible controls and procedures. Further, the effectiveness of ICFR is subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with policies or procedures may change.

Management has evaluated, with the participation of our Chief Executive Officer and Chief Financial Officer, the effectiveness of our ICFR and DC&P as of the end of the period covered by this MD&A. Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as at Dec. 31, 2020, the end of the period covered by this MD&A, our ICFR and DC&P were effective.





TRANSALTA CORPORATION M126
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Consolidated Financial Statements

Management's Report
To the Shareholders of TransAlta Corporation 
The Consolidated Financial Statements and other financial information included in this annual report have been prepared by management. It is management’s responsibility to ensure that sound judgment, appropriate accounting principles and methods, and reasonable estimates have been used to prepare this information. They also ensure that all information presented is consistent.
Management is also responsible for establishing and maintaining internal controls and procedures over the financial reporting process. The internal control system includes an internal audit function and an established business conduct policy that applies to all employees. In addition, TransAlta Corporation has a code of conduct that applies to all employees and is signed annually. The code of conduct can be viewed on TransAlta’s website (www.transalta.com). Management believes the system of internal controls, review procedures and established policies provides reasonable assurance as to the reliability and relevance of financial reports. Management also believes that TransAlta’s operations are conducted in conformity with the law and with a high standard of business conduct.
The Board of Directors (the “Board”) is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal controls. The Board carries out its responsibilities principally through its Audit, Finance and Risk Committee (the “Committee”). The Committee, which consists solely of independent directors, reviews the financial statements and annual report and recommends them to the Board for approval. The Committee meets with management, internal auditors and external auditors to discuss internal controls, auditing matters and financial reporting issues. Internal and external auditors have full and unrestricted access to the Committee. The Committee also recommends the firm of external auditors to be appointed by the shareholders.
TAC-20201231_G1.JPG
TAC-20201231_G2.JPG
Dawn L. Farrell Todd Stack
President and Chief Executive Officer Executive Vice President, Finance and
Chief Financial Officer
March 2, 2021




TRANSALTA CORPORATION F1

Consolidated Financial Statements

Management’s Annual Report on Internal Control Over Financial Reporting
To the Shareholders of TransAlta Corporation
The following report is provided by management in respect of TransAlta Corporation’s (“TransAlta”) internal control over financial reporting (as defined in Rules 13a-15f and 15d-15f under the United States Securities Exchange Act of 1934 and National Instrument 52-109 Certification of Disclosure in Issuers' Annual and Interim Filings).
TransAlta’s management is responsible for establishing and maintaining adequate internal control over financial reporting for TransAlta.
Management has used the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) 2013 framework to evaluate the effectiveness of TransAlta’s internal control over financial reporting. Management believes that the COSO 2013 framework is a suitable framework for its evaluation of TransAlta’s internal control over financial reporting because it is free from bias, permits reasonably consistent qualitative and quantitative measurements of TransAlta’s internal controls, is sufficiently complete so that those relevant factors that would alter a conclusion about the effectiveness of TransAlta’s internal controls are not omitted, and is relevant to an evaluation of internal control over financial reporting.
Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper overrides. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process, and it is possible to design safeguards into the process to reduce, though not eliminate, this risk.
TransAlta proportionately consolidates the joint operations of the Sheerness Generating Station, and Pioneer Pipeline Limited Partnership and we equity account for our investments in SP Skookumchuck Investment, LLC and EMG International, LLC in accordance with International Financial Reporting Standards. Management does not have the contractual ability to assess the internal controls of these joint arrangements and associates. Once the financial information is obtained from these joint arrangements and associates it falls within the scope of TransAlta’s internal controls framework. Management’s conclusion regarding the effectiveness of internal controls does not extend to the internal controls at the transactional level of these joint arrangements and associates.
Included in the 2020 Consolidated Financial Statements of TransAlta for joint operations and equity accounted investments are $481 million and $394 million of total and net assets, respectively, as of December 31, 2020, and $112 million and $6 million of revenues and net earnings (loss), respectively, for the year then ended.
Management has assessed the effectiveness of TransAlta’s internal control over financial reporting, as at Dec. 31, 2020, and has concluded that such internal control over financial reporting is effective.
Ernst & Young LLP, who has audited the consolidated financial statements of TransAlta for the year ended Dec. 31, 2020, has also issued a report on internal control over financial reporting under the standards of the Public Company Accounting Oversight Board (United States). This report is located on the following page of this Annual Report.
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Dawn L. Farrell Todd Stack
President and Chief Executive Officer Executive Vice President, Finance and
Chief Financial Officer
March 2, 2021




TRANSALTA CORPORATION F2

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm
To the Shareholders and Directors of TransAlta Corporation
Opinion on Internal Control Over Financial Reporting
We have audited TransAlta Corporation’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”). In our opinion, TransAlta Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on the COSO criteria.

As indicated in the accompanying Management’s Annual Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the joint operations and equity accounted investments of the Sheerness Generating Station, Pioneer Pipeline Limited Partnership, SP Skookumchuk Investment, LLC and EMG International, LLC, which are included in the 2020 consolidated financial statements of TransAlta Corporation and constituted $481 million and $394 million of total and net assets, respectively, as of December 31, 2020, and $112 million and $6 million of revenues and net earnings (loss), respectively, for the year then ended. Our audit of internal control over financial reporting of TransAlta Corporation also did not include an evaluation of the internal control over financial reporting of the joint operations and equity accounted investments of the Sheerness Generating Station, Pioneer Pipeline Limited Partnership, SP Skookumchuck Investment, LLC and EMG International, LLC.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated statements of financial position of TransAlta Corporation as of December 31, 2020 and 2019, and the related consolidated statements of earnings (loss), comprehensive income (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2020, and the related notes and our report dated March 2, 2021 expressed an unqualified opinion thereon.

Basis for Opinion
TransAlta 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 Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on TransAlta Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to TransAlta Corporation in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. 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, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.






TRANSALTA CORPORATION F3

Consolidated Financial Statements

Definition and Limitations of Internal Control Over Financial Reporting
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 corporation; (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 corporation are being made only in accordance with authorizations of management and directors of the corporation; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the corporation’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.


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Chartered Professional Accountants

Calgary, Canada
March 2, 2021

F4 TRANSALTA CORPORATION

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm
To the Shareholders and Directors of TransAlta Corporation
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statements of financial position of TransAlta Corporation (the “Corporation”) as of December 31, 2020 and 2019, the related consolidated statements of earnings (loss), comprehensive income (loss), changes in equity and cash flows, for each of the years then ended, and the related notes (collectively referred to as the “consolidated financial statements“). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of TransAlta Corporation at December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), TransAlta Corporation’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated March 2, 2021 expressed an unqualified opinion thereon.

Basis for Opinion
These consolidated financial statements are the responsibility of TransAlta Corporation‘s management. Our responsibility is to express an opinion on TransAlta Corporation‘s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to TransAlta Corporation in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.




TRANSALTA CORPORATION F5

Consolidated Financial Statements


Long-Lived Assets within the Centralia Thermal Plant cash generating unit (“CGU”) & Goodwill related to the Wind and Solar segment
Description of the Matter As disclosed in notes 2(I), 2(J), 2(Z)(II), 18 and 21 of the consolidated financial statements, the Corporation owns significant power generation assets which are required to be reviewed for indicators of impairment at the CGU level and has recognized goodwill from historical acquisitions which must be tested for impairment at least annually. Long lived assets for the Centralia Thermal Plant CGU are included in the Centralia segment which amounts to $260 million. Goodwill related to the Wind and Solar segment amounts to $175 million.

We identified the assessment of indicators of impairment for the Centralia Thermal Plant CGU as a critical audit matter because it involves auditing the judgment applied by management to assess various external and internal sources of information, more specifically if significant changes with an adverse effect on the Corporation have taken place during the year, or will take place in the near future, in the market or economic environment. Determining the recoverable amount for the Wind and Solar segment for the purposes of the annual goodwill impairment test was identified as a critical audit matter due to the significant estimation uncertainty and judgement applied by management in determining the recoverable amount, primarily due to the sensitivity of the significant assumptions to the future cash flows and the effect that changes in these assumptions would have on the recoverable amount. The estimates with a high degree of subjectivity include forecasted future cash flows, generation profiles, and commodity prices, and determining the appropriate discount rate.
How We Addressed the Matter in Our Audit We obtained an understanding of management’s process for performing their assessment of indicators of impairment and the estimation of the recoverable amount. We evaluated the design and tested the operating effectiveness of controls over the Corporation’s processes to identify indicators and determine the recoverable amount. Our audit procedures to test the indicators assessment included, among others, evaluating the Corporation’s determination of future commodity prices by comparing them to externally available third-party future commodity price estimates. Our audit procedures to test the Corporation’s recoverable amount of the Wind and Solar segment included, among others, comparing the significant assumptions used to estimate cash flows to current contracts with external parties and historical trends, and obtaining historical power generation data to evaluate future generation forecasts. We assessed the historical accuracy of management’s forecasts by comparing them with actual results and performed a sensitivity analysis to evaluate the assumptions that were most significant to the determination of the recoverable amounts. We evaluated the Corporation’s determination of future commodity prices by comparing them to externally available third-party future commodity price estimates. We also involved our internal valuation specialist to assist in our evaluation of the discount rates, which involved benchmarking the inputs against available market data.
Valuation of Level III Derivative Instruments
Description of the Matter
As disclosed in notes 2(Z)(V) and 15 of the consolidated financial statements, the Corporation enters into transactions that are accounted for as derivative financial instruments and are recorded at fair value. The valuation of derivative instruments classified as level III are determined using assumptions that are not readily observable. As at December 31, 2020 the Corporation’s derivative financial instruments classified as level III were $582 million.

Auditing the determination of fair value of level III derivative instruments that rely on significant unobservable inputs can be complex and relies on judgments and estimates concerning future commodity prices, discount rates, volatility, unit availability and demand profiles, and can fluctuate significantly depending on market conditions. Therefore, such determination of fair value was identified as a critical audit matter.
How We Addressed the Matter in Our Audit We obtained an understanding of the Corporation’s processes and we evaluated and tested the design and operating effectiveness of internal controls addressing the determination and review of inputs used in establishing level III fair values. Our audit procedures included, among others, testing a sample of level III derivative instrument internal models used by management and evaluating the significant assumptions utilized. We also compared management's future pricing assumptions, credit valuation adjustments, and liquidity assumptions to third-party data as well as comparing terms such as volumes and timing to executed commodity contracts. We compared the unit availability and demand profile assumptions to historical information. We performed a sensitivity analysis to evaluate the assumptions that were most significant to the determination of level III fair value. For a sample of level III derivative instruments, we involved our internal valuation specialist to assist in our evaluation of the appropriateness of the discount rates by evaluating the key assumptions and methodologies.


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Chartered Professional Accountants
We have served as auditors of TransAlta Corporation and its predecessor entities since 1947.
Calgary, Canada
March 2, 2021





TRANSALTA CORPORATION F6

Consolidated Financial Statements



Consolidated Statements of Earnings (Loss)
 
Year ended Dec. 31 (in millions of Canadian dollars except where noted)
2020 2019 2018
Revenues (Note 5) 2,101  2,347  2,249 
Fuel, carbon compliance and purchased power (Note 6) 968  1,086  1,100 
Gross margin 1,133  1,261  1,149 
Operations, maintenance and administration (Note 6) 472  475  515 
Depreciation and amortization 654  590  574 
Asset impairment charge (Note 7) 84  25  73 
Gain on termination of Keephills 3 coal rights contract (Note 4(R))
—  (88) — 
Taxes, other than income taxes 33  29  31 
Termination of Sundance B and C PPAs (Note 4(S))
—  (56) (157)
Net other operating income (Note 9) (11) (49) (47)
Operating income (99) 335  160 
Equity income (Note 10)
1  —  — 
Finance lease income 7  6  8 
Net interest expense (Note 11) (238) (179) (250)
Foreign exchange gain (loss) 17  (15) (15)
Gain on sale of assets and other (Note 4(R) and 18)
9  46  1 
Earnings (loss) before income taxes (303) 193  (96)
Income tax expense (recovery) (Note 12) (50) 17  (6)
Net earnings (loss) (253) 176  (90)
Net earnings (loss) attributable to:      
TransAlta shareholders (287) 82  (198)
Non-controlling interests (Note 13) 34  94  108 
  (253) 176  (90)
Net earnings (loss) attributable to TransAlta shareholders (287) 82  (198)
Preferred share dividends (Note 28) 49  30  50 
Net earnings (loss) attributable to common shareholders (336) 52  (248)
Weighted average number of common shares outstanding in the year (millions)
275  283  287 
Net earnings (loss) per share attributable to common shareholders, basic and diluted
   (Note 27)
(1.22) 0.18  (0.86)
 
See accompanying notes.
 





TRANSALTA CORPORATION F7

Consolidated Financial Statements

Consolidated Statements of Comprehensive Income (Loss)
 
Year ended Dec. 31 (in millions of Canadian dollars)
2020 2019 2018
Net earnings (loss) (253) 176  (90)
Other comprehensive income (loss)      
Net actuarial gains (losses) on defined benefit plans, net of tax(1)
(11) (26) 15 
  Losses on derivatives designated as cash flow hedges, net of tax (1) —  — 
Total items that will not be reclassified subsequently to net earnings (12) (26) 15 
  Gains (losses) on translating net assets of foreign operations, net of tax (11) (59) 84 
Gains (losses) on financial instruments designated as hedges of foreign operations,
net of tax 		11  21  (41)
Gains (losses) on derivatives designated as cash flow hedges, net of tax(2)
20  61  (8)
Reclassification of gains on derivatives designated as cash flow hedges to net earnings,
  net of tax(3)
(110) (42) (46)
Total items that will be reclassified subsequently to net earnings (90) (19) (11)
Other comprehensive income (loss) (102) (45) 4 
Total comprehensive income (loss) (355) 131  (86)
Total comprehensive income (loss) attributable to:      
TransAlta shareholders (439) 54  (210)
Non-controlling interests (Note 13) 84  77  124 
  (355) 131  (86)
 
(1) Net of income tax recovery of $3 million for the year ended Dec. 31, 2020 (2019 — $7 million recovery, 2018 — $5 million expense).
(2) Net of income tax expense of $8 million for the year ended Dec. 31, 2020 (2019 —$16 million expense, 2018 — $1 million recovery).
(3) Net of reclassification of income tax expense of $31 million for the year ended Dec. 31, 2020 (2019 —$10 million expense,  2018 — $11 million expense).

See accompanying notes.





TRANSALTA CORPORATION F8

Consolidated Financial Statements


Consolidated Statements of Financial Position
As at Dec. 31 (in millions of Canadian dollars)
2020 2019
Cash and cash equivalents 703  411 
Restricted cash (Note 24) 71  32 
Trade and other receivables (Note 14) 583  462 
Prepaid expenses 31  19 
Risk management assets (Note 15 and 16) 171  166 
Inventory (Note 17) 238  251 
Assets held for sale (Note 4(B) and 7) 105  — 
  1,902  1,341 
Investments (Note 10)
100  — 
Long-term portion of finance lease receivables (Note 8) 228  176 
Risk management assets (Note 15 and 16) 521  640 
Property, plant and equipment (Note 18)
Cost 13,398  13,395 
Accumulated depreciation (7,576) (7,188)
  5,822  6,207 
Right-of-use assets (Note 19) 141  146 
Intangible assets (Note 20) 313  318 
Goodwill (Note 21) 463  464 
Deferred income tax assets (Note 12) 51  18 
Other assets (Note 22) 206  198 
Total assets 9,747  9,508 
Accounts payable and accrued liabilities 599  413 
Current portion of decommissioning and other provisions (Note 23) 59  58 
Risk management liabilities (Note 15 and 16) 94  81 
Current portion of contract liabilities (Note 5) 1  1 
Income taxes payable 18  14 
Dividends payable (Note 27 and 28) 59  37 
Current portion of long-term debt and lease liabilities (Note 24) 105  513 
  935  1,117 
Credit facilities, long-term debt and lease liabilities (Note 24) 3,256  2,699 
Exchangeable securities (Note 25)
730  326 
Decommissioning and other provisions (Note 23) 614  488 
Deferred income tax liabilities (Note 12) 396  472 
Risk management liabilities (Note 15 and 16) 68  29 
Contract liabilities (Note 5) 14  14 
Defined benefit obligation and other long-term liabilities (Note 26) 298  301 
Equity    
Common shares (Note 27) 2,896  2,978 
Preferred shares (Note 28) 942  942 
Contributed surplus 38  42 
Deficit (1,826) (1,455)
Accumulated other comprehensive income (Note 29) 302  454 
Equity attributable to shareholders 2,352  2,961 
Non-controlling interests (Note 13) 1,084  1,101 
Total equity 3,436  4,062 
Total liabilities and equity 9,747  9,508 
Significant and subsequent events (Note 4)
Commitments and contingencies (Note 36)
 
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On behalf of the Board: John P. Dielwart
Director 		Beverlee F. Park
Director
See accompanying notes.




TRANSALTA CORPORATION F9

Consolidated Financial Statements

Consolidated Statements of Changes in Equity
(in millions of Canadian dollars)
 
Common
shares
Preferred
shares 		Contributed
surplus 		Deficit
Accumulated other
comprehensive
income(1)
Attributable to
shareholders 		Attributable
to non-controlling
interests 		Total
Balance, Dec. 31, 2018 $3,059 $942 $11 $ (1,496) $481 $2,997 $1,137 $4,134
Adjustments on implementation of
IFRS 16 		—  —  —  3  —  3  —  3 
Adjusted balance as at Jan. 1, 2019 3,059  942  11  (1,493) 481  3,000  1,137  4,137 
Net earnings —  —  —  82  —  82  94  176 
Other comprehensive income (loss):              
Net losses on translating net
assets of foreign operations,
net of hedges and of tax 		—  —  —  —  (38) (38) —  (38)
Net gains on derivatives
designated as cash flow hedges,
net of tax 		—  —  —  —  19  19  —  19 
Net actuarial losses on defined
benefits plans, net of tax 		—  —  —  —  (26) (26) —  (26)
Intercompany FVOCI investments —  —  —  —  17  17  (17) — 
Total comprehensive income (loss)       82  (28) 54  77  131 
Common share dividends —  —  —  (34) —  (34) —  (34)
Preferred share dividends —  —  —  (30) —  (30) —  (30)
Shares purchased under NCIB (83) —  —  15  —  (68) —  (68)
Changes in non-controlling
  interests in TransAlta
  Renewables (Note 4(V) and 13)
—  —  —  5  1  6  22  28 
Effect of share-based payment
plans 		2  —  31  —  —  33  —  33 
Distributions paid, and payable, to
non-controlling interests 		—  —  —  —  —  —  (135) (135)
Balance, Dec. 31, 2019
2,978  942  42  (1,455) 454  2,961  1,101  4,062 
Net earnings (loss) —  —  —  (287) —  (287) 34  (253)
Other comprehensive income (loss):              
Net losses on derivatives
designated as cash flow hedges,
net of tax 		—  —  —  —  (91) (91) —  (91)
Net actuarial losses on defined
benefits plans, net of tax 		—  —  —  —  (11) (11) —  (11)
Intercompany FVOCI investments —  —  —  —  (50) (50) 50  — 
Total comprehensive income (loss)       (287) (152) (439) 84  (355)
Common share dividends —  —  —  (58) —  (58) —  (58)
Preferred share dividends —  —  —  (49) —  (49) —  (49)
Shares purchased under NCIB (79) —  —  18  —  (61) —  (61)
Changes in non-controlling
interests in TransAlta
Renewables 		—  —  —  5  —  5  15  20 
Effect of share-based payment
  plans (Note 30)
(3) —  (4) —  —  (7) —  (7)
Distributions paid, and payable, to
non-controlling interests 		—  —  —  —  —  —  (116) (116)
Balance, Dec. 31, 2020 2,896  942  38  (1,826) 302  2,352  1,084  3,436 
(1) Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive income (loss).
 See accompanying notes.







TRANSALTA CORPORATION F10

Consolidated Financial Statements

Consolidated Statements of Cash Flows
Year ended Dec. 31 (in millions of Canadian dollars)
2020 2019 2018
Operating activities      
Net earnings (loss) (253) 176  (90)
Depreciation and amortization (Note 37) 798  709  710 
Net gain on sale of assets (Note 4(I) Note 4(R))
(9) (45) — 
Accretion of provisions (Note 23) 30  23  24 
Decommissioning and restoration costs settled (Note 23) (18) (34) (31)
Deferred income tax recovery (Note 12) (85) (18) (34)
Unrealized (gain) loss from risk management activities 42  (32) 30 
Unrealized foreign exchange loss 1  13  28 
Provisions 9  13  7 
Asset impairment (Note 7) 84  25  73 
Equity income, net of distributions from Joint Ventures (1) —  — 
Other non-cash items 15  (102) 147 
Cash flow from operations before changes in working capital 613  728  864 
Change in non-cash operating working capital balances (Note 33) 89  121  (44)
Cash flow from operating activities 702  849  820 
Investing activities      
Additions to property, plant and equipment (Note 18 and 37) (486) (417) (277)
Additions to intangible assets (Note 20 and 37) (14) (14) (20)
Restricted cash (Note 24) (39) 34  (35)
Loan receivable (Note 22) (5) (10) 1 
Acquisitions, net of cash acquired (Note 4) (32) (117) (30)
Acquisition of investments (Note 10) (102) —  — 
Investment in the Pioneer Pipeline —  (83) (15)
Proceeds on sale of property, plant and equipment 6  13  2 
Realized gains on financial instruments 2  3  2 
Decrease in finance lease receivable 17  24  59 
Other (12) 23  15 
Change in non-cash investing working capital balances (22) 32  (96)
Cash flow used in investing activities (687) (512) (394)
Financing activities      
Net increase (decrease) in borrowings under credit facilities (Note 24) (106) (119) 312 
Repayment of long-term debt (Note 24) (489) (96) (1,179)
Issuance of long-term debt (Note 24) 753  166  345 
Issuance of exchangeable securities (Note 25) 400  350  — 
Dividends paid on common shares (Note 27) (47) (45) (46)
Dividends paid on preferred shares (Note 28) (39) (40) (40)
Net proceeds on sale of non-controlling interest in subsidiary (Note 4(W))
—  —  144 
Repurchase of common shares under NCIB (Note 27) (57) (68) (23)
Realized gains on financial instruments 3  —  48 
Distributions paid to subsidiaries' non-controlling interests (Note 13) (97) (106) (165)
Decrease in lease liabilities (Note 24) (25) (21) (18)
Financing fees and other (11) (35) (31)
Change in non-cash financing working capital balances (13) —  2 
Cash flow from (used in) financing activities 272  (14) (651)
Cash flow from (used in) operating, investing, and financing activities 287  323  (225)
Effect of translation on foreign currency cash 5  (1) — 
Increase (decrease) in cash and cash equivalents 292  322  (225)
Cash and cash equivalents, beginning of year 411  89  314 
Cash and cash equivalents, end of year 703  411  89 
Cash income taxes paid 36  35  87 
Cash interest paid 201  185  188 
See accompanying notes.





TRANSALTA CORPORATION F11

Notes to Consolidated Financial Statements
1. Corporate Information
A. Description of the Business
TransAlta Corporation (“TransAlta” or the “Corporation”) was incorporated under the Canada Business Corporations Act in March 1985. The Corporation became a public company in December 1992. Its head office is located in Calgary, Alberta.

I. Generation Segments
The six generation segments of the Corporation are as follows: Hydro, Wind and Solar, North American Gas, Australian Gas, Alberta Thermal, and Centralia. The Corporation directly or indirectly owns and operates hydro, wind and solar, natural gas-fired and coal-fired facilities, related mining operations and natural gas pipeline operations in Canada, the United States (“US”) and Australia. The Wind and Solar segment includes the financial results, on a proportionate basis, of our investment in SP Skookumchuck Investment LLC. Revenues are derived from the availability and production of electricity and steam as well as ancillary services such as system support. Electricity sales made by the Corporation’s commercial and industrial group are assumed to be sourced from the Corporation’s production and have been included in the Alberta Thermal segment.

II. Energy Marketing Segment
The Energy Marketing segment derives revenue and earnings from the wholesale trading of electricity and other energy-related commodities and derivatives.

Energy Marketing manages available generating capacity as well as the fuel and transmission needs of the generation segments by utilizing contracts of various durations for the forward sales of electricity and for the purchase of natural gas and transmission capacity. Energy Marketing is also responsible for recommending portfolio optimization decisions. The results of these optimization activities are included in each generation segment.

III. Corporate and Other Segment
The Corporate and Other segment includes the Corporation’s central finance, legal, administrative, corporate development and investor relation functions. Activities and charges directly or reasonably attributable to other segments are allocated thereto. In 2020, the Corporate and Other segment also includes the investment in EMG International, LLC ("EMG"), a wastewater treatment processing company.

B. Basis of Preparation 
These consolidated financial statements have been prepared by management in compliance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

The consolidated financial statements have been prepared on a historical cost basis except for financial instruments and assets held for sale, which are measured at fair value, as explained in the following accounting policies.

These consolidated financial statements were authorized for issue by TransAlta's Board of Directors (the "Board") on March 2, 2021.

C. Basis of Consolidation 
The consolidated financial statements include the accounts of the Corporation and the subsidiaries that it controls. Control exists when the Corporation is exposed, or has rights, to variable returns from its involvement with the subsidiary and has the ability to affect the returns through its power over the subsidiary. The financial statements of the subsidiaries are prepared for the same reporting period and apply consistent accounting policies as the parent company.

2. Significant Accounting Policies
A. Revenue Recognition 
I. Revenue from Contracts with Customers
The majority of the Corporation’s revenues from contracts with customers are derived from the sale of generation capacity, electricity, thermal energy, environmental attributes and byproducts of power generation. The Corporation evaluates whether the contracts it enters into meet the definition of a contract with a customer at the inception of the contract and on an ongoing basis if there is an indication of significant changes in facts and circumstances. Revenue is measured based on the transaction price specified in a contract with a customer. Revenue is recognized when control of the good or services is transferred to the customer. For certain contracts, revenue may be recognized at the invoiced amount, as permitted using the invoice practical expedient, if such amount corresponds directly with the Corporation’s performance to date. The Corporation excludes amounts collected on behalf of third parties from revenue.
F12 TRANSALTA CORPORATION
Notes to Consolidated Financial Statements
Performance Obligations
Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Corporation’s contracts may contain more than one performance obligation.

Transaction Price
The Corporation allocates the transaction price in the contract to each performance obligation. Transaction price allocated to performance obligations may include variable consideration. Variable consideration is included in the transaction price for each performance obligation when it is highly probable that a significant reversal of the cumulative variable revenue will not occur. Variable consideration is assessed at each reporting period to determine whether the constraint is lifted. The consideration contained in some of the Corporation's contracts with customers is primarily variable, and may include both variability in quantity and pricing, such as: revenues can be dependent upon future production volumes that are driven by customer or market demand or by the operational ability of the plant; revenues can be dependent upon the variable cost of producing the energy; revenues can be dependent upon market prices; and revenues can be subject to various indices and escalators.

When multiple performance obligations are present in a contract, transaction price is allocated to each performance obligation in an amount that depicts the consideration the Corporation expects to be entitled to in exchange for transferring the good or service. The Corporation estimates the amount of the transaction price to allocate to individual performance obligations based on their relative stand-alone selling prices, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.

Recognition
The nature, timing of recognition of satisfied performance obligations and payment terms for the Corporation’s goods and services are described below:
Good or Service Description
Capacity Capacity refers to the availability of an asset to deliver goods or services. Customers typically pay for capacity for each defined time period (i.e., monthly) in an amount representative of availability of the asset for the defined time period. Obligations to deliver capacity are satisfied over time and revenue is recognized using a time-based measure. Contracts for capacity are typically long term in nature. Payments are typically received from customers on a monthly basis.
Contract Power The sale of contract power refers to the delivery of units of electricity to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (i.e., monthly). Obligations to deliver electricity are satisfied over time and revenue is recognized using a units-based output measure (i.e., megawatt hours). Contracts for power are typically long-term in nature and payments are typically received on a monthly basis.
Thermal Energy Thermal energy refers to the delivery of units of steam to a customer under the terms of a contract. Customers pay a contractually specified price for the output at the end of predefined contractual periods (i.e., monthly). Obligations to deliver steam are satisfied over time and revenue is recognized using a units-based output measure (i.e., gigajoules). Contracts for thermal energy are typically long term in nature. Payments are typically received from customers on a monthly basis.
Environmental Attributes Environmental attributes refers to the delivery of renewable energy certificates, green attributes and other similar items. Customers may contract for environmental attributes in conjunction with the purchase of power, in which case the customer pays for the attributes in the month subsequent to the delivery of the power. Alternatively, customers pay upon delivery of the environmental attributes. Obligations to deliver environmental attributes are satisfied at a point in time, generally upon delivery of the item.
Generation Byproducts Generation byproducts refers to the sale of byproducts from the use of coal in the Corporation’s Canadian and US coal operations, and the sale of coal to third parties. Obligations to deliver byproducts are satisfied at a point in time, generally upon delivery of the item. Payments are received upon satisfaction of delivery of the byproducts.

A contract liability is recorded when the Corporation receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Corporation has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Corporation recognizes unconditional rights to consideration separately as a receivable. Contract assets and receivables are evaluated at each reporting period to determine whether there is any objective evidence that they are impaired.

The Corporation recognizes a significant financing component where the timing of payment from the customer differs from the Corporation’s performance under the contract and where that difference is the result of the Corporation financing the transfer of goods and services.





TRANSALTA CORPORATION F13
Notes to Consolidated Financial Statements
II. Revenue from Other Sources
Lease Revenue
In certain situations, a long-term electricity or thermal sales contract may contain, or be considered, a lease. Revenues associated with non-lease elements are recognized as goods or services revenues as outlined above. Where the terms and conditions of the contract result in the customer assuming the principal risks and rewards of ownership of the underlying asset, the contractual arrangement is considered a finance lease, which results in the recognition of finance lease income. Where the Corporation retains the principal risks and rewards, the contractual arrangement is an operating lease. Rental income, including contingent rents where applicable, is recognized over the term of the contract.

Revenue from Derivatives
Commodity risk management activities involve the use of derivatives such as physical and financial swaps, forward sales contracts, futures contracts and options, which are used to earn revenues and to gain market information. These derivatives are accounted for using fair value accounting. The initial recognition and subsequent changes in fair value affect reported net earnings in the period the change occurs and are presented on a net basis in revenue. The fair values of instruments that remain open at the end of the reporting period represent unrealized gains or losses and are presented on the Consolidated Statements of Financial Position as risk management assets or liabilities. Some of the derivatives used by the Corporation in trading activities are not traded on an active exchange or have terms that extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using internal valuation techniques or models.

B. Foreign Currency Translation 
The Corporation, its subsidiary companies and joint arrangements each determine their functional currency based on the currency of the primary economic environment in which they operate. The Corporation’s functional currency is the Canadian dollar, while the functional currencies of its subsidiary companies and joint arrangements are the Canadian, US or Australian dollar. Transactions denominated in a currency other than the functional currency of an entity are translated at the exchange rate in effect on the transaction date. The resulting exchange gains and losses are included in each entity’s net earnings in the period in which they arise.

The Corporation’s foreign operations are translated to the Corporation’s presentation currency, which is the Canadian dollar, for inclusion in the consolidated financial statements. Foreign-denominated monetary and non-monetary assets and liabilities of foreign operations are translated at exchange rates in effect at the end of the reporting period, and revenue and expenses are translated at exchange rates in effect on the transaction date. The resulting translation gains and losses are included in other comprehensive income (loss) (“OCI”) with the cumulative gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”). Amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in a foreign net investment as a result of a disposal, partial disposal or loss of control.

C. Financial Instruments and Hedges
I. Financial Instruments

Classification and Measurement
IFRS 9 introduced the requirement to classify and measure financial assets based on their contractual cash flow characteristics and the Corporation’s business model for the financial asset. All financial assets and financial liabilities, including derivatives, are recognized at fair value on the Consolidated Statements of Financial Position when the Corporation becomes party to the contractual provisions of a financial instrument or non-financial derivative contract. Financial assets must be classified and measured at either amortized cost, at fair value through profit or loss (“FVTPL”), or at fair value through other comprehensive income (“FVOCI”).

Financial assets with contractual cash flows arising on specified dates, consisting solely of principal and interest, and that are held within a business model whose objective is to collect the contractual cash flows are subsequently measured at amortized cost. Financial assets measured at FVOCI are those that have contractual cash flows arising on specific dates, consisting solely of principal and interest, and that are held within a business model whose objective is to collect the contractual cash flows and to sell the financial asset. All other financial assets are subsequently measured at FVTPL.

Financial liabilities are classified as FVTPL when the financial liability is held for trading. All other financial liabilities are subsequently measured at amortized cost.

Funds received under tax equity investment arrangements are classified as long-term debt. These arrangements are used in the US where project investors acquire an equity investment in the project entity and in return for their investment, are allocated substantially all of the earnings, cash flows and tax benefits (such as production tax credits, investment tax credits, accelerated tax depreciation, as applicable) until they have achieved the agreed upon target rate of return. Once achieved, the arrangements flip, with the Corporation then receiving the majority of earnings, cash flows and tax benefits. At that time, the tax equity financings will be classified as a non-controlling interest. In applying the




TRANSALTA CORPORATION F14
Notes to Consolidated Financial Statements
effective interest method to tax equity financings, the Corporation has made an accounting policy choice to recognize the impacts of the tax attributes in net interest expense.

The Corporation enters into a variety of derivative financial instruments to manage its exposure to commodity price risk, interest rate risk and foreign currency exchange risk, including fixed price financial swaps, long-term physical power sale contracts, foreign exchange forward contracts and designating foreign currency debt as a hedge of net investments in foreign operations.

Derivatives are initially recognized at fair value at the date the derivative contracts are entered into and are subsequently remeasured to their fair value at the end of each reporting period. The resulting gain or loss is recognized in net earnings immediately, unless the derivative is designated and effective as a hedging instrument, in which case the timing of the recognition in net earnings is dependent on the nature of the hedging relationship.

Derivatives embedded in non-derivative host contracts that are not financial assets within the scope of IFRS 9 (e.g., financial liabilities) are treated as separate derivatives when they meet the definition of a derivative, their risks and characteristics are not closely related to those of the host contracts and the host contracts are not measured at FVTPL. Derivatives embedded in hybrid contracts that contain financial asset hosts within the scope of IFRS 9 are not separated and the entire contract is measured at either FVTPL or amortized cost, as appropriate.

Financial assets are derecognized when the contractual rights to receive cash flows expire. Financial liabilities are derecognized when the obligation is discharged, cancelled or expired.

Financial assets are also derecognized when the Corporation has transferred its rights to receive cash flows from the asset or has assumed an obligation to pay the received cash flows to a third party under a "pass-through" arrangement and either transferred substantially all the risks and rewards of the asset, or transferred control of the asset. TransAlta will continue to recognize the asset and any associated liability if TransAlta retains substantially all of the risks and rewards of the asset, or retains control of the asset. Continuing involvement that takes the form of a guarantee over the transferred asset is measured at the lower of the original carrying amount of the asset and the maximum amount of consideration that TransAlta could be required to repay.

Financial assets and financial liabilities are offset and the net amount is reported in the Consolidated Statements of Financial Position if there is a currently enforceable legal right to offset the recognized amounts and there is an intention to settle on a net basis or to realize the assets and settle the liabilities simultaneously.

Transaction costs are expensed as incurred for financial instruments classified or designated as FVTPL. For other financial instruments, such as debt instruments, transaction costs are recognized as part of the carrying amount of the financial instrument. The Corporation uses the effective interest method of amortization for any transaction costs or fees, premiums or discounts earned or incurred for financial instruments measured at amortized cost.

Impairment of Financial Assets
TransAlta recognizes an allowance for expected credit losses for financial assets measured at amortized cost as well as certain other instruments. The loss allowance for a financial asset is measured at an amount equal to the lifetime expected credit loss if its credit risk has increased significantly since initial recognition or if the financial asset is a purchased or originated credit-impaired financial asset. If the credit risk on a financial asset has not increased significantly since initial recognition, its loss allowance is measured at an amount equal to the 12-month expected credit loss.

For trade receivables, lease receivables and contract assets recognized under IFRS 15, TransAlta applies a simplified approach for measuring the loss allowance. Therefore, the Corporation does not track changes in credit risk but instead recognizes a loss allowance at an amount equal to the lifetime expected credit losses at each reporting date.

The assessment of the expected credit loss is based on historical data and adjusted by forward-looking information. Forward-looking information utilized includes third-party default rates over time, dependent on credit ratings.

II. Hedges
Where hedge accounting can be applied and the Corporation chooses to seek hedge accounting treatment, a hedge relationship is designated as a fair value hedge, a cash flow hedge or a hedge of foreign currency exposures of a net investment in a foreign operation.

A relationship qualifies for hedge accounting if, at inception, it is formally designated and documented as a hedge, and the hedging instrument and the hedged item have values that generally move in opposite direction because of the hedged risk. The documentation includes identification of the hedging instrument and hedged item or transaction, the nature of the risk being hedged, the Corporation’s risk management objectives and strategy for undertaking the hedge, and how hedge effectiveness will be assessed. The process of hedge accounting includes linking derivatives to specific recognized assets and liabilities or to specific firm commitments or highly probable anticipated transactions.




TRANSALTA CORPORATION F15
Notes to Consolidated Financial Statements

The Corporation formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives used are highly effective in offsetting changes in fair values or cash flows of hedged items. If hedge criteria are not met or the Corporation does not apply hedge accounting, the derivative is recognized at fair value on the Consolidated Statements of Financial Position, with subsequent changes in fair value recorded in net earnings in the period of change.

Fair Value Hedges
In a fair value hedging relationship, the carrying amount of the hedged item is adjusted for changes in fair value attributable to the hedged risk, with the changes being recognized in net earnings. 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 derivative, which is also recorded in net earnings.

For fair value hedges relating to items carried at amortized cost, any adjustment to carrying value is amortized through profit or loss over the remaining term of the hedge using the effective interest rate ("EIR") method. The EIR amortization may begin as soon as an adjustment exists and no later than when the hedged item ceases to be adjusted for changes in its fair value attributable to the risk being hedged.

If the hedged item is derecognized, the unamortized fair value is recognized immediately in profit or loss.

Cash Flow Hedges
In a cash flow hedging relationship, the effective portion of the change in the fair value of the hedging derivative is recognized in OCI while any ineffective portion is recognized in net earnings. The cash flow hedge reserve is adjusted to the lower of the cumulative gain or loss on the hedging instrument and the cumulative change in fair value of the hedged item.

If cash flow hedge accounting is discontinued, the amounts previously recognized in AOCI must remain in AOCI if the hedged future cash flows are still expected to occur. Otherwise, the amount will be immediately reclassified to net earnings as a reclassification adjustment. After discontinuation, once the hedged cash flow occurs, any amount remaining in AOCI must be accounted for depending on the nature of the underlying transaction.

Hedges of Foreign Currency Exposures of a Net Investment in a Foreign Operation
In hedging a foreign currency exposure of a net investment in a foreign operation, the effective portion of foreign exchange gains and losses on the hedging instrument is recognized in OCI and the ineffective portion is recognized in net earnings. The related fair values are recorded in risk management assets or liabilities, as appropriate. The amounts previously recognized in AOCI are recognized in net earnings when there is a reduction in the hedged net investment as a result of a disposal, partial disposal or loss of control.

D. Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less.

E. Collateral Paid and Received
The terms and conditions of certain contracts may require the Corporation or its counterparties to provide collateral when the fair value of the obligation pursuant to these contracts is in excess of any credit limits granted. Downgrades in creditworthiness by certain credit rating agencies may decrease the credit limits granted to the Corporation or its counterparties and accordingly increase the amount of collateral that may have to be provided by the Corporation or its counterparties.

F. Inventory
I. Fuel
The Corporation’s inventory balance is comprised of coal and natural gas used as fuel, which is measured at the lower of weighted average cost and net realizable value.

The cost of internally produced coal inventory is determined using absorption costing, which is defined as the sum of all applicable expenditures and charges directly incurred in bringing inventory to its existing condition and location. Available coal inventory tends to increase during the second and third quarters as a result of favourable weather conditions and lower electricity production as maintenance is performed. Due to the limited number of processing steps incurred in mining coal and preparing it for consumption and its relatively low value on a per-unit basis, management does not distinguish between work in process and coal available for consumption. The cost of natural gas and purchased coal inventory includes all applicable expenditures and charges incurred in bringing the inventory to its existing condition and location.





TRANSALTA CORPORATION F16
Notes to Consolidated Financial Statements
II. Energy Marketing
Commodity inventories held in the Energy Marketing segment for trading purposes are measured at fair value less costs to sell. Changes in fair value less costs to sell are recognized in net earnings in the period of change.

III. Parts, Materials and Supplies
Parts, materials and supplies are recorded at the lower of cost, measured at moving average costs, and net realizable value.

IV. Emission Credits and Allowances
Emission credits and allowances are recorded as inventory at cost. Those purchased for use by the Corporation are recorded at cost and are carried at the lower of weighted average cost and net realizable value. For emission credits that are not ordinarily interchangeable, the Corporation records the credits using the specific identification method. Credits granted to, or internally generated by, TransAlta are recorded at nil. Emission liabilities are recorded using the best estimate of the amount required by the Corporation to settle its obligation in excess of government-established caps and targets. To the extent compliance costs are recoverable under the terms of contracts with third parties, the amounts are recognized as revenue in the period of recovery.

Emission credits and allowances that are held for trading and that meet the definition of a derivative are accounted for using the fair value method of accounting. Emission credits and allowances that do not satisfy the criteria of a derivative are accounted for using the accrual method.

G. Property, Plant and Equipment
The Corporation’s investment in property, plant and equipment (“PP&E”) is initially measured at the original cost of each component at the time of construction, purchase or acquisition. A component is a tangible portion of an asset that can be separately identified and depreciated over its own expected useful life, and is expected to provide a benefit for a period in excess of one year. Original cost includes items such as materials, labour, borrowing costs and other directly attributable costs, including the initial estimate of the cost of decommissioning and restoration. Costs are recognized as PP&E assets if it is probable that future economic benefits will be realized and the cost of the item can be measured reliably. The cost of major spare parts is capitalized and classified as PP&E, as these items can only be used in connection with an item of PP&E.

Planned maintenance is performed at regular intervals. Planned major maintenance includes inspection, repair and maintenance of existing components, and the replacement of existing components. Costs incurred for planned major maintenance activities are capitalized in the period maintenance activities occur and are amortized on a straight-line basis over the term until the next major maintenance event. Expenditures incurred for the replacement of components during major maintenance are capitalized and amortized over the estimated useful life of such components.

The cost of routine repairs and maintenance and the replacement of minor parts is charged to net earnings as incurred. Subsequent to initial recognition and measurement at cost, all classes of PP&E continue to be measured using the cost model and are reported at cost less accumulated depreciation and impairment losses, if any.

An item of PP&E or a component is derecognized upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on derecognition is included in net earnings when the asset is derecognized.

The estimate of the useful life of each component of PP&E is based on current facts and past experience, and takes into consideration existing long-term sales agreements and contracts, current and forecasted demand, and the potential for technological obsolescence. The useful life is used to estimate the rate at which the component of PP&E is depreciated. PP&E assets are subject to depreciation when the asset is considered to be available for use, which is typically upon commencement of commercial operations. Capital spares that are designated as critical for uninterrupted operation in a particular facility are depreciated over the life of that facility, even if the item is not in service. Other capital spares begin to be depreciated when the item is put into service. Each significant component of an item of PP&E is depreciated to its residual value over its estimated useful life, generally using straight-line or unit-of-production methods. Estimated useful lives, residual values and depreciation methods are reviewed annually and are subject to revision based on new or additional information. The effect of a change in useful life, residual value or depreciation method is accounted for prospectively.





TRANSALTA CORPORATION F17
Notes to Consolidated Financial Statements
Estimated remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows:
Hydro generation
1-52 years
Wind generation
1-29 years
Gas generation
1-17 years
Coal generation
1-29 years
Mining property and equipment
1-9 years
Capital spares and other
2-52 years

TransAlta capitalizes borrowing costs on capital invested in projects under construction (see Note 2(R)). Upon commencement of commercial operations, capitalized borrowing costs, as a portion of the total cost of the asset, are depreciated over the estimated useful life of the related asset.

H. Intangible Assets
Intangible assets acquired in a business combination are recognized separately from goodwill at their fair value at the date of acquisition. Intangible assets acquired separately are recognized at cost. Internally generated intangible assets arising from development projects are recognized when certain criteria related to the feasibility of internal use or sale, and probable future economic benefits of the intangible asset, are demonstrated.

Intangible assets are initially recognized at cost, which is comprised of all directly attributable costs necessary to create, produce and prepare the intangible asset to be capable of operating in the manner intended by management. 

Subsequent to initial recognition, intangible assets continue to be measured using the cost model, and are reported at cost less accumulated amortization and impairment losses, if any. Amortization is included in depreciation and amortization and fuel, carbon compliance and purchased power in the Consolidated Statements of Earnings (Loss).

Amortization commences when the intangible asset is available for use and is computed on a straight-line basis over the intangible asset’s estimated useful life, except for coal rights, which are amortized using a unit-of-production basis, based on the estimated mine reserves. Estimated useful lives of intangible assets may be determined, for example, with reference to the term of the related contract or licence agreement. The estimated useful lives and amortization methods are reviewed annually with the effect of any changes being accounted for prospectively.

Intangible assets consist of power sale contracts with fixed prices higher than market prices at the date of acquisition, coal rights, software and intangibles under development. Estimated remaining useful lives of intangible assets are as follows:
Software
2-7 years
Power sale contracts
1-20 years

I. Impairment of Tangible and Intangible Assets Excluding Goodwill
At the end of each reporting period, the Corporation assesses whether there is any indication that PP&E and finite life intangible assets are impaired.

Factors that could indicate that an impairment exists include: significant underperformance relative to historical or projected operating results; significant changes in the manner in which an asset is used, or in the Corporation’s overall business strategy; or significant negative industry or economic trends. In some cases, these events are clear. However, in many cases, a clearly identifiable event indicating possible impairment does not occur. Instead, a series of individually insignificant events occur over a period of time leading to an indication that an asset may be impaired. This can be further complicated in situations where the Corporation is not the operator of the facility. Events can occur in these situations that may not be known until a date subsequent to their occurrence.

The Corporation’s operations, the market and business environment are routinely monitored, and judgments and assessments are made to determine whether an event has occurred that indicates a possible impairment. If such an event has occurred, an estimate is made of the recoverable amount of the asset or “CGU” to which the asset belongs. Recoverable amount is the higher of an asset’s fair value less costs of disposal and its value in use. Fair value is the price that would be received to sell an asset in an orderly transaction between market participants at the measurement date. In determining fair value, recent market transactions are taken into account. If no such transactions can be identified, an appropriate valuation model such as discounted cash flows is used. Value in use is the present value of the estimated future cash flows expected to be derived from the asset from its continued use and ultimate disposal by the Corporation. If the recoverable amount is less than the carrying amount of the asset or CGU, an asset impairment charge is recognized in net earnings, and the asset’s carrying amount is reduced to its recoverable amount.




TRANSALTA CORPORATION F18
Notes to Consolidated Financial Statements

At each reporting date, an assessment is made whether there is any indication that an impairment charge previously recognized may no longer exist or may have decreased. If such indication exists, the recoverable amount of the asset or CGU to which the asset belongs is estimated, and, if there has been an increase in the recoverable amount, the impairment charge previously recognized is reversed. Where an impairment charge is subsequently reversed, the carrying amount of the asset is increased to the lesser of the revised estimate of its recoverable amount or the carrying amount that would have been determined (net of depreciation) had no impairment charge been recognized previously. A reversal of an impairment charge is recognized in net earnings. 

J. Goodwill
Goodwill arising in a business combination is recognized as an asset at the date control is acquired. Goodwill is measured as the cost of an acquisition plus the amount of any non-controlling interest in the acquiree (if applicable) less the fair value of the related identifiable assets acquired and liabilities assumed.

Goodwill is not subject to amortization, but is tested for impairment at least annually, or more frequently, if an analysis of events and circumstances indicates that a possible impairment may exist. These events could include a significant change in financial position of the CGUs or groups of CGUs to which the goodwill relates or significant negative industry or economic trends. For impairment purposes, goodwill is allocated to each of the Corporation’s CGUs or groups of CGUs that are expected to benefit from the synergies of the business combination in which the goodwill arose. To test for impairment, the recoverable amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount. If the recoverable amount is less than the carrying amount, an impairment charge is recognized in net earnings immediately, by first reducing the carrying amount of the goodwill, and then by reducing the carrying amount of the other assets in the unit. An impairment charge recognized for goodwill is not reversed in subsequent periods.

K. Project Development Costs
Project development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. These costs are recognized as operating expenses until construction of a plant or acquisition of an investment is likely to occur, there is reason to believe that future costs are recoverable, and that efforts will result in future value to the Corporation, at which time the costs incurred subsequently are included in PP&E or other assets. The appropriateness of capitalization of these costs is evaluated each reporting period, and amounts capitalized for projects no longer probable of occurring are charged to net earnings.

L. Income Taxes
The Corporation uses the liability method of accounting for income taxes. Under the liability method, deferred income tax assets and liabilities are recognized on the differences between the carrying amounts of assets and liabilities and their respective income tax basis (temporary differences). A deferred income tax asset may also be recognized for the benefit expected from unused tax credits and losses available for carryforward, to the extent that it is probable that future taxable earnings will be available against which the tax credits and losses can be applied. Deferred income tax assets and liabilities are measured based on income tax rates and tax laws that are enacted or substantively enacted by the end of the reporting period and that are expected to apply in the years in which temporary differences are expected to be realized or settled. Deferred income tax is charged or credited to net earnings, except when related to items charged or credited to either OCI or directly to equity. The carrying amount of deferred income tax assets is evaluated at the end of each reporting period and is reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be realized. Unrecognized deferred tax assets are re-assessed at each reporting date and are recognised to the extent that it has become probable that future taxable income will allow the deferred income tax asset to be recovered.

Deferred income tax liabilities are recognized for taxable temporary differences arising on investments in subsidiaries, except where the Corporation is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. 

M. Employee Future Benefits
The Corporation has defined benefit pension and other post-employment benefit plans. The current service cost of providing benefits under the defined benefit plans is determined using the projected unit credit method pro-rated based on service. The net interest cost is determined by applying the discount rate to the net defined benefit liability. The discount rate used to determine the present value of the defined benefit obligation, and the net interest cost, is determined by reference to market yields at the end of the reporting period on high-quality corporate bonds with terms and currencies that match the estimated terms and currencies of the benefit obligations. Remeasurements, which include actuarial gains and losses and the return on plan assets (excluding net interest), are recognized through OCI in the period in which they occur. Actuarial gains and losses arise from experience adjustments and changes in actuarial assumptions. Remeasurements are not reclassified to profit or loss, from OCI, in subsequent periods.





TRANSALTA CORPORATION F19
Notes to Consolidated Financial Statements
Gains or losses arising from either a curtailment or settlement of a defined benefit plan are recognized when the curtailment or settlement occurs. When the restructuring of a benefit plan gives rise to a curtailment and a settlement of obligations, the curtailment is accounted for prior to the settlement.

In determining whether statutory minimum funding requirements of the Corporation’s defined benefit pension plans give rise to recording an additional liability, letters of credit provided by the Corporation as security are considered to alleviate the funding requirements. No additional liability results in these circumstances.

Contributions payable under defined contribution pension plans are recognized as a liability and an expense in the period in which the services are rendered.

N. Provisions
Provisions are recognized when the Corporation has a present obligation (legal or constructive) as a result of a past event, it is probable that the Corporation will be required to settle the obligation, and a reliable estimate can be made of the amount of the obligation. A legal obligation can arise through a contract, legislation or other operation of law. A constructive obligation arises from an entity’s actions whereby through an established pattern of past practice, published policies or a sufficiently specific current statement, the entity has indicated it will accept certain responsibilities and has thus created a valid expectation that it will discharge those responsibilities. The amount recognized as a provision is the best estimate, remeasured at each period-end, of the expenditures required to settle the present obligation, considering the risks and uncertainties associated with the obligation. Where expenditures are expected to be incurred in the future, the obligation is measured at its present value using a current market-based, risk-adjusted interest rate.

The Corporation records a decommissioning and restoration provision for all generating facilities and mine sites for which it is legally or constructively required to remove the facilities at the end of their useful lives and restore the plant or mine sites. For some hydro facilities, the Corporation is required to remove the generating equipment, but is not required to remove the structures. Initial decommissioning provisions are recognized at their present value when incurred. Each reporting date, the Corporation determines the present value of the provision using the current discount rates that reflect the time value of money and associated risks. The Corporation recognizes the initial decommissioning and restoration provisions, as well as changes resulting from revisions to cost estimates and period-end revisions to the market-based, risk-adjusted discount rate, as a cost of the related PP&E (see Note 2(G)) to the extent the related PP&E asset is still in use. Where the related PP&E asset has reached the end of its useful life, changes in the decommissioning and restoration provision are recognized in net earnings. The accretion of the net present value discount is charged to net earnings each period and is included in net interest expense. Where the Corporation expects to receive reimbursement from a third party for a portion of future decommissioning costs, the reimbursement is recognized as a separate asset when it is virtually certain that the reimbursement will be received. Decommissioning and restoration obligations for coal mines are incurred over time as new areas are mined, and a portion of the provision is settled over time as areas are reclaimed prior to final pit reclamation. Reclamation costs for mining assets are recognized on a unit-of-production basis.

Changes in other provisions resulting from revisions to estimates of expenditures required to settle the obligation or period-end revisions to the market-based, risk-adjusted discount rate are recognized in net earnings. The accretion of the net present value discount is charged to net earnings each period and is included in net interest expense.

O. Share-Based Payments
The Corporation measures share-based awards compensation expense at grant date at fair value and recognizes the expense over the vesting period based on the Corporation’s estimate of the number of units that will eventually vest. Any award that vests in installments is accounted for as a separate award with its own distinct fair value measurement.

Compensation expense associated with equity-settled and cash-settled awards are recognized within equity and liability, respectively. The liability associated with cash-settled awards is remeasured to fair value at each reporting date up to, and including, the settlement date, with changes in fair value recognized within compensation expense.

P. Assets Held for Sale 
Assets are classified as held for sale if their carrying amount will be recovered primarily through a sale as opposed to continued use by the Corporation. Assets classified as held for sale are measured at the lower of their carrying amount and fair value less costs of disposal. Any impairment is recognized in net earnings. Depreciation and equity accounting ceases when an asset or equity investment, respectively, is classified as held for sale. Assets classified as held for sale are reported as current assets in the Consolidated Statements of Financial Position.






TRANSALTA CORPORATION F20
Notes to Consolidated Financial Statements
Q. Leases 
I. Lease Policy for 2019 and 2020
The Corporation adopted IFRS 16 Leases ("IFRS 16") with an initial adoption date of Jan. 1, 2019. As a result, in 2019, the Corporation changed its accounting policy for leases, which is outlined below. Refer to (II) below for information on the prior accounting policy.

Under IFRS 16, a contract contains a lease when the customer obtains the right to control the use of an identified asset for a period of time in exchange for consideration.

Lessee
The Corporation enters into lease arrangements with respect to land, building and office space, vehicles and site machinery and equipment. For all contracts that meet the definition of a lease under IFRS 16 in which the Corporation is the lessee, and which are not exempt as short-term or low-value leases, the Corporation:
▪Recognizes right-of-use assets and lease liabilities in the Consolidated Statements of Financial Position;
▪Recognizes depreciation of the right-of-use assets and interest expense on lease liabilities in the Consolidated Statements of Earnings (Loss); and
▪Recognizes the principal repayments on lease liabilities as financing activities and interest payments on lease liabilities as operating activities in the Consolidated Statements of Cash Flows.

For short-term and low-value leases, the Corporation recognizes the lease payments as operating expenses.

Variable lease payments that do not depend on an index or a rate are not included in the measurement of the lease liability and the right-of-use asset and are recognized as an expense in the period in which the event or condition that triggers the payments occurs.

Right-of-use assets are initially measured at an amount equal to the lease liability and adjusted for any payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset, or to restore the underlying asset or the site on which it is located, less any lease incentives received.

Lease liabilities are initially measured at the present value of the lease payments that are not paid at commencement and discounted using the Corporation's incremental borrowing rate or the rate implicit in the lease. The lease liability is remeasured when there is a change in future lease payments arising from a change in an index or rate, or if there is a change in the Corporation’s estimate or assessment of whether it will exercise an extension, termination or purchase option. A corresponding adjustment is made to the carrying amount of the right-of-use asset, or is recorded in profit or loss if the carrying amount of the right-of-use asset has been reduced to zero.

The lease term includes periods covered by an option to extend if the Corporation is reasonably certain to exercise that option and periods covered by an option to terminate if the Corporation is reasonably certain not to exercise that option.

Right-of-use assets are depreciated over the shorter period of either the lease term or the useful life of the underlying asset. If a lease transfers ownership of the underlying asset or the cost of the right-of-use asset reflects that the Corporation expects to exercise the purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset.

The Corporation has elected to apply the practical expedient that permits a lessee not to separate non-lease components, and instead account for any lease and associated non-lease components as a single arrangement.
Lessor
Power purchase agreements (“PPA”) and other long-term contracts may contain, or may be considered, leases where the fulfilment of the arrangement is dependent on the use of a specific asset (e.g., a generating unit) and the arrangement conveys to the customer the right to control the use of that asset.

Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the customer assuming the principal risks and rewards of ownership of the asset, the arrangement is a finance lease. Assets subject to finance leases are not reflected as PP&E and the net investment in the lease, represented by the present value of the amounts due from the lessee, is recorded in the Consolidated Statements of Financial Position as a financial asset, classified as a finance lease receivable. The payments considered to be part of the leasing arrangement are apportioned between a reduction in the lease receivable and finance lease income. The finance lease income element of the payments




TRANSALTA CORPORATION F21
Notes to Consolidated Financial Statements
is recognized using a method that results in a constant rate of return on the net investment in each period and is reflected in finance lease income on the Consolidated Statements of Earnings (Loss).

Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the Corporation retaining the principal risks and rewards of ownership of the asset, the arrangement is an operating lease. For operating leases, the asset is, or continues to be, capitalized as PP&E and depreciated over its useful life.

When the Corporation has subleased all or a portion of an asset it is leasing and for which it remains the primary obligor under the lease, it accounts for the head lease and the sublease as two separate contracts. The sublease is classified as a finance lease by reference to the right-of-use asset arising from the head lease.

II. Lease Policy Prior to 2019
A lease is an arrangement whereby the lessor conveys to the lessee, in return for a payment or series of payments, the right to use an asset for an agreed period of time. 

PPA and other long-term contracts may contain, or may be considered, leases where the fulfilment of the arrangement is dependent on the use of a specific asset (e.g., a generating unit) and the arrangement conveys to the customer the right to use that asset.

Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the customer assuming the principal risks and rewards of ownership of the asset, the arrangement is a finance lease. Assets subject to finance leases are not reflected as PP&E and the net investment in the lease, represented by the present value of the amounts due from the lessee, is recorded in the Consolidated Statements of Financial Position as a financial asset, classified as a finance lease receivable. The payments considered to be part of the leasing arrangement are apportioned between a reduction in the lease receivable and finance lease income. The finance lease income element of the payments is recognized using a method that results in a constant rate of return on the net investment in each period and is reflected in finance lease income on the Consolidated Statements of Earnings (Loss).

Where the Corporation determines that the contractual provisions of a contract contain, or are, a lease and result in the Corporation retaining the principal risks and rewards of ownership of the asset, the arrangement is an operating lease. For operating leases, the asset is, or continues to be, capitalized as PP&E and depreciated over its useful life. Rental income, including contingent rent, from operating leases is recognized over the term of the arrangement and is reflected in revenue on the Consolidated Statements of Earnings (Loss). Contingent rent may arise when payments due under the contract are not fixed in amount but vary based on a future factor such as the amount of use or production.

Leasing or other contractual arrangements that transfer substantially all of the risks and rewards of ownership to the Corporation are considered finance leases. A leased asset and lease obligation are recognized at the lower of the fair value or the present value of the minimum lease payments. Lease payments are apportioned between interest expense and a reduction of the lease liability. Contingent rents are charged as expenses in the periods incurred. The leased asset is depreciated over the shorter of the estimated useful life of the asset and the lease term.

R. Borrowing Costs 
The Corporation capitalizes borrowing costs that are directly attributable to, or relate to general borrowings used for, the construction of qualifying assets. Qualifying assets are assets that take a substantial period of time to prepare for their intended use and typically include generating facilities or other assets that are constructed over periods of time exceeding 12 months. Borrowing costs are considered to be directly attributable if they could have been avoided if the expenditure on the qualifying asset had not been made. Borrowing costs that are capitalized are included in the cost of the related PP&E component. Capitalization of borrowing costs ceases when substantially all the activities necessary to prepare the asset for its intended use are complete. 

All other borrowing costs are expensed in the period in which they are incurred.

S. Non-Controlling Interests 
Non-controlling interests arise from business combinations in which the Corporation acquires less than a 100 per cent interest. Non-controlling interests are initially measured at either fair value or at the non-controlling interest’s proportionate share of the acquiree’s identifiable net assets. The Corporation determines on a transaction-by-transaction basis which measurement method is used. Non-controlling interests also arise from other contractual arrangements between the Corporation and other parties, whereby the other party has acquired an interest in a specified asset or operation, and the Corporation retains control.

Subsequent to acquisition, the carrying amount of non-controlling interests is increased or decreased by the non-controlling interest’s share of subsequent changes in equity and payments to the non-controlling interest. Total comprehensive income is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.




TRANSALTA CORPORATION F22
Notes to Consolidated Financial Statements

T. Joint Arrangements 
A joint arrangement is a contractual arrangement that establishes the terms by which two or more parties agree to undertake and jointly control an economic activity. The Corporation's joint arrangements are generally classified as two types: joint operations and joint ventures.

A joint operation arises when the parties that have joint control have rights to the assets and obligations for the liabilities relating to the arrangement. Generally, each party takes a share of the output from the asset and each bears an agreed upon share of the costs incurred in respect of the joint operation. The Corporation reports its interests in joint operations in its consolidated financial statements using the proportionate consolidation method by recognizing its share of the assets, liabilities, revenues and expenses in respect of its interest in the joint operation.

In a joint venture, the venturers do not have rights to individual assets or obligations of the venture. Rather, each venturer has rights to the net assets of the arrangement. The Corporation reports its interests in joint ventures using the equity method. Under the equity method, the investment is initially recognized at cost and the carrying amount is increased or decreased to recognize the Corporation’s share of the joint venture’s net earnings or loss after the date of acquisition. The impact of transactions between the Corporation and joint ventures is eliminated based on the Corporation’s ownership interest. Distributions received from joint ventures reduce the carrying amount of the investment. Any excess of the cost of an acquisition less the fair value of the recognized identifiable assets, liabilities and contingent liabilities of an acquired joint venture is recognized as goodwill and is included in the carrying amount of the investment and is assessed for impairment as part of the investment.

Investments in joint ventures are evaluated for impairment at each reporting date by first assessing whether there is objective evidence that the investment is impaired. If such objective evidence is present, an impairment charge is recognized if the investment’s recoverable amount is less than its carrying amount. The investment’s recoverable amount is determined as the higher of value in use and fair value less costs of disposal. 

U. Investments in Associates 
Associates are entities over which the Corporation has significant influence. Significant influence is the power to participate in financial and operating policy decisions of the entity, but is not control or joint control over the policies. Significant influence is generally present when an investor holds more than 20 per cent of the voting power of the investee.

Investments in associates are accounted for using the equity method of accounting. Under the equity method, the investment is initially recognized at cost and the carrying amount is increased or decreased to recognize the Corporation’s share of the associate’s net earnings or loss after the date of acquisition. The Corporation’s share of the associate’s net earnings or loss is recognized in net earnings. Distributions received from the associate reduce the carrying amount of the investment

Investments in associates are evaluated for impairment at each reporting date by first assessing whether there is objective evidence that the investment is impaired. If such objective evidence is present, an impairment charge is recognized if the investment’s recoverable amount is less than its carrying amount. The investment’s recoverable amount is determined as the higher of value in use and fair value less costs of disposal. Any impairment loss is recognized within equity income in the statement of earnings.

V. Government Incentives 
Government incentives are recognized when the Corporation has reasonable assurance that it will comply with the conditions associated with the incentive and that the incentive will be received. When the incentive relates to an expense item, it is recognized in net earnings over the same period in which the related costs or revenues are recognized. When the incentive relates to an asset, it is recognized as a reduction of the carrying amount of PP&E and released to earnings as a reduction in depreciation over the expected useful life of the related asset.

W. Earnings per Share 
Basic earnings per share is calculated by dividing net earnings attributable to common shareholders by the weighted average number of common shares outstanding in the year.

Diluted earnings per share is calculated by dividing net earnings attributable to common shareholders, adjusted for the after-tax effects of dividends, interest or other changes in net earnings that would result from potential dilutive instruments, by the weighted average number of common shares outstanding in the year, adjusted for additional common shares that would have been issued on the conversion of all potential dilutive instruments.






TRANSALTA CORPORATION F23
Notes to Consolidated Financial Statements
X. Business Combinations 
Transactions in which the acquisition constitutes a business are accounted for using the acquisition method. Identifiable assets acquired and liabilities assumed are measured at their acquisition date fair values. A business consists of inputs and processes applied to those inputs that have the ability to contribute to the creation of outputs. Goodwill is measured as the excess of the fair value of consideration transferred less the fair value of the identifiable assets acquired and liabilities assumed. Acquisition-related costs to effect the business combination, with the exception of costs to issue debt or equity securities, are recognized in net earnings as incurred.

In 2019, the Corporation early-adopted amendments to IFRS 3 Business Combinations in advance of the mandatory effective date of Jan. 1, 2020. The amendments, among other things, introduced an optional fair value concentration test that can be applied on a transaction-by-transaction basis, to permit a simplified assessment of whether an acquired set of activities and assets are not a business. Where substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets, the Corporation may elect to treat the acquisition as an asset acquisition and not as a business combination.

Y. Stripping Costs 
A mine stripping activity asset is recognized when all of the following are met: i) it is probable that the future benefit associated with improved access to the coal reserves associated with the stripping activity will be realized; ii) the component of the coal reserve to which access has been improved can be identified; and iii) the costs related to the stripping activity associated with that component can be measured reliably. Costs include those directly incurred to perform the stripping activity as well as an allocation of directly attributable overheads. The resulting stripping activity asset is amortized on a unit-of-production basis over the expected useful life of the identified component that it relates to. The amortization is recognized as a component of the standard cost of coal inventory. 

Z. Significant Accounting Judgments and Key Sources of Estimation Uncertainty 
The preparation of financial statements requires management to make judgments, estimates and assumptions that could affect the reported amounts of assets, liabilities, revenues, expenses and disclosures of contingent assets and liabilities during the period. These estimates are subject to uncertainty. Actual results could differ from those estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic conditions, legislation and regulations.

In the process of applying the Corporation’s accounting policies, management has to make judgments and estimates about matters that are highly uncertain at the time the estimate is made and that could significantly affect the amounts recognized in the consolidated financial statements. Different estimates with respect to key variables used in the calculations, or changes to estimates, could potentially have a material impact on the Corporation’s financial position or performance. The key judgments and sources of estimation uncertainty are described below:

I. COVID-19
The outbreak of the novel strain of coronavirus ("COVID-19") has resulted in governments worldwide enacting emergency measures to constrain the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods, self-isolation, physical and social distancing and the closure of non-essential businesses, have caused significant disruption to businesses globally, which has resulted in an uncertain and challenging economic environment. The duration and impact of the COVID-19 pandemic are unknown at this time. Estimates to the extent to which the COVID-19 pandemic may, directly or indirectly, impact the Corporation's operations, financial results and conditions in future periods are also subject to significant uncertainty. For a description of additional risks identified as a result of the pandemic, refer to Note 16. Actual results could differ from these estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic conditions, legislation and regulations.

II. Impairment of PP&E and Goodwill
Impairment exists when the carrying amount of an asset, CGU or group of CGUs to which goodwill relates exceeds its recoverable amount, which is the higher of its fair value less costs of disposal and its value in use. An assessment is made at each reporting date as to whether there is any indication that an impairment charge may exist or that a previously recognized impairment charge may no longer exist or may have decreased. In determining fair value less costs of disposal, information about third-party transactions for similar assets is used and if none is available, other valuation techniques, such as discounted cash flows, are used. Value in use is computed using the present value of management’s best estimates of future cash flows based on the current use and present condition of the asset.

In estimating either fair value less costs of disposal or value in use using discounted cash flow methods, estimates and assumptions must be made about sales prices, cost of sales, production, fuel consumed, capital expenditures, retirement costs and other related cash inflows and outflows over the life of the facilities, which can range from 30 to 60 years. In developing these assumptions, management uses estimates of contracted and future market prices based on expected market supply and demand in the region in which the plant operates, anticipated production levels, planned and




TRANSALTA CORPORATION F24
Notes to Consolidated Financial Statements
unplanned outages, changes to regulations and transmission capacity or constraints for the remaining life of the facilities.

Discount rates are determined by employing a weighted average cost of capital methodology that is based on capital structure, cost of equity and cost of debt assumptions based on comparable companies with similar risk characteristics and market data as the asset, CGU or group of CGUs subject to the test. These estimates and assumptions are susceptible to change from period to period and actual results can, and often do, differ from the estimates, and can have either a positive or negative impact on the estimate of the impairment charge, and may be material.

The impairment outcome can also be impacted by the determination of CGUs or groups of CGUs for asset and goodwill impairment testing. A CGU is the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or groups of assets, and goodwill is allocated to each CGU or group of CGUs that is expected to benefit from the synergies of the acquisition from which the goodwill arose. The allocation of goodwill is reassessed upon changes in the composition of segments, CGUs or groups of CGUs. In respect of determining CGUs, significant judgment is required to determine what constitutes independent cash flows between power plants that are connected to the same system. The Corporation evaluates the market design, transmission constraints and the contractual profile of each facility, as well as the Corporation’s own commodity price risk management plans and practices, in order to inform this determination.

With regard to the allocation or reallocation of goodwill, significant judgment is required to evaluate synergies and their impacts. Minimum thresholds also exist with respect to segmentation and internal monitoring activities. The Corporation evaluates synergies with regards to opportunities from combined talent and technology, functional organization and future growth potential, and considers its own performance measurement processes in making this determination. Information regarding significant judgments and estimates in respect of impairment during 2018 to 2020 is found in Notes 7, 18 and 21.

III. Leases
In determining whether the Corporation’s contracts contain, or are, leases, management must use judgment in assessing whether the contract provides the customer with the right to substantially all of the economic benefits from the use of the asset during the lease term and whether the customer obtains the right to direct the use of the asset during the lease term. For those agreements considered to contain, or be, leases, further judgment is required to determine the lease term by assessing whether termination or extension options are reasonably certain to be exercised. Judgment is also applied in identifying in-substance fixed payments (included) and variable payments that are based on usage or performance factors (excluded) and in identifying lease and non-lease components (services that the supplier performs) of contracts and in allocating contract payments to lease and non-lease components.

For leases where the Corporation is a lessor, judgment is required to determine if substantially all of the significant risks and rewards of ownership are transferred to the customer or remain with the Corporation, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how the Corporation classifies amounts related to the arrangement as either PP&E or as a finance lease receivable on the Consolidated Statements of Financial Position, and therefore the amount of certain items of revenue and expense is dependent upon such classifications.

IV. Income Taxes
Preparation of the consolidated financial statements involves determining an estimate of, or provision for, income taxes in each of the jurisdictions in which the Corporation operates. The process also involves making an estimate of income taxes currently payable and income taxes expected to be payable or recoverable in future periods, referred to as deferred income taxes. Deferred income taxes result from the effects of temporary differences due to items that are treated differently for tax and accounting purposes. The tax effects of these differences are reflected in the Consolidated Statements of Financial Position as deferred income tax assets and liabilities. An assessment must also be made to determine the likelihood that the Corporation’s future taxable income will be sufficient to permit the recovery of deferred income tax assets. To the extent that such recovery is not probable, deferred income tax assets must be reduced. Management uses the Corporation’s long-range forecasts as a basis for evaluation of recovery of deferred income tax assets. Management must exercise judgment in its assessment of continually changing tax interpretations, regulations and legislation to ensure deferred income tax assets and liabilities are complete and fairly presented. Differing assessments and applications than the Corporation’s estimates could materially impact the amounts recognized for deferred income tax assets and liabilities. See Note 12 for further details on the impacts of the Corporation’s tax policies.

V. Financial Instruments and Derivatives
The Corporation’s financial instruments and derivatives are accounted for at fair value, with the initial and subsequent changes in fair value affecting earnings in the period the change occurs. The fair values of financial instruments and derivatives are classified within three levels, with Level III fair values determined using inputs for the asset or liability that are not readily observable. These fair value levels are outlined and discussed in more detail in Note 15. Some of the Corporation’s fair values are included in Level III because they are not traded on an active exchange or have terms that




TRANSALTA CORPORATION F25
Notes to Consolidated Financial Statements
extend beyond the time period for which exchange-based quotes are available and require the use of internal valuation techniques or models to determine fair value.

The determination of the fair value of these contracts and derivative instruments can be complex and relies on judgments and estimates concerning future prices, volatility and liquidity, among other factors. These fair value estimates may not necessarily be indicative of the amounts that could be realized or settled, and changes in these assumptions could affect the reported fair value of financial instruments. Fair values can fluctuate significantly and can be favourable or unfavourable depending on current market conditions. Judgment is also used in determining whether a highly probable forecasted transaction designated in a cash flow hedge is expected to occur based on the Corporation’s estimates of pricing and production to allow the future transaction to be fulfiled.

When the Corporation enters into contracts to buy or sell non-financial items, such as certain commodities, and the contracts can be settled net in cash, the Corporation must use judgment to evaluate whether such contracts were entered into and continue to be held for the purposes of the receipt or delivery of the commodity in accordance with the Corporation's expected purchase, sale or usage requirements (i.e., normal purchase and sale). If this assertion cannot be supported, initially at contract inception and on an ongoing basis, the contracts must be accounted for as derivatives and measured at fair value, with changes in fair value recognized in net earnings. In supporting the normal purchase and sale assertion, the Corporation considers the nature of the contracts, the forecasted demand and supply requirements to which the contracts relate, and its past practice of net settling other similar contracts, which may taint the normal purchase and sale assertion.

VI. Project Development Costs
Project development costs are capitalized in accordance with the accounting policy in Note 2(K). Management is required to use judgment to determine if there is reason to believe that future costs are recoverable, and that efforts will result in future value to the Corporation, in determining the amount to be capitalized. Information on the write-off of project development costs is disclosed in Note 7.

VII. Provisions for Decommissioning and Restoration Activities
TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(N) and Note 23. Initial decommissioning provisions, and subsequent changes thereto, are determined using the Corporation’s best estimate of the required cash expenditures, adjusted to reflect the risks and uncertainties inherent in the timing and amount of settlement. The estimated cash expenditures are present valued using a current, risk-adjusted, market-based, pre-tax discount rate. A change in estimated cash flows, market interest rates or timing could have a material impact on the carrying amount of the provision. Information regarding significant judgments and estimates made during 2020 in respect of decommissioning and restoration provisions can be found in Note 3(A)(III) and Notes 7 and 23.

VIII. Useful Life of PP&E
Each significant component of an item of PP&E is depreciated over its estimated useful life. Estimated useful lives are determined based on current facts and past experience, and take into consideration the anticipated physical life of the asset, existing long-term sales agreements and contracts, current and forecasted demand, the potential for technological obsolescence and regulations. The useful lives of PP&E are reviewed at least annually to ensure they continue to be appropriate. Information on changes in useful lives of facilities is disclosed in Note 3(A)(III).

IX. Employee Future Benefits
The Corporation provides pension and other post-employment benefits, such as health and dental benefits, to employees. The cost of providing these benefits is dependent upon many factors, including actual plan experience and estimates and assumptions about future experience.

The liability for pension and post-employment benefits and associated costs included in annual compensation expenses are impacted by estimates related to: 
▪Employee demographics, including age, compensation levels, employment periods, the level of contributions made to the plans and earnings on plan assets;;
▪The effects of changes to the provisions of the plans; and
▪Changes in key actuarial assumptions, including rates of compensation and health-care cost increases and discount rates.

Due to the complexity of the valuation of pension and post-employment benefits, a change in the estimate of any one of these factors could have a material effect on the carrying amount of the liability for pension and other post-employment benefits or the related expense. These assumptions are reviewed annually to ensure they continue to be appropriate. See Note 31 for disclosures on employee future benefits.





TRANSALTA CORPORATION F26
Notes to Consolidated Financial Statements
X. Other Provisions
Where necessary, the Corporation recognizes provisions arising from ongoing business activities, such as interpretation and application of contract terms, ongoing litigation and force majeure claims. These provisions, and subsequent changes thereto, are determined using the Corporation’s best estimate of the outcome of the underlying event and can also be impacted by determinations made by third parties, in compliance with contractual requirements. The actual amount of the provisions that may be required could differ materially from the amount recognized. More information is disclosed in Notes 4, 9 and 23 with respect to other provisions.

XI. Revenue from Contracts with Customers
Where contracts contain multiple promises for goods or services, management exercises judgment in determining whether goods or services constitute distinct goods or services or a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer. The determination of a performance obligation affects whether the transaction price is recognized at a point in time or over time. Management considers both the mechanics of the contract and the economic and operating environment of the contract in determining whether the goods or services in a contract are distinct.

In determining the transaction price and estimates of variable consideration, management considers the past history of customer usage in estimating the goods and services to be provided to the customer. The Corporation also considers the historical production levels and operating conditions for its variable generating assets. The Corporation’s contracts generally outline a specific amount to be invoiced to a customer associated with each performance obligation in the contract. Where contracts do not specify amounts for individual performance obligations, the Corporation estimates the amount of the transaction price to allocate to individual performance obligations based on their stand-alone selling price, which is primarily estimated based on the amounts that would be charged to customers under similar market conditions.

The satisfaction of performance obligations requires management to make judgments as to when control of the underlying good or service transfers to the customer. Determining when a performance obligation is satisfied affects the timing of revenue recognition. Management considers both customer acceptance of the good or service, and the impact of laws and regulations such as certification requirements, in determining when this transfer occurs.

Management also applies judgment in determining whether the invoice practical expedient permits recognition of revenue at the invoiced amount, if that invoiced amount corresponds directly with the entity's performance to date.

XII. Classification of Joint Arrangements
Upon entering into a joint arrangement, the Corporation must classify it as either a joint operation or joint venture, which classification affects the accounting for the joint arrangement. In making this classification, the Corporation exercises judgment in evaluating the terms and conditions of the arrangement to determine whether the parties have rights to the assets and obligations or rights to the net assets. Factors such as the legal structure, contractual arrangements and other facts and circumstances, such as where the purpose of the arrangement is primarily for the provision of the output to the parties and when the parties are substantially the only source of cash flows for the arrangement, must be evaluated to understand the rights of the parties to the arrangement.

XIII. Significant Influence
Upon entering into an investment, the Corporation must classify it as either an investment as an associate or an investment under IFRS 9. In making this classification, the Corporation exercises judgment in evaluating whether the Corporation has significant influence over the investee. Significant influence is the power to participate in the financial and operating policy decisions of the investee, but is not control or joint control over those policies. If the Corporation holds 20 per cent or more of the voting rights in the investee, it is presumed that the entity has significant influence, unless it can be clearly demonstrated that this is not the case. Other factors such as representation on the board of directors, participation in policy-making processes, material transactions between the Corporation and investee, interchange of managerial personnel or providing essential technical information are considered when assessing if the Corporation has significant influence over an investee.

3. Accounting Changes
A. Current Accounting Changes

I. Amendments to IAS 1 and IAS 8 Definition of Material
The Corporation adopted the amendments to IAS 1 and IAS 8 as of Jan. 1, 2020. The amendments provide a new definition of material that states “information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.”




TRANSALTA CORPORATION F27
Notes to Consolidated Financial Statements

The amendments clarify that materiality will depend on the nature or magnitude of information, either individually or in combination with other information, in the context of the financial statements. A misstatement of information is material if it could reasonably be expected to influence decisions made by the primary users. These amendments had no impact on the consolidated financial statements of, nor is there expected to be any future impact to, the Corporation.

II. Amendments to IFRS 7 and 9 Interest Rate Benchmark Reform
In September 2019, the IASB issued amendments to the IFRS relating to Interest Rate Benchmark Reform - amending IFRS 9, IAS 39 and IFRS 7. These amendments provide temporary relief during the period of uncertainty from applying specific hedge accounting requirements to hedging relationships directly affected by the ongoing interest rate benchmark reforms. These amendments are mandatory for annual periods beginning on or after Jan. 1, 2020. The Corporation adopted these amendments as of Jan. 1, 2020. There were no hedging relationships that were directly affected on Jan. 1, 2020.

During the first quarter of 2020, the Corporation entered into cash flow hedges of interest rate risk associated with a future forecasted debt issuance using London Interbank Offered Rate ("LIBOR") based derivative instruments. As a temporary relief, provided by the IFRS 9 amendments, the Corporation has assumed that the LIBOR interest rate on which the cash flows of the interest rate swaps are based is not altered by interbank offered rates ("IBOR") reform when assessing if the hedge is highly effective.

III. Change in Estimates
Useful Life of PP&E at Alberta Thermal
During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021 and accordingly the useful life of the related assets was adjusted to align with the Corporation's conversion to gas plans. This resulted in an increase of $15 million in depreciation expense that was recognized in the Consolidated Statements of Earnings (Loss) during the second half of 2020. As at Dec. 31, 2020, the carrying value of the Highvale mine, including PP&E, right-of-use assets and intangible assets, was $373 million,

During the third quarter of 2019, the Corporation adjusted the useful lives of certain coal assets, effective Sept. 1, 2019, to reflect the changes announced related to the Clean Energy Investment Plan (see Note 4(A) for further details). As a result, assets used only for coal-burning operations were adjusted to shorten their useful lives whereas other asset lives were extended as they were identified as being used after the coal-to-gas or combined-cycle conversions. Due to the impact of shortening the lives of the coal assets, overall depreciation expense for the year ended Dec. 31, 2019 increased by approximately $16 million.

In 2018, as a result of the Off-Coal Agreement (“OCA”) with the Government of Alberta described in Note 9(B), the Corporation adjusted the useful lives of some of its mine assets to align with the Corporation's coal-to-gas conversion plans. As a result, depreciation expense and intangibles amortization for the year ended Dec.31, 2018, increased by $38 million.

In the third quarter of 2018, the Corporation retired Sundance Unit 2 and recorded an impairment charge of $38 million for the remaining net book value of the asset. In the third quarter of 2020, the Corporation recognized an impairment on Sundance Unit 3 in the amount of $70 million, due to the Corporation's decision to retire the unit. The retirement decision for Sundance Unit 3 was largely driven by an assessment of future market conditions, the age and condition of the unit, and our ability to supply energy and capacity from our generation portfolio in Alberta.

Useful Life of PP&E at Wind and Solar
During the third quarter of 2019, the allocation of the costs recognized for the components of the Wind and Solar PP&E and the useful lives for these identified components were reviewed. As a result of the review, additional components were identified for parts where the useful lives are shorter than the original estimate. The useful life of each of these components was reduced from 30 years to either 15 years or 10 years. Accordingly, depreciation expense for the year ended Dec. 31, 2019, increased by approximately $11 million.

Sheerness
During the second quarter of 2019, the Corporation adjusted the useful life of its Sheerness coal-fired facility assets to align with the dual-fuel conversion plans. As a result, the assets used for coal-burning operations as well as the other asset lives were extended and depreciation expense for the year ended Dec. 31, 2019, decreased by approximately $8 million.





TRANSALTA CORPORATION F28
Notes to Consolidated Financial Statements
The useful lives may be revised or extended in compliance with the Corporation's accounting policies, dependent upon future operating decisions and events.

Decommissioning and other provisions
In the fourth quarter of 2020, the Corporation adjusted the Sarnia decommissioning and restoration provision to reflect an updated engineering study. The Corporation's current best estimate of the decommissioning and restoration provision decreased by $15 million. This resulted in a decrease in the related assets in PP&E.

In the third quarter of 2020, the Corporation adjusted the Highvale mine decommissioning and restoration provision to reflect the mine closure advancement, an updated mine plan and current mining activity including increased volume of material movement. The Corporation's current best estimate of the decommissioning and restoration provision increased by $75 million. This resulted in an increase in the related assets in PP&E.

During the third quarter of 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believed that the fine coal recovery and reclamation work would be completed as originally proposed. At the end of 2019, the Corporation's best estimate of the decommissioning and restoration provision increased by $141 million. Since the Centralia mine is no longer operating and reached the end of its useful life in 2006, this adjustment resulted in the immediate recognition of the full $141 million, through asset impairment in net earnings.

B. Future Accounting Changes
Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use
The Corporation plans to early adopt the amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use on Jan. 1, 2021. The amendment has a mandatory effective date of Jan. 1, 2022. The amendments prohibit deducting from the cost of an item of property, plant and equipment any proceeds from selling items produced while bringing the asset to the location and condition necessary for it to be capable of operating. No adjustments are expected from early adopting the amendments.

IFRS 7 Financial Instruments, Disclosures - Interest Rate Benchmark Reform
The IASB issued Interest Rate Benchmark Reform — Phase 2 in August 2020, which amends IFRS 9 Financial Instruments, IAS 39 Financial Instruments: Recognition and Measurement, IFRS 7 Financial Instruments: Disclosures and IFRS 16 Leases. The amendments are effective Jan. 1, 2021, and will be adopted by the Corporation in 2021, no financial impact is expected upon adoption.

C. Comparative Figures
 
Certain comparative figures have been reclassified to conform to the current period’s presentation. These reclassifications did not impact previously reported net earnings.

4. Significant and Subsequent Events
A. Clean Energy Investment Plan
TransAlta's Clean Energy Investment Plan announced in 2019 includes converting our existing Alberta coal assets to natural gas and advancing our leadership position in on-site generation and renewable energy. The Clean Energy Investment Plan provided further details of previously highlighted initiatives that TransAlta has been continuing to progress since early 2017.

TransAlta’s Clean Energy Investment Plan includes converting three of our existing Alberta thermal units to gas during 2021 by replacing existing coal burners with natural gas burners. The cost to convert each unit is expected to be approximately $35 million. On Feb. 1, 2021, we announced the completion of the conversion to gas of Sundance Unit 6. The Corporation continues to advance the conversion of its Keephills Unit 2 and Keephills Unit 3 for completion later in 2021 and has issued Full Notice to Proceed for both units. In addition, on April 4, 2020, the dual-fuel conversion of Sheerness Unit 2 was completed. The Sheerness facility will receive it's last coal shipment in the first quarter of 2021, with coal stock being actively depleted until the end of 2021. The elimination of coal as a fuel source will reduce future fuel costs and greenhouse gas ("GHG") costs at Sheerness.

The highlights of these gas conversion investments include:
▪Positioning TransAlta’s fleet as a low-cost generator in the Alberta energy-only market;
▪Generating attractive returns by leveraging the Corporation’s existing infrastructure;
▪Significantly extending the life and cash flows of our Alberta thermal assets; and
▪Significantly reducing air emissions and costs.





TRANSALTA CORPORATION F29
Notes to Consolidated Financial Statements
The Clean Energy Investment Plan also includes repowering the steam turbines at Sundance Unit 5 and, potentially, Keephills Unit 1 by installing one or more combustion turbines and heat recovery steam generators, thereby creating highly efficient combined-cycle units. The repowered units are expected to be a 35 per cent to 45 per cent lower capital investment when compared to a new combined-cycle facility, while achieving a similar heat rate. During the first quarter of 2020, we received regulatory approval from the Alberta Utilities Commission ("AUC") and Alberta Environment and Parks for the repowering of Sundance Unit 5 and Keephills Unit 1 into combined-cycle units. During the fourth quarter of 2020, an equipment supply agreement was executed as part of the strategy to repower Sundance Unit 5 into a highly efficient combined cycle unit. The commercial operation date is anticipated in the fourth quarter of 2023. The Sundance Unit 5 repowered combined-cycle unit will have a capacity of approximately 730 MW and is expected to cost approximately $800 million to $825 million, well below a greenfield combined-cycle project. As part of this transaction, we also acquired a long-term PPA for capacity plus energy, including the passthrough of GHG costs, starting in late 2023 with Shell Energy North America (Canada). The Corporation will continue to evaluate the prospect for the repowering of Keephills Unit 1 in 2021 and 2022, as a supply addition to the Alberta market in the 2026 to 2030 time frame.

TransAlta has determined to cease coal-fired operations in Canada by Jan 1, 2022. During the third quarter of 2020, the Board approved the accelerated shutdown of the Highvale mine by the end of 2021, and the useful life of the related assets was adjusted to align with the Corporation's conversion to gas plans. As a result, the Corporation announced that Keephills Unit 1 and Sundance Unit 4 will discontinue firing with coal and will only operate on gas effective Jan. 1, 2022. The maximum capability of these units will be reduced to 70 MW and 113 MW, respectively.

As at Dec. 31, 2020, the carrying value of the Highvale mine, including PP&E right-of-use assets and intangible assets, was $373 million. As a result, our cost per tonne of coal will increase as the fixed coal costs will be spread over lower volumes. During the second half of 2020, the increased depreciation expense and our cost per tonne of coal exceeded the net realizable value of the coal inventory and a writedown of $37 million was recognized in fuel, carbon compliance and purchased power. As the Highvale mine moves into the reclamation phase, our anticipated coal consumption is expected to continue to decline, further increasing the cost of coal, and future expected writedowns in fuel costs. In 2020, we started the year with 2.1 million tonnes of coal inventory, during which we mined an additional 2.3 million tonnes and consumed 3.5 million tonnes. We ended the year with approximately 1 million tonnes of coal inventory and we will continue to actively deplete our coal stock as we wind down our mining activity by the end of 2021.

The Corporation’s Clean Energy Investment Plan also consists of three wind projects in the United States, one wind project in Alberta and a cogeneration facility that is discussed in more detail later in this section. The Big Level wind project ("Big Level") and Antrim wind project ("Antrim") began commercial operations on Dec. 19, 2019, and Dec, 24, 2019, respectively. The Skookumchuck wind project began commercial operation on Nov. 7, 2020, and was acquired by the Corporation on Nov. 25. 2020. The Windrise wind project ("Windrise") is currently under construction. These projects are underpinned by long-term PPAs with highly creditworthy counterparties. In addition, TransAlta has entered into agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant ("K3"). Please see Note 4(J) for additional details on the current status of the Kaybob cogeneration project.

B. Pioneer Pipeline
On Dec. 17, 2018, the Corporation exercised its option to acquire 50 per cent ownership in the Pioneer gas pipeline ("Pioneer Pipeline") for $83 million. Tidewater Midstream & Infrastructure Ltd.'s (“TMI”) and TransAlta each own a 50 per cent interest in the Pioneer Pipeline, which is backstopped by a 15-year take-or-pay agreement from TransAlta at market rate tolls. During the fourth quarter of 2019, TransAlta recognized a right-of-use asset and lease liability for the portion of the Pioneer Pipeline that is not directly owned.

During 2019, the Pioneer Pipeline transported its first gas four months ahead of schedule to TransAlta's generating units at Sundance and Keephills. The Pioneer Pipeline initially had approximately 50 MMcf/day of natural gas flowing during the start-up phase where initial flows fluctuated depending on market conditions. Firm throughput of approximately 130 MMcf/day of natural gas began flowing through the Pioneer Pipeline on Nov. 1, 2019.

The Pioneer Pipeline is held in a separate entity that is a joint operation with TMI. The Corporation reports its interests in joint operations in its consolidated financial statements using the proportionate consolidation method by recognizing its share of the assets, liabilities, revenues and expenses in respect of its interest in the joint operation within the Alberta Thermal segment. The Pioneer Pipeline is classified as a joint operation, due to the fact that TransAlta is currently the only customer and both parties are providing the only cash flows to fund the operations.




TRANSALTA CORPORATION F30
Notes to Consolidated Financial Statements

On Oct. 1, 2020, TransAlta announced that it had entered into a definitive Purchase and Sale Agreement providing for the sale of its 50 per cent interest in the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. (“ATCO”) (the "Transaction"). The purchase price of $255 million represents both TransAlta's and TMI's interests. This agreement replaces the previous Purchase and Sale agreement to sell the Pioneer Pipeline to NOVA Gas Transmission Ltd. (“NGTL”) from the second quarter of 2020. ATCO acquired the right to purchase the Pioneer Pipeline through an option agreement with NGTL. Following closing of the Transaction, the Pioneer Pipeline will be integrated into NGTL's and ATCO's Alberta integrated natural gas transmission systems to provide reliable natural gas supply to TransAlta's Sundance and Keephills power generating stations. At Dec. 31, 2020, our interest in the Pioneer Pipeline is included in assets held for sale in the Consolidated Statements of Financial Position.

In addition, TransAlta has entered into incremental long-term firm natural gas delivery transportation agreements with NGTL for 351 TJ per day, bringing the total long-term firm natural gas transportation contracts up to 400 TJ per day by 2023. TransAlta’s current commitments, including the 139 TJ per day supply arrangement with TMI, will remain in place until the closing of the Transaction. The Transaction is subject to customary regulatory approvals and is anticipated to close during the second quarter of 2021.

C. Skookumchuck Wind Project
On April 12, 2019, TransAlta signed an agreement with Southern Power Company, a subsidiary of Southern Company, to have the option to purchase a 49 per cent interest in SP Skookumchuck Investments, LLC ("Skookumchuck") with Southern Power upon the facility's commercial operation date. Skookumchuck is a 136.8 MW wind project located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas V136 wind turbines. The project began commercial operation on Nov. 7, 2020.

On Nov. 25, 2020, TransAlta completed the acquisition of Skookumchuck. TransAlta's total capital investment was $163 million, with TransAlta paying cash of $86 million (US$66 million) with the remaining $77 million (US$59 million) being funded with tax equity financing. The investment has been classified as a joint venture, as the investment is held in a separate entity and the Corporation has rights to the net assets of Skookumchuck. The Corporation reports its interests in joint arrangements in its consolidated financial statements using the equity method recognizing its share of income (loss) in the Consolidated Statements of Earnings (Loss).

The project has a 20-year PPA with Puget Sound Energy. TransAlta has entered into an definitive agreement with TransAlta Renewables to sell the Corporation's interest in Skookumchuck, which is expected to close in April 2021, as further described below in this section.

D. WindCharger
On Aug. 1, 2020, the WindCharger battery storage project ("WindCharger") was sold to TransAlta Renewables. Wind-Charger has been operational since Oct. 15, 2020 and is the first utility-scale battery energy storage project in Alberta. The WindCharger project has a nameplate capacity of 10 MW with a total storage capacity of 20 MWh. WindCharger is located in southern Alberta in the Municipal District of Pincher Creek next to TransAlta’s existing Summerview wind facility substation. WindCharger stores energy produced by the nearby Summerview II wind facility and discharges it into the Alberta electricity grid at times of peak demand. TransAlta is expected to receive co-funding of almost 50 per cent of the $14 million construction cost from Emissions Reduction Alberta. WindCharger is participating in both the wholesale energy and ancillary services market of the Alberta Electric System Operator ("AESO").

E. Windrise
On Dec. 17, 2018, TransAlta's 207 MW Windrise wind project was identified by the AESO as one of the three selected projects in the third round of the Renewable Electricity Program. TransAlta and the AESO subsequently executed a Renewable Electricity Support Agreement with a 20-year term. Windrise is situated on 11,000 acres of land located in the county of Willow Creek, Alberta, and is expected to cost approximately $270 million to $285 million. Windrise has secured approval for the wind facility and transmission line required to connect the facility to the Alberta grid from the AUC. Construction activities on Windrise continue to advance with all appropriate procedures in place to protect the construction team during the COVID-19 pandemic. However as a result of COVID-19 and related delays in construction, the commercial operation date is expected to occur during the second half of 2021. As of Dec. 31, 2020, Windrise was 78 per cent complete. On Feb. 26, 2021, TransAlta Renewables acquired Windrise from the Corporation as described further below.





TRANSALTA CORPORATION F31
Notes to Consolidated Financial Statements
F. Acquisition of Wind Development Projects
In 2019, TransAlta acquired a portfolio of wind development projects in the US. If the Corporation decides to move forward with any of these projects, additional consideration may be payable on a project-by-project basis only in the event a project achieves commercial operations prior to Dec. 31, 2025.

G. EMG International Acquisition
On Nov. 30, 2020, TransAlta acquired a 30 per cent equity interest in EMG to diversify our sustainability offerings to customers while directly supporting our clean energy transition and sustainability goals. Included in the purchase price of US$12 million is an estimated component contingent on EMG realizing certain earnings metrics in 2020 and 2021, following the acquisition. The final contingent amount will be calculated based on actual earnings metrics achieved. EMG is an established company with over 25 years of experience in process wastewater treatment and specializes in the design and construction of high-rate anaerobic digester systems. EMG’s wastewater treatment process converts organic waste into a valuable source of renewable energy. Their technology produces a biogas stream that can be used as fuel to generate electricity, displacing energy consumed from higher emitting resources. The investment provides a unique opportunity for TransAlta to leverage its vast expertise in on-site generation to support further advancements by EMG in the waste-to-energy space. This investment will advance the Corporation's presence in the US sustainability and on-site generation markets. The investment has been classified as an Investment in associate, as the Corporation owns 30 per cent of the entity and has representation on the management committee. The Corporation reports its investment in associates in its consolidated financial statements using the equity method recognizing its share of income (loss) in the Consolidated Statement of Earnings (Loss).

H. TransAlta Renewables Acquisitions
On Dec. 23, 2020, the Corporation announced that it had entered into definitive agreements for the acquisition by TransAlta Renewables of its 100 per cent direct interest in the 207 MW Windrise wind project located in the Municipal District of Willow Creek, Alberta; a 49 per cent economic interest in the 137 MW Skookumchuck wind facility located across Thurston and Lewis counties in Washington State; and a 100 per cent economic interest in the 29 MW Ada cogeneration facility located in Ada, Michigan. TransAlta Renewables' acquisition of the Windrise closed on Feb. 26, 2021, and the acquisition of the economic interests in the Ada cogeneration facility and the Skookumchuck wind facility are expected to close in April 2021. The total acquisition value for the portfolio of assets is expected to be $439 million, which includes the remaining construction costs for the Windrise wind project. TransAlta Renewables will fund the acquisition and remaining construction costs with the proceeds from the TEC Hedland financing. Please refer to Note 4(L) for further details.

I. BHP Nickel West Contract Extension
On Oct. 22, 2020, Southern Cross Energy ("SCE"), a subsidiary of the Corporation, replaced and extended its current PPA with BHP Billiton Nickel West Pty Ltd. ("BHP"). SCE is composed of four generation facilities with a combined capacity of 245 MW in the Goldfields region of Western Australia.

The new agreement was effective Dec. 1, 2020, and replaces the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extends the term to Dec. 31, 2038, and provides SCE with the exclusive right to supply thermal and electrical energy from the Southern Cross Facilities for BHP's mining operations located in the Goldfields region of Western Australia. The extension will provide SCE a return on new capital investments, which will be required to support BHP's future power requirements and recently announced emission reduction targets. The amendments within the PPA also provide BHP participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. Evaluation of renewable energy supply and carbon emissions reduction initiatives under the extended PPA with SCE are underway, including a 18.5MW solar photovoltaic facility supported by a battery energy storage system and a waste heat steam turbine system.

For accounting purposes, the original agreement was accounted for as an operating lease. Under the new PPA, the agreement is now accounted for as a finance lease. As a result, we derecognized net assets of $77 million, which includes balances for PP&E, intangible assets, deferred credits and prepaid expenses. In addition, we recognized a finance lease receivable of $89 million and a gain on asset disposition of $12 million. Subsequent to the transaction, the Corporation incurred additional major maintenance costs in relation to these assets which was recorded as a reduction to the gain on asset disposition.

J. Agreement to Construct and Own a Cogeneration Plant in Alberta
On Oct. 1, 2019, TransAlta and Energy Transfer Canada ("ET Canada" formerly known as SemCAMS Midstream ULC) entered into definitive agreements to develop, construct and operate a 40 MW cogeneration facility at the Kaybob




TRANSALTA CORPORATION F32
Notes to Consolidated Financial Statements
South No. 3 sour gas processing plant. The facility was expected to receive its final regulatory approvals in the second half of the year and begin construction in December 2020. On Sept. 25, 2020, the AUC released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. We are in ongoing commercial and technical discussions with ET Canada relative to the project at K3, or potentially developing a new project at another site owned and/or operated by ET Canada.

K. Acquisition of a Contracted Cogeneration Asset in Michigan
On May 19, 2020, the Corporation closed the previously announced acquisition of a contracted natural-gas-fired cogeneration facility from two private companies for a purchase price of US$27 million. The Ada facility is a 29 MW cogeneration facility ("Ada") in Michigan that is contracted under a PPA and a steam sale agreement for approximately six years with Consumers Energy and Amway.

The fair values of the identifiable assets and liabilities of the acquired entity in the business combination as at the date of acquisition were:
As at May 19, 2020 Fair value recognized
on acquisition
Assets
Net working capital 6 
Property, plant and equipment 1 
Intangible assets(1)
37 
Risk management liabilities (current and long-term) (5)
Decommissioning provisions (1)
Total identifiable net assets at fair value 38 
Cash consideration 32 
Working capital consideration 6 
Total purchase consideration transferred 38 
(1) This relates to the power sales contract acquired and will be amortized over six years.

L. TEC Hedland Pty Ltd. Secures AU$800 Million Financing
On Oct. 22, 2020, TEC Hedland Pty Ltd. ("TEC"), a subsidiary of the Corporation, closed an AU$800 million senior secured note offering ("Offering"), by way of a private placement, which is secured by, among other things, a first ranking charge over all assets of TEC. The Offering bears interest at 4.07 per cent per annum, payable quarterly and maturing on June 30, 2042, with principal payments starting on Mar. 31, 2022. The Offering has a rating of BBB by Kroll Bond Rating Agency.

TransAlta Renewables has received $480 million (AU$515 million) of the proceeds from the Offering through the redemption of certain intercompany structures. An additional AU$200 million has been loaned to TransAlta Renewables by TransAlta Energy (Australia) Pty Ltd. ("TEA"), which is a subsidiary of TransAlta. The loan bears interest at 4.32 per cent and will be repaid by Oct. 23, 2022 or on demand. The remaining proceeds from the Offering were set aside for required reserves and transaction costs.

TransAlta Renewables used a portion of the proceeds from the redemption and the intercompany loan to repay existing indebtedness on its credit facility and to acquire the asset and economic interests noted above.

M. Strategic Investment by Brookfield
On March 22, 2019, the Corporation entered into an agreement (the "Investment Agreement") whereby Brookfield Renewable Partners or its affiliates (collectively “Brookfield”) agreed to invest $750 million (the "Investment") in the Corporation through the purchase of exchangeable securities. The securities are exchangeable by Brookfield into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future adjusted earnings before interest, taxes, depreciation and amortization ("EBITDA").

On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039. On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in consideration for redeemable, retractable first preferred shares. The proceeds from the first tranche were used to accelerate our conversion to gas program. The Corporation intends to use the proceeds from the second tranche of the




TRANSALTA CORPORATION F33
Notes to Consolidated Financial Statements
financing to advance the Corporation’s conversion to gas program, to fund other growth initiatives and for general corporate purposes.

Upon entering into the Investment Agreement and as required under the terms of the agreement, the Corporation paid Brookfield a $7.5 million structuring fee. A commitment fee of $15 million was also paid upon completion of the initial funding. These transaction costs, representing three per cent of the total investment of $750 million, have been recognized as part of the carrying value of the unsecured subordinated debentures. See Note 25 for further details.

In accordance with the terms of the Investment Agreement, TransAlta has formed a Hydro Assets Operating Committee consisting of two representatives from Brookfield and two representatives from TransAlta to collaborate in connection with the operation and maximization of the value of the Alberta Hydro Assets. In connection with this, the Corporation has committed to pay Brookfield an annual fee of $1.5 million for six years beginning May 1, 2019 (the "Brookfield Hydro Fee"), which is recognized in the operations, maintenance and administration expense on the Consolidated Statements of Earnings (Loss).

TransAlta has indicated that it intends to return up to $250 million of capital to shareholders through share repurchases within three years of receiving the first tranche of the Investment. As of Dec. 31, 2020, 15,068,900 common shares have been repurchased and $129 million under the normal course issuer bid normal course issuer bid("NCIB") program.

Under the terms of the Investment Agreement, Brookfield committed to purchase TransAlta common shares on the open market to increase its share ownership in TransAlta to not less than nine per cent by May 1, 2021. As of Jan. 8, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 33,845,685 common shares, representing approximately 12.4 per cent of the issued and outstanding common shares, calculated on an undiluted basis. In connection with the Investment, Brookfield is entitled to nominate two directors for election to the Board.

On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice alleging, among other things, oppression by the Corporation and its directors and seeking to set aside the Brookfield Investment Agreement. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter was adjourned due to the COVID-19 pandemic and is now scheduled to proceed to trial for three weeks starting April 19, 2021. Refer to Note 36 for further details.

N. Centralia Unit 1 Retirement
The Corporation owns a two-unit 1,340 MW thermal coal-fired facility in Centralia, Washington in relation to which we have entered into a number of multiple year medium- and short-term energy sales agreements. In 2011, Washington State passed the TransAlta Energy Transition Bill (chapter 180, Laws of 2011) (the "Bill'') allowing the Centralia thermal facility to comply with the State's GHG emissions performance standards by ceasing coal generation in one of its two boilers by the end of 2020 and the other by the end of 2025. The Bill removed restrictions that had previously been imposed on the facility limiting the duration of new contracts from the facility and limiting the technology that the facility would be required to implement for nitrogen oxide controls. Centralia Unit 1 was retired from service effective Dec. 31, 2020.

O. Mothballing of Sundance Units and Sundance Unit 3 Retirement
On March 8, 2019, the Corporation announced that the AESO granted an extension to the mothballing of Sundance Units 3 and 5, which are to remain mothballed until Nov. 1, 2021, extended from April 1, 2020. On July 22, 2020, the Corporation announced that it gave notice to the AESO to retire Sundance Unit 3 effective July 31, 2020. The retirement decision was largely driven by TransAlta’s assessment of future market conditions, the age and condition of the unit and our ability to supply energy and capacity from our generation portfolio in Alberta. This decision advances our transition to 100 per cent clean electricity by 2025. The Corporation recognized an impairment charge of approximately $70 million ($52 million after-tax) during the third quarter 2020.





TRANSALTA CORPORATION F34
Notes to Consolidated Financial Statements
P. COVID-19
The World Health Organization declared a Public Health Emergency of International Concern relating to COVID-19 on Jan. 30, 2020, which they subsequently declared, on March 11, 2020, as a global pandemic. The outbreak of COVID-19 has resulted in governments worldwide enacting emergency measures to constrain the spread of the virus. These measures, which include the implementation of travel bans, self-imposed quarantine periods, self-isolation, physical and social distancing and the closure of non-essential business, have caused significant disruption to businesses globally, which has resulted in an uncertain and challenging economic environment.

The Corporation continued to operate under its business continuity plan, which focused on ensuring that: (i) employees who could work remotely did so; and (ii) employees who operate and maintain our facilities, and who were not able to work remotely, were able to work safely and in a manner that ensured they remained healthy. During the second and third quarters of 2020, the Corporation successfully brought employees who were working remotely back to the office without compromising health and safety standards. In November 2020, as a result of rising COVID-19 case counts in the Province of Alberta and in light of office attendance restrictions eventually imposed by the Government of Alberta, staff at TransAlta's head office returned to remote work protocols. All of TransAlta's offices and sites follow strict health screening and social distancing protocols with personal protective equipment readily available and in use. Further, TransAlta maintains travel bans aligned to local jurisdictional guidance, enhanced cleaning procedures, revised work schedules, contingent work teams and the reorganization of processes and procedures to limit contact with other employees and contractors on-site.

While our financial results have been impacted by price and demand as a result of COVID-19, all of our facilities continue to remain fully operational and capable of meeting our customers' needs. The Corporation continues to work and serve all of our customers and counterparties under the terms of their contracts. We have not experienced interruptions to service requirements. Electricity and steam supply continue to remain a critical service requirement to all of our customers and have been deemed an essential service in our jurisdictions.

During the second quarter of 2020, the Government of Canada passed the Canada Emergency Wage Subsidy as part of its COVID-19 Economic Response Plan. The program's intent is to support employment by providing expense relief to companies that experienced revenue declines in 2020. In January 2021, TransAlta applied for support under this program and expects to receive $8 million (pre-tax) for application periods in 2020. This represents a portion of the funding that the Corporation is eligible for and will be used in supporting a strategy to add incremental employment within the Corporation.

Q. Normal Course Issuer Bid
2020
On May 26, 2020, the Corporation announced that the Toronto Stock Exchange ("TSX") accepted the notice filed by the Corporation to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, the Corporation may repurchase up to a maximum of 14,000,000 common Shares, representing approximately 7.02 per cent of its public float of common shares as at May 25, 2020. Purchases under the NCIB may be made through open market transactions on the TSX and any alternative Canadian trading platforms on which the common shares are traded, based on the prevailing market price. Any common shares purchased under the NCIB will be cancelled.

The period during which the Corporation is authorized to make purchases under the NCIB commenced on May 29, 2020, and ends on May 28, 2021, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Corporation’s election.

Under TSX rules, not more than 228,157 common shares (being 25 per cent of the average daily trading volume on the TSX of 912,630 common shares for the six months ended April 30, 2020) can be purchased on the TSX on any single trading day under the NCIB, with the exception that one block purchase in excess of the daily maximum is permitted per calendar week.

During the year ended Dec. 31, 2020, under the current and previous NCIB, the Corporation purchased and cancelled a total of 7,352,600 common shares at an average price of $8.33 per common share, for a total cost of $61 million. See Note 27 for further details.




TRANSALTA CORPORATION F35
Notes to Consolidated Financial Statements

2019
On May 27, 2019, the Corporation announced that the TSX accepted the notice filed by the Corporation to implement a NCIB for a portion of its common shares. Pursuant to such NCIB, the Corporation was permitted to repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.92 per cent of issued and outstanding common shares as at May 27, 2019.

During the year ended Dec. 31, 2019, the Corporation purchased and cancelled a total of 7,716,300 common shares at an average price of $8.80 per common share, for a total cost of $68 million. See Note 27 for further details.

2018
On March 9, 2018, the Corporation announced that the TSX accepted the notice filed by the Corporation to implement an NCIB for a portion of its common shares. Pursuant to such NCIB, the Corporation was permitted to repurchase up to a maximum of 14,000,000 common shares, representing approximately 4.86 per cent of issued and outstanding common shares as at March 2, 2018.

During the year ended Dec. 31, 2018, the Corporation purchased and cancelled a total of 3,264,500 common shares at an average price of $7.02 per common share, for a total cost of $23 million.

R. TransAlta and Capital Power Swap Non-Operating Interests in Keephills 3 and Genesee 3
On Oct. 1, 2019, the Corporation closed a transaction with Capital Power Corporation ("Capital Power") to swap TransAlta's 50 per cent ownership interest in the 466 MW Genesee 3 facility for Capital Power's 50 per cent ownership interest in the 463 MW Keephills 3 facility. As a result, TransAlta now owns 100 per cent of the Keephills 3 facility and Capital Power owns 100 per cent of the Genesee 3 facility.

The transaction price for each non-operating interest largely offset each other, resulting in a net payment of approximately $10 million from Capital Power to TransAlta. Final working capital true-ups and settlements occurred in November 2019, with a net working capital difference of less than $1 million paid by TransAlta to Capital Power.

In 2019, the Corporation early-adopted 2020 amendments to IFRS 3 Business Combinations, which introduce an optional fair value concentration test. The Corporation elected to apply the optional fair value concentration test to its acquisition of the non-operating interest in Keephills 3, through which it was determined that greater than 90 per cent of the fair value was concentrated in the PP&E acquired. As a result, the acquisition was determined to not be a business and IFRS 3 requirements were not applied and the existing carrying amount of the owned 50 per cent of Keephills 3 was not required to be assessed at fair value. Consequently, the acquisition has been accounted for as an asset acquisition, with the following carrying amounts assigned based on relative fair values:

Working capital 11 
Property, plant and equipment 308 
Other assets 3 
Other liabilities (2)
Decommissioning and other provisions (19)
Total acquisition cost 301 

The sale of Genesee 3 resulted in a gain of $77 million, which was recognized in gains on sale of assets and other on the statement of earnings during the fourth quarter of 2019.

On the closing of the transaction, all of the Keephills 3 and Genesee 3 project agreements with Capital Power were terminated, including the agreement governing the supply of coal from TransAlta’s Highvale mine to the Keephills 3 facility. The Highvale mine accounted for the revenues generated under this agreement pursuant to IFRS 15 Revenue from Contracts with Customers, which resulted in the recognition of a contract liability representing the mine’s unsatisfied performance obligations for which consideration was received in advance. On Oct. 1, 2019, upon termination of this agreement, the Highvale mine had no future performance obligations and accordingly, the balance of the contract liability of $88 million was recognized in earnings in the fourth quarter of 2019.





TRANSALTA CORPORATION F36
Notes to Consolidated Financial Statements
S. Termination of the Alberta Sundance Power Purchase Arrangement
On Sept. 18, 2017, the Corporation received formal notice from the Balancing Pool for the termination of the Sundance B and C PPAs effective March 31, 2018. This announcement was expected and the Corporation took steps to re-take dispatch control for the units effective March 31, 2018. 

Pursuant to a written agreement, the Balancing Pool paid the Corporation approximately $157 million on March 29, 2018. The Corporation disputed the termination payment received. The Balancing Pool excluded certain mining and corporate assets that should have been included in the net book value calculation, which the Corporation pursued from the Balancing Pool through an arbitration initiated under the PPAs. On Aug. 26, 2019, the Corporation announced it was successful in the arbitration and received the full amount it was seeking to recover of $56 million, plus GST and interest.

T. US Wind Projects
On Feb. 20, 2018, TransAlta Renewables announced it entered into an arrangement to acquire interests in two construction-ready wind projects in the Northeastern United States (collectively, the "US Wind Projects"). Big Level consists of a 90 MW wind project located in Pennsylvania that has a 15-year PPA with Microsoft Corporation, and Antrim consists of a 29 MW wind project located in New Hampshire with two 20-year PPAs with Partners Healthcare and New Hampshire Electric Co-op. The Counterparties in the PPAs all have a Standard & Poor's credit ratings of A+ or better. 

A subsidiary of TransAlta acquired Big Level on March 1, 2018, and Antrim on March 28, 2019.

On April 20, 2018, TransAlta Renewables completed the acquisition of an economic interest in Big Level from a subsidiary of TransAlta Power Ltd. (“TA Power”). Pursuant to the arrangement, a TransAlta subsidiary owns Big Level directly and TA Power issued to TransAlta Renewables tracking preferred shares that pay quarterly dividends based on the pre-tax net earnings of Big Level. The tracking preferred shares have preference over the common shares of TA Power held by TransAlta, in respect of dividends and the distribution of assets in the event of the liquidation, dissolution or winding-up of TA Power.

On March 28, 2019, the closing conditions related to the acquisition of Antrim were finalized and the TransAlta subsidiary acquired the development project for total cash consideration of $24 million and the settlement of the balance of the outstanding loan receivable of $41 million. As a result, the Corporation recognized $50 million for assets under construction in PP&E and $15 million in intangibles. The TransAlta subsidiary also paid the final holdback for the Big Level development project of $7 million (US$5 million) on the closing of Antrim.

During 2019, TransAlta Renewables funded the acquisition of Antrim and the construction costs of the US Wind Projects by subscribing for $142 million (US$105 million) of interest-bearing promissory notes and $78 million (US$59 million) of tracking preferred shares.

During 2020, TransAlta Renewables subscribed for additional tracking preferred shares in Big Level and Antrim for $72 million (US$52 million). In addition TransAlta Renewables repaid a portion of the total outstanding promissory notes to the Corporation related to the Big Level and Antrim wind projects in the amount of $92 million (US$72 million).

Big Level and Antrim each began commercial operations in December 2019. In conjunction with reaching commercial operation, tax equity proceeds were raised to partially fund the US Wind Projects in the amount of approximately US$85 million for Big Level and approximately US$41 million for Antrim. The tax equity financing is classified as long-term debt on the Consolidated Statements of Financial Position.

From the tax equity proceeds, a subsidiary of TransAlta repaid $98 million (US$72 million) of the interest-bearing promissory notes from TransAlta Renewables. The remaining amount of the tax equity proceeds is held as reserves within the project entity and will be released upon certain conditions being met. Once these conditions are met, the reserves will be released and the subsidiary of TransAlta will repay the remaining outstanding interest-bearing promissory notes from TransAlta Renewables.

U. Kent Hills 3 Wind Project
On Oct. 19, 2018, TransAlta Renewables announced that the Kent Hills 3 expansion was fully operational, bringing total generating capacity of the Kent Hills wind facility to 167 MW.





TRANSALTA CORPORATION F37
Notes to Consolidated Financial Statements
V. TransAlta Renewables Acquires Three Renewable Assets from the Corporation
On May 31, 2018, TransAlta Renewables acquired from a subsidiary of the Corporation an economic interest in the 50 MW Lakeswind wind facility in Minnesota and 21 MWs of solar projects located in Massachusetts ("Mass Solar") through the subscription of tracking preferred shares of a subsidiary of the Corporation. In addition, TransAlta Renewables acquired from a subsidiary of the Corporation ownership of the 20 MW Kent Breeze wind facility located in Ontario. The total purchase price for the three assets was approximately $166 million, including the assumption of $62 million of tax equity obligations and project debt, for net cash consideration of $104 million. The Corporation continues to operate these assets on behalf of TransAlta Renewables.

The acquisition of Kent Breeze was accounted for by TransAlta Renewables as a business combination under common control, requiring the application of the pooling of interests method of accounting, whereby the assets and liabilities acquired were recognized at the book values previously recognized by TransAlta at May 31, 2018, and not at their fair values. As a result, the Corporation recognized a transfer of equity from the non-controlling interests in the amount of $1 million in 2018.

On June 28, 2018, TransAlta Renewables subscribed for an additional $33 million (US$25 million) of tracking preferred shares of a subsidiary of the Corporation related to Mass Solar to fund the repayment of Mass Solar's project debt.

In connection with these acquisitions, the Corporation recorded a $12 million impairment charge, of which $11 million was recorded against PP&E and $1 million against intangibles. See Note 7 for further details.

W. TransAlta Renewables Closes $150- Million Share Offering of Common Shares
On June 22, 2018, TransAlta Renewables closed a bought deal offering of 11,860,000 common shares through a syndicate of underwriters (the "Share Offering"). The common shares were issued at a price of $12.65 per common share for gross proceeds of approximately $150 million ($144 million of net proceeds).

The net proceeds of the Share Offering were used to partially repay drawn amounts under TransAlta Renewables' credit facility, which was drawn in order to fund recent acquisitions. The additional liquidity under the credit facility was used for general corporate purposes, including ongoing construction costs associated with the US Wind Projects, described in 4(J) above.

The Corporation did not purchase any additional common shares under the Share Offering and, following the closing, owned 161 million common shares, representing approximately 61 per cent of the outstanding common shares of TransAlta Renewables. See Note 13 for further details of TransAlta's ownership of TransAlta Renewables.

X. $345 Million Financing Related to the Off-Coal Agreement
On July 20, 2018, the Corporation monetized the payments under OCA with the Government of Alberta by closing a $345 million bond offering through its indirect wholly owned subsidiary, TransAlta OCP LP ("TransAlta OCP"). The offering was a private placement that was secured by, among other things, a first ranking charge over the OCA payments payable by the Government of Alberta. The amortizing bonds bear interest at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030. The bonds have a rating of BBB, with a stable trend, by DBRS. Under the terms of the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million, net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030.

The net proceeds were used to partially repay the 6.40 per cent debentures, as described in Note 24.





TRANSALTA CORPORATION F38
Notes to Consolidated Financial Statements
5. Revenue
A. Disaggregation of Revenue
The majority of the Corporation's revenues are derived from the sale of physical power, capacity and environmental attributes, leasing of power facilities, and from asset optimization activities, which the Corporation disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue.
Year ended Dec. 31, 2020 Hydro Wind
and
Solar
North American
Gas(1)
Australian
Gas
Alberta Thermal(2)
Centralia(2)
Energy
Marketing 		Corporate and Other Total
Revenues from contracts with
customers 		141  261  196  90  325  10  —  —  1,023 
Revenue from leases(3)
—  —  8  60  55  —  —  —  123 
Revenue from derivatives and
other trading activities 		—  (2) 4  —  (12) 283  122  12  407 
Government incentives 1  4  —  —  —  —  —  —  5 
Revenue from other(4)
10  66  9  8  251  204  —  (5) 543 
Total revenue 152  329  217  158  619  497  122  7  2,101 
Revenues from contracts with customers
Timing of revenue recognition
   At a point in time —  25  —  —  23  10  —  —  58 
   Over time 141  236  196  90  302  —  —  —  965 
Total revenue from contracts
with customers 		141  261  196  90  325  10  —  —  1,023 
(1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted.
(2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
(3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases.
(4) Includes merchant revenue and other miscellaneous.

Year ended Dec. 31, 2019 Hydro Wind
and
Solar
North American
Gas(1)
Australian
Gas
Alberta Thermal(2)
Centralia(2)
Energy
Marketing 		Corporate and Other Total
Revenues from contracts with
customers 		142  244  190  87  395  10  —  —  1,068 
Revenue from leases(3)
—  —  —  65  65  —  —  —  130 
Revenue from derivatives and
other trading activities 		—  18  2  —  (17) 160  129  4  296 
Government incentives —  8  —  —  —  —  —  —  8 
Revenue from other(4)
14  42  17  8  373  401  —  (10) 845 
Total revenue 156  312  209  160  816  571  129  (6) 2,347 
Revenues from contracts with customers
Timing of revenue recognition
   At a point in time —  27  —  —  41  10  —  —  78 
   Over time 142  217  190  87  354  —  —  —  990 
Total revenue from contracts with customers 142  244  190  87  395  10  —  —  1,068 
(1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted.
(2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
(3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases.
(4) Includes merchant revenue and other miscellaneous.






TRANSALTA CORPORATION F39
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2018 Hydro Wind and
Solar
North American Gas(1)
Australian
Gas
Alberta Thermal(2)
Centralia(2)
Energy
Marketing 		Corporate Total
Revenues from contracts with
customers 		132  206  206  91  517  9  —  —  1,161 
Revenue from leases(3)
7  27  —  68  68  —  —  —  170 
Revenue from derivatives and
other trading activities 		—  (20) 4  —  (1) 115  67  —  165 
Government incentives —  16  —  —  —  —  —  —  16 
Revenue from other(4)
17  53  22  6  328  318  —  (7) 737 
Total revenue 156  282  232  165  912  442  67  (7) 2,249 
Revenues from contracts with customers
Timing of revenue recognition
   At a point in time —  18  —  —  38  9  —  —  65 
   Over time 132  188  206  91  479  —  —  —  1,096 
Total revenue from contracts with customers 132  206  206  91  517  9  —  —  1,161 
(1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details. In addition, during the third quarter of 2020, merchant revenue within this segment was reclassified from revenue from contracts with customers to revenue from other and prior periods were adjusted.
(2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
(3) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases.
(4) Includes merchant revenue and other miscellaneous.

B. Contract Liabilities
The Corporation has recognized the following revenue-related contract liabilities:
Contract liabilities 2020 2019
Balance, beginning of the year 15  88 
IFRS 16 transition adjustments(1)
—  15 
Amounts transferred to revenue included in opening balance (1) (10)
Consideration received 1  5 
Increases due to interest accrued and expensed during the period —  5 
Contract termination associated with the purchase of Keephills 3 (Note 4(R))
—  (88)
Consideration paid 2  — 
Performance obligations satisfied (2) — 
Balance, end of year 15  15 
Current portion 1  1 
Long-term portion 14  14 
(1) In 2019, on transition to IFRS 16, some contracts that were previously considered leases under IAS 17 did not meet the definition of a lease under IFRS 16 and therefore were assessed under IFRS 15 and balances were transferred from deferred revenue to contract liabilities.

The opening contract liabilities in 2019 were primarily comprised of consideration received from the Corporation’s Keephills 3 joint operation partner, Capital Power, for which the Corporation had a future obligation to transfer goods and services to Capital Power under the contract. On closing of the Keephills 3 and Genesee 3 swap, wherein the Corporation acquired Capital Power's 50 per cent ownership interest in Keephills 3 and sold its 50 per cent ownership interest in Genesee 3, the agreement with Capital Power was terminated in 2019 and the Corporation no longer had any further performance obligations and the related contract liability balance was recognized in net earnings.

The remaining contract liabilities outstanding at Dec. 31, 2020, and Dec. 31, 2019, primarily relate to prepayments relating to the Corporation's New Richmond and Bone Creek facilities where the Corporation still has to fulfil its performance obligations.





TRANSALTA CORPORATION F40
Notes to Consolidated Financial Statements
C. Remaining Performance Obligations
The following disclosures regarding the aggregate amounts of transaction prices allocated to remaining performance obligations (contract revenues that have not yet been recognized) for contracts in place at the end of the reporting period exclude revenues related to contracts that qualify for the following practical expedients:
▪The Corporation recognizes revenue from the contract in an amount that is equal to the amount invoiced where the amount invoiced represents the value to the customer of the service performed to date. Certain of the Corporation’s contracts at some of its wind, hydro, gas and solar facilities, and within its commercial and industrial business, qualify for this practical expedient. For these contracts, the Corporation is not required to disclose information about the remaining unsatisfied performance obligations.
▪Contracts with an original expected duration of less than 12 months.

Additionally, in many of the Corporation’s contracts, elements of the transaction price are considered constrained, such as for variable revenues dependent upon future production volumes that are driven by customer or market demand or market prices that are subject to factors outside the Corporation’s influence. Future revenues that are related to constrained variable consideration are not included in the disclosure of remaining performance obligations until the constraints are resolved. Further, adjustments to revenue to recognize a significant financing component in a contract are not included in the amounts disclosed for remaining performance obligations.

As a result, the amounts of future revenues disclosed below represent only a portion of future revenues that are expected to be realized by the Corporation from its contractual portfolio.

Hydro
At Dec. 31, 2020, the Corporation's PPA with the Balancing Pool to provide the capacity of 12 hydro facilities throughout the province of Alberta concluded. Future production will be sold into the merchant market. The Corporation has contracts for blackstart services at specific hydro facilities, which will conclude at the end of 2030. The Corporation also has a contract with the Government of Alberta to manage water on the Bow River for flood and drought mitigation purposes, which concludes in 2021.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2020, are approximately $31 million, which the Corporation expects to recognize approximately $8 million in 2021 and approximately $2 million to $3 million annually from 2022-2030.

The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to all hydro energy contracts in Ontario, British Columbia and Washington; accordingly, disclosures related to remaining performance obligations are not provided for these contracts.

Wind and Solar
At Dec. 31, 2020, the Corporation had long-term contracts with customers to deliver electricity and the associated renewable energy credits from three wind facilities located in Alberta, Minnesota and Quebec, for which the invoice practical expedient is not applied. The PPAs generally require all available generation to be provided to customers at fixed prices, with certain pricing subject to annual escalations for inflation. The Corporation expects to recognize such amounts as revenue as it delivers electricity over the remaining terms of the contracts, until 2024, 2034 and 2033, respectively. Electricity delivered is ultimately dependent upon the wind resource, which is outside of the Corporation’s control. Amounts delivered, and therefore revenue recognized, in the future will vary. These variable revenues for electricity delivered are considered to be fully constrained, and will be recognized over time as the performance obligation, the delivery of electricity, is satisfied. Accordingly, these revenues are excluded from these disclosures. The Corporation also has contracts to sell renewable energy certificates generated at merchant wind facilities and expects to recognize revenues as it delivers the renewable energy certificates to the purchasers over the remaining terms of the contracts, from 2020 through 2024.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2020, are approximately $13 million, of which the Corporation expects to recognize between approximately $2 million to $5 million annually through to contract expiry.

The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to wind energy contracts in Ontario, New Brunswick, Quebec and Wyoming, and for all solar contracts; accordingly, disclosures related to remaining performance obligations are not provided for these contracts.





TRANSALTA CORPORATION F41
Notes to Consolidated Financial Statements
North American Gas
At Dec. 31, 2020, the Corporation has contracts with customers to deliver energy services from one of its gas facilities in Ontario. The contracts all consist of a single performance obligation requiring the Corporation to stand ready to deliver electricity and steam. A summary of the key terms of these contracts is set out below.

The energy supply agreements require specified amounts of steam to be delivered to each customer, and have pricing terms that include fixed and variable charges for electricity, capacity and steam, as well as a true-up based on contractual minimum volumes of steam. The steam reconciliation is based on an estimate of the customer’s steam volume taken and the contractual minimum volume, and various factors including the annual average market price of electricity and the average locally posted and index prices of natural gas, as well as transportation. For steam volumes not taken by the customer, a revenue-sharing mechanism provides for sharing of revenues earned by the Corporation using that steam to generate and sell electricity. Capacity and electricity pricing vary from contract to contract and are subject to annual indexation at varying rates. Electricity and steam delivered is ultimately dependent upon customer requirements, which is outside of the Corporation’s control. The variable revenues under the contracts are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Corporation expects to recognize revenue as it delivers electricity and steam until the completion of the contract in late 2022.

At the same gas facility, the Corporation has a contract with the local power authority with fixed capacity charges that are adjusted for seasonal fluctuations, steam demand from the plant’s other customers and for deemed net revenue related to production of electricity into the market. As a result, revenues recognized in the future will vary as they are dependent upon factors outside of the Corporation’s control and are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Corporation expects to recognize such revenue as it stands ready to deliver electricity until the completion of the contract term on Dec. 31, 2025.

At Dec. 31, 2020, the Corporation had contracts with customers to deliver steam, hot water and chilled water from one of its other gas facilities in Ontario, extending through 2023. Prices under these contracts are at fixed base amounts per gigajoule and are subject to escalation annually for both gas prices and inflation. The contracts include minimum annual take-or-pay volumes.

The Corporation's contract with its customer for provision of steam and electricity output at its Alberta cogeneration facility, effective Jan. 1, 2020 through Dec. 31, 2029, is considered an operating lease resulting in some revenues being classified for accounting purposes as variable lease revenues. Other revenue streams are based on cost-recovery mechanisms and thus are variable in nature and are considered to be fully constrained and excluded from these disclosures.

Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2020, are approximately $13 million in total, of which the Corporation expects to recognize between approximately $4 million to $5 million annually for the duration of the contracts.

The practical expedient allowing the recognition of revenue from the contract in an amount that is equal to the amount invoiced is applied to some of the Corporation’s other gas facilities’ contracts in Ontario and the United States; accordingly, disclosures related to remaining performance obligations are not provided for these contracts.

Australian Gas
At Dec. 31, 2020, the Corporation has PPAs with customers to deliver electricity from its gas facilities located in Australia. The PPAs generally call for all available generation to be provided to customers. Pricing terms include fixed and variable price components for delivered electricity and fixed capacity payments. Prices may be subject to true-up adjustments for deviations from expected heat rates and are subject to various escalators to reflect inflation. Electricity delivered is ultimately dependent upon customer requirements, which is outside of the Corporation’s control. These variable revenues for electricity delivered are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of electricity, is satisfied. Accordingly, these revenues are excluded from these disclosures. The contracts have durations that range from 2026 to 2042.

One of the Corporation's PPA with its customer to deliver electricity from its gas facilities is considered a finance lease resulting in some revenues being classified for accounting purposes as finance lease income. The Corporation also earns revenues from providing operation and maintenance services for the facility for a fixed monthly fee. Pricing is subject to periodic review under the PPA and subject to escalation to reflect inflation out to the end of the contract in 2038. Other revenue streams are based on cost-recovery mechanisms and thus are variable in nature and considered to be fully constrained and excluded from these disclosures.





TRANSALTA CORPORATION F42
Notes to Consolidated Financial Statements
Estimated future revenues related to the remaining performance obligations for these contracts as at Dec. 31, 2020, are approximately $2,594 million, of which the Corporation expects to recognize approximately $203 million in total over the next two fiscal years and on average, between approximately $100 million to $126 million annually thereafter for the duration of the remaining contract.

Alberta Thermal
At Dec. 31, 2020, the Corporation's PPAs with the Balancing Pool for capacity and electricity from two of its coal facilities concluded. Future production will be sold into the merchant market.

The Corporation also has several contracts for sale of byproducts of coal combustion from certain of its coal facilities. The contracts range in duration from one to three years. Generally, revenues vary based on market prices that are subject to factors outside of the Corporation’s control, and the quantities delivered and sold, which are ultimately dependent upon customer demand. These variable revenues are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of byproducts, is satisfied. Accordingly, these revenues are excluded from these disclosures.

The Corporation has a contract, commencing in late 2023, for the sale of capacity and electricity, exercisable at the option of the customer, under which the Corporation will receive a fixed capacity payment and variable energy payments based on production. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2020, are approximately $336 million, of which the Corporation expects to recognize on average, between $5 million to $10 million in 2023 and $40 million to $45 million annually thereafter for the duration of the contracts.

Centralia
The Corporation’s long-term contract for the sale of electricity produced at its US Coal plant is considered a derivative and is designated as an all-in-one hedge. Accordingly, while revenues for electricity delivered to the customer are recognized pursuant to the contractual terms, the revenues are not accounted for under IFRS 15 and the contract has been excluded from any required IFRS 15 disclosures.

The Corporation also has a contract for the sale of byproducts of coal combustion from its US Coal plant. Generally, revenues vary based on market prices that are subject to factors outside of the Corporation’s control, and the quantities delivered and sold, which are ultimately dependent upon customer demand. These variable revenues are considered to be fully constrained, and will be recognized at a point in time as the performance obligation, the delivery of byproducts, is satisfied. Accordingly, these revenues are excluded from these disclosures.

6. Expenses by Nature
Expenses classified by nature are as follows:
Year ended Dec. 31 2020 2019 2018
  Fuel, carbon compliance and
purchased
power 		Operations,
maintenance and
administration 		Fuel, carbon compliance and
purchased
power 		Operations,
maintenance and
administration 		Fuel, carbon compliance and
purchased
power 		Operations,
maintenance and
administration
Fuel and carbon compliance 574  —  669  —  656  — 
Coal inventory writedown (Note 17) 37  —  —  —  —  — 
Purchased power 163  —  246  —  210  — 
Mine depreciation 144  —  119  —  136  — 
Salaries and benefits 50  235  52  228  98  245 
Other operating expenses —  237  —  247  —  270 
Total 968  472  1,086  475  1,100  515 






TRANSALTA CORPORATION F43

Notes to Consolidated Financial Statements
7. Asset Impairment and Reversals
As part of the Corporation’s monitoring controls, long-range forecasts are prepared for each CGU. The long-range forecast estimates are used to assess the significance of potential indicators of impairment and provide criteria to evaluate adverse changes in operations. The Corporation also considers the relationship between its market capitalization and its book value, among other factors, when reviewing for indicators of impairment. When indicators of impairment are present, the Corporation estimates a recoverable amount for each CGU by calculating an approximate fair value less costs of disposal using discounted cash flow projections based on the Corporation’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Corporation’s long-range forecast, including changes to fuel costs, operating costs, capital expenditures, external power prices and useful lives of the assets extending to the last planned asset retirement in 2073.

A. 2020
Sundance Unit 3
In the third quarter of 2020, the Corporation recognized an impairment on Sundance Unit 3 in the amount of $70 million in the Alberta Thermal segment, due to the Corporation's decision to retire the unit (see Note 4(O)). Previously, the Corporation had expected Sundance Unit 3 to remain mothballed until November 2021. As there were no estimated future cash flows from power generation expected to be derived from the unit, the unit was removed from the Alberta merchant CGU and immediately written down to the recoverable value of the scrap materials.

BC Hydro Facility
In the third quarter of 2020, the Corporation recorded an impairment of $2 million in the Hydro segment, due to a review of water resources that resulted in a revision to the forecasted production at a BC hydro facility. The impairment assessment was based on fair value less costs of disposal using discounted cash flow projections based on the Corporation's long-range forecasts. The resulting fair value measurement is categorized as a Level III fair value measurement. The key assumptions impacting the determination of fair value are electricity production and sales prices, which are subject to measurement uncertainty.

Centralia Land
In the fourth quarter of 2020, the Corporation recognized an impairment of $9 million (US$7 million) in the Centralia segment due to a decrease in the fair value of the land determined through a third-party appraiser.

In addition to the asset impairments noted above, a net asset impairment of $3 million was recognized for changes in the decommissioning and restoration liabilities related to the Centralia mine and Sundance Unit 1, which are no longer operating and have reached the end of their useful lives (see Note 23).

B. 2019
Centralia Thermal Facility
In 2012, the Corporation recorded an impairment of $347 million relating to the Centralia thermal facility CGU. As part of the annual impairment test, the Corporation considers possible indicators of impairment at the Centralia thermal facility CGU. In 2019, an internal valuation indicated the fair value less costs of disposal of the Centralia thermal facility CGU exceeded the carrying value, resulting in a full recoverability test in 2019. The updated fair value included sustained changes in the power price market and cost of coal due to contract renegotiations. As a result of the recoverability test, an impairment reversal of $151 million was recorded in the Centralia segment.
The valuations are categorized as Level III fair value measurements and subject to measurement uncertainty based on the key assumptions outlined below, and on inputs to the Corporation’s long-range forecast, including changes to fuel costs, operating costs, capital expenses and the level of contractedness under the Memorandum of Agreement ("MOA") for coal transition established with the State of Washington. The valuation period includes cash flows until the decommissioning of the facility in 2025.

The Corporation utilized the Corporation's long-range forecast and the following key assumptions in 2019 compared with 2016 assumptions, which was the most recent detailed valuation:
2019 2016
Mid-Columbia annual average power prices
US$30 to US$42 per MWh
US$22 to US$46 per MWh
On-highway diesel fuel on coal shipments
US$2.35 to US$2.40 per gallon
US$1.69 to US$2.09 per gallon
Discount rates
5.2 to 6.4 per cent
5.4 to 5.7 per cent





TRANSALTA CORPORATION F44
Notes to Consolidated Financial Statements
During 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will occur as originally proposed. At the end of 2019, the Corporation's best estimate of the decommissioning and restoration provision increased by $141 million. Since the Centralia mine is no longer operating and reached the end of its useful life in 2006, this adjustment results in the immediate recognition of the full $141 million, through asset impairment charges in net earnings.

Refer to Note 3(A)(III) and 23 for further details on the Centralia mine decommissioning and restoration provision.

Assets Held for Sale
In the fourth quarter of 2019, the Corporation identified several trucks and associated inventory to be sold within the Alberta Thermal segment and accordingly wrote the assets down to net realizable value, resulting in an impairment charge of $15 million.

C. 2018

Sundance Unit 2
In the third quarter of 2018, the Corporation recognized an impairment charge on Sundance Unit 2 in the amount of $38 million, due to the Corporation’s decision to retire Sundance Unit 2. Previously, the Corporation had expected Sundance Unit 2 to remain mothballed for a period of up to two years and therefore remain within the Alberta merchant CGU. The impairment assessment was based on value in use and included the estimated future cash flows expected to be derived from the unit until its retirement on July 31, 2018. Discounting did not have a material impact.
Lakeswind and Kent Breeze
On May 31, 2018, TransAlta Renewables acquired an economic interest in Lakeswind through the subscription of tracking preferred shares of a subsidiary of the Corporation and also purchased Kent Breeze (see Note 4(V)). In connection with these acquisitions, the assets were fair valued using discount rates that average approximately seven per cent. Accordingly, the Corporation has recorded an impairment of $12 million using the valuation in the agreement as the indicator of fair value less cost of disposal in 2018. The impairment charge had an $11 million impact on PP&E and a $1 million impact on intangible assets (refer to Note 18 and 20).
D. Project Development Costs
During 2020, the Corporation wrote off nil (2019 — $18 million; 2018 — $23 million) in project development costs related to projects that are no longer proceeding.

8. Finance Lease Receivables
Amounts receivable under the Corporation’s finance leases associated with the Poplar Creek cogeneration facility and in 2020, the Southern Cross Energy facilities are as follows:
As at Dec. 31 2020 2019
  Minimum
lease
receipts 		Present value of
minimum lease
receipts 		Minimum
lease
receipts 		Present value of
minimum lease
receipts
Within one year 63  56  20  20 
Second to fifth years inclusive 169  126  80  74 
More than five years 100  82  120  97 
  332  264  220  191 
Less: unearned finance lease income 68  —  29  — 
Total finance lease receivables 264  264  191  191 
Included in the Consolidated Statements of Financial Position as:        
Current portion of finance lease receivables (Note 14) 36    15   
 Long-term portion of finance lease receivables 228    176   
  264    191   





TRANSALTA CORPORATION F45

Notes to Consolidated Financial Statements
9. Net Other Operating Income
Net other operating income includes the following:
Year ended Dec. 31 2020 2019 2018
Coal supply agreement 29  —  — 
Alberta Off-Coal Agreement (40) (40) (40)
Insurance recoveries —  (10) (7)
Other expenses —  1  — 
Net other operating income (11) (49) (47)

A.Onerous Contract Provision for Coal Supply Agreement
During the fourth quarter of 2020, an onerous contract provision of $29 million was recognized as a result of a decision to accelerate our plans to eliminate coal as a fuel source by the end of 2021 at the Sheerness facility. The last coal shipment is expected to be received during the first quarter of 2021, while payments required under the contract will continue until 2025.

B. Alberta Off-Coal Agreement
The Corporation receives payments from the Government of Alberta for the cessation of coal-fired emissions from its interest in the Keephills 3, Genesee 3 and Sheerness coal-fired plants on or before Dec. 31, 2030. The swap of ownership interests in Keephills 3 and Genesee 3 did not impact the payments received. Refer to Note 4(R) for further details.

Under the terms of the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million ($37 million, net to the Corporation), which commenced Jan. 1, 2017, and will terminate at the end of 2030. The Corporation recognizes the off-coal payments evenly throughout the year. Receipt of the payments is subject to certain terms and conditions. The OCA’s main condition is the cessation of all coal-fired emissions on or before Dec. 31, 2030. The affected plants are not, however, precluded from generating electricity at any time by any method, other than generation resulting in coal-fired emissions after Dec. 31, 2030. In July 2018, the Corporation obtained financing against the OCA payments. Refer to Note 4(X) and 24 for further details.

C. Insurance Recoveries
There were no insurance recoveries in 2020.

During 2019, the Corporation received $10 million in insurance recoveries, which related to insurance proceeds for tower fires at Wyoming and Summerview.

During 2018, the Corporation received $7 million in insurance recoveries, of which $6 million related to insurance proceeds for the tower fire at Wyoming and a $1 million claim related to equipment repairs within Alberta Thermal.

10. Investments
The Corporation’s investments in joint ventures and associates that are accounted for using the equity method consist of its investments in Skookumchuck and EMG.

The change in investments is as follows:
Skookumchuck EMG Total
Balance, Dec. 31, 2019 —  —  — 
Contributions(1)
86  16  102 
Equity income 1  —  1 
Change in foreign exchange rates (2) (1) (3)
Balance, Dec. 31, 2020 85  15  100 
(1) Contributions were paid in US dollars and were US$66 million for Skookumchuck and US$12 million for EMG, including contingent consideration.





TRANSALTA CORPORATION F46
Notes to Consolidated Financial Statements
Summarized financial information on the results of operations relating to the Corporation’s pro-rata interests in Skookumchuck and EMG is as follows:
Year ended Dec. 31 2020
Results of operations
Revenues 3 
Expenses (2)
Proportionate share of net earnings 1 

On Nov. 25, 2020, TransAlta purchased a 49 per cent interest in Skookumchuck, a 136.8 MW wind facility located in Lewis and Thurston counties near Centralia in Washington state consisting of 38 Vestas 136 wind turbines. Summarized financial information relating to 100 per cent of Skookumchuck, including adjustments for the application of consistent accounting policies and the Corporation’s purchase price adjustments, is as follows:
Year ended Dec. 31 2020
Revenues 6 
Depreciation and amortization 2 
Interest expense 1 
Net earnings 3 
Other comprehensive loss — 
Total comprehensive loss 3 
As at Dec. 31 2020
Current assets 6 
Non-current assets 382 
Current liabilities (65)
Non-current liabilities (150)
Net assets 173 
Additional items included above
Cash and cash equivalents 1 
Current financial liabilities(1)
(27)
Non-current financial liabilities(1)
(147)
(1) Excludes trade and other payables and provisions.

A reconciliation of the carrying amount to the Corporation’s 49 per cent interest in the Skookumchuck is as follows:
As at Dec. 31 2020
Net assets 173 
Less: 51 per cent of Skookumchuck net assets not owned by the Corporation (88)
Net investment 85 

Skookumchuck’s ability to make distributions to its owners, including the Corporation, is dependent on available cash flow and is restricted by covenants and conditions, including principal and interest funding requirements imposed by the tax equity financing agreements.

Skookumchuck's approximate future payments under contractual commitments are as follows:
  2021 2022 2023 2024 2025 2026 and thereafter Total
Long-term service agreements(1)
1  1  1  1  1  28  33 
(1) Refer to Note 36 for further details on long-term service agreements.





TRANSALTA CORPORATION F47

Notes to Consolidated Financial Statements
11. Net Interest Expense
The components of net interest expense are as follows: 
Year ended Dec. 31 2020 2019 2018
Interest on debt 158  161  184 
Interest on exchangeable securities (Note 25)
34  20  — 
Interest income (10) (13) (11)
Capitalized interest (Note 18)
(8) (6) (2)
Loss on redemption of bonds (Note 24)
—  —  24 
Interest on lease liabilities 8  4  3 
Credit facility fees, bank charges and other interest 18  15  13 
Tax shield on tax equity financing (Note 24)(1)
1  (35) — 
Interest on line loss rule proceeding (Note 36(I)(I)) 5  —  — 
Other(2)
2  10  15 
Accretion of provisions (Note 23) 30  23  24 
Net interest expense 238  179  250 
(1) Relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim projects that was assigned to the tax equity investor. The tax equity investment is treated as debt under IFRS and the monetization of the tax depreciation is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.
(2) In 2020, other interest expense included approximately nil (2019 — $5 million, 2018 — $7 million) for the significant financing component required under IFRS 15. In addition, in 2018, approximately $5 million of costs were expensed due to project-level financing that is no longer practicable.






TRANSALTA CORPORATION F48
Notes to Consolidated Financial Statements
12. Income Taxes
A. Consolidated Statements of Earnings

I. Rate Reconciliations
Year ended Dec. 31 2020 2019 2018
Earnings (loss) before income taxes (303) 193  (96)
Net earnings (loss) attributable to non-controlling interests not subject to tax 2  (26) (19)
Adjusted earnings (loss) before income taxes (301) 167  (115)
Statutory Canadian federal and provincial income tax rate (%) 24.5  % 26.5  % 26.8  %
Expected income tax expense (recovery) (74) 44  (31)
Increase (decrease) in income taxes resulting from:      
Differences in effective foreign tax rates 3  5  (3)
Deferred income tax expense related to temporary difference on investment in
subsidiaries 		9  —  — 
Writedown (reversal of writedown) of deferred income tax assets 8  (9) 27 
Statutory and other rate differences (7) (31) — 
Other 11  8  1 
Income tax expense (recovery) (50) 17  (6)
Effective tax rate (%) 17  % 10  % 5  %

II. Components of Income Tax Expense
The components of income tax expense are as follows:
Year ended Dec. 31 2020 2019 2018
Current income tax expense 35  35  28 
Deferred income tax expense (recovery) related to the origination and reversal of
temporary differences 		(95) 22  (61)
Deferred income tax expense related to temporary difference on investment in
subsidiary 		9  —  — 
Deferred income tax recovery resulting from changes in tax rates or laws(1)
(7) (31) — 
Deferred income tax expense (recovery) arising from the writedown (reversal of
   writedown) of deferred income tax assets(2)
8  (9) 27 
Income tax expense (recovery) (50) 17  (6)
Year ended Dec. 31 2020 2019 2018
Current income tax expense 35  35  28 
Deferred income tax recovery (85) (18) (34)
Income tax expense (recovery) (50) 17  (6)
(1) In 2020 the Corporation recognized a deferred income tax recovery of $7 million (2019 —$31 million) related to a decrease in the Alberta corporate tax rate from 11 per cent to 8 per cent. The tax decrease was originally scheduled as follows: 11 per cent effective July 1, 2019, 10 per cent effective Jan. 1, 2020, 9 per cent effective Jan. 1, 2021, and 8 per cent effective Jan. 1, 2022. The Government of Alberta enacted the rate to decrease to 8 per cent effective Dec. 9, 2020.
(2) During the year ended Dec. 31, 2020, the Corporation recorded a writedown of deferred tax assets of $8 million (2019 — $9 million writedown reversal, 2018 — $27 million writedown). In the current year additional deferred tax assets were created from the recognition of other comprehensive losses in the US. The deferred income tax assets mainly relate to the tax benefits of losses associated with the Corporation’s directly owned US operations. The Corporation evaluates at each period end, whether it is probable that sufficient future taxable income would be available from the Corporation’s directly owned US operations to utilize the underlying tax losses.





TRANSALTA CORPORATION F49

Notes to Consolidated Financial Statements
B. Consolidated Statements of Changes in Equity
The aggregate current and deferred income tax related to items charged or credited to equity are as follows:
Year ended Dec. 31 2020 2019 2018
Income tax expense (recovery) related to:      
Net impact related to cash flow hedges (23) 6  (12)
Net actuarial gains (losses) (3) (7) 5 
Income tax expense reported in equity (26) (1) (7)

C. Consolidated Statements of Financial Position
Significant components of the Corporation’s deferred income tax assets (liabilities) are as follows:
As at Dec. 31 2020 2019
Net operating loss carryforwards(1)
469  494 
Future decommissioning and restoration costs 140  122 
Property, plant and equipment (717) (828)
Risk management assets and liabilities, net (107) (141)
Employee future benefits and compensation plans 62  56 
Interest deductible in future periods 22  42 
Foreign exchange differences on US-denominated debt 31  40 
Other deductible temporary differences 2  4 
Net deferred income tax liability, before writedown of deferred income tax assets (98) (211)
Writedown of deferred income tax assets (247) (243)
Net deferred income tax liability, after writedown of deferred income tax assets (345) (454)
(1) Net operating losses expire between 2029 and 2039.

The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows:
As at Dec. 31 2020 2019
Deferred income tax assets(1)
51  18 
Deferred income tax liabilities (396) (472)
Net deferred income tax liability (345) (454)
 
(1) The deferred income tax assets presented on the Consolidated Statements of Financial Position are recoverable based on estimated future earnings and tax planning strategies. The assumptions used in the estimate of future earnings are based on the Corporation’s long-range forecasts.
 
D. Contingencies
As of Dec. 31, 2020, the Corporation had recognized a net liability of nil (2019 — $1 million) related to uncertain tax positions.

13. Non-Controlling Interests
The Corporation’s subsidiaries and operations that have non-controlling interests are as follows:
Subsidiary/Operation
Non-controlling interest as at Dec. 31, 2020
TransAlta Cogeneration L.P.
49.99% - Canadian Power Holdings Inc.
TransAlta Renewables
39.9% - Public shareholders
Kent Hills Wind LP(1)
17% - Natural Forces Technologies Inc.
 (1) Owned by TransAlta Renewables.

TransAlta Cogeneration, L.P. (“TA Cogen”) operates a portfolio of cogeneration facilities in Canada and owns 50 per cent of a dual-fuel generating facility. TransAlta Renewables owns and operates a portfolio of gas and renewable power generation facilities in Canada and owns economic interests in various other gas and renewable facilities of the Corporation.




TRANSALTA CORPORATION F50
Notes to Consolidated Financial Statements
Summarized financial information relating to subsidiaries with significant non-controlling interests is as follows:
A. TransAlta Renewables
 
The net earnings, distributions and equity attributable to non-controlling interests include the 17 per cent non-controlling interest in the 167 MW Kent Hills wind facility located in New Brunswick.
On May 31, 2018, TransAlta Renewables implemented a dividend reinvestment plan ("DRIP") for Canadian holders of common shares of TransAlta Renewables. Commencing with the dividend paid on July 31, 2018, eligible shareholders could elect to automatically reinvest monthly dividends into additional common shares of the Corporation. The Corporation does not participate in the DRIP.
In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends. The dividend paid on Oct. 30, 2020, to shareholders of record on Oct. 15, 2020, was the last dividend payment eligible for reinvestment by participating shareholders. Subsequent dividends will be paid only in cash.
As a result of the DRIP and the Share Offering described in Note 4(W), the Corporation’s share of ownership and equity participation in TransAlta Renewables has changed as follows:
Period Ownership and voting
rights percentage 		Equity participation
percentage
Aug. 1, 2017 to June 21, 2018 64.0  64.0 
June 22, 2018 to July 30, 2018 61.1  61.1 
July 31, 2018 to Nov. 29, 2018 61.0  61.0 
Nov. 30, 2018 to Dec. 31, 2018 60.9  60.9 
Jan. 1, 2019 to Mar. 31, 2019 60.8  60.8 
April 1, 2019 to June 30, 2019 60.6  60.6 
July 1, 2019 to Sept. 30, 2019 60.5  60.5 
Oct. 1, 2019 to Dec. 31, 2019 60.4  60.4 
Jan. 1, 2020 to Mar. 31, 2020 60.3  60.3 
April 1, 2020 to June 30, 2020 60.2  60.2 
July 1, 2020 to Dec. 31, 2020 60.1  60.1 

Year ended Dec. 31 2020 2019 2018
Revenues 436  446  462 
Net earnings 97  183  241 
Total comprehensive income 223  138  281 
Amounts attributable to the non-controlling interests:    
Net earnings 40  73  94 
Total comprehensive income 90  56  110 
Distributions paid to non-controlling interests 80  69  79 

As at Dec. 31 2020 2019
Current assets 743  293 
Long-term assets 2,913  3,409 
Current liabilities (364) (152)
Long-term liabilities (987) (1,237)
Total equity (2,305) (2,313)
Equity attributable to non-controlling interests (948) (941)
Non-controlling interests’ share (per cent) 39.9 39.6





TRANSALTA CORPORATION F51

Notes to Consolidated Financial Statements
B. TA Cogen
Year ended Dec. 31 2020 2019 2018
Results of operations      
Revenues 146  181  185 
Net earnings (loss) (13) 43  29 
Total comprehensive income (loss) (13) 43  29 
Amounts attributable to the non-controlling interest:      
Net earnings (loss) (6) 21  14 
Total comprehensive income (loss) (6) 21  14 
Distributions paid to Canadian Power Holdings Inc. 17  37  86 

As at Dec. 31 2020 2019
Current assets 69  41 
Long-term assets 323  328 
Current liabilities (78) (27)
Long-term liabilities (37) (19)
Total equity (277) (323)
Equity attributable to Canadian Power Holdings Inc. (136) (160)
Non-controlling interest share (per cent) 49.99 49.99


14. Trade and Other Receivables
As at Dec. 31 2020 2019
Trade accounts receivable 488  399 
Collateral paid (Note 16) 49  42 
Current portion of finance lease receivables (Note 8) 36  15 
Income taxes receivable 10  6 
Trade and other receivables 583  462 





TRANSALTA CORPORATION F52
Notes to Consolidated Financial Statements
15. Financial Instruments
A. Financial Assets and Liabilities – Classification and Measurement
 
Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost. The following table outlines the carrying amounts and classifications of the financial assets and liabilities:

Carrying value as at Dec. 31, 2020
  Derivatives
used for
hedging 		Derivatives
held for
trading (FVTPL) 		Amortized cost Total
Financial assets        
Cash and cash equivalents(1)
—  —  703  703 
Restricted cash —  —  71  71 
Trade and other receivables —  —  583  583 
Long-term portion of finance lease receivable —  —  228  228 
Risk management assets        
Current 102  69  —  171 
Long-term 471  50  —  521 
Other assets (Note 22)
—  —  52  52 
Financial liabilities        
Accounts payable and accrued liabilities —  —  599  599 
Dividends payable —  —  59  59 
Risk management liabilities        
Current 10  84  —  94 
Long-term —  68  —  68 
Credit facilities, long-term debt and lease liabilities(2)
—  —  3,361  3,361 
Exchangeable securities (Note 25)
—  —  730  730 
(1) Includes cash equivalents of nil.
(2) Includes current portion.

Carrying value as at Dec. 31, 2019
  Derivatives
used for
hedging 		Derivatives
held for
trading (FVTPL) 		Amortized cost Total
Financial assets        
Cash and cash equivalents(1)
—  —  411  411 
Restricted cash —  —  32  32 
Trade and other receivables —  —  462  462 
Long-term portion of finance lease receivables —  —  176  176 
Risk management assets
Current 71  95  —  166 
Long-term 607  33  —  640 
Other assets (Note 22)
—  —  47  47 
Financial liabilities
Accounts payable and accrued liabilities —  —  413  413 
Dividends payable —  —  37  37 
Risk management liabilities
Current 1  80  —  81 
Long-term 1  28  —  29 
Credit facilities, long-term debt and lease liabilities(2)
—  —  3,212  3,212 
Exchangeable securities (Note 25)
—  —  326  326 

(1) Includes cash equivalents of nil.
(2) Includes current portion.




TRANSALTA CORPORATION F53

Notes to Consolidated Financial Statements
B. Fair Value of Financial Instruments
 
The fair value of a financial instrument is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair values can be determined by reference to prices for that instrument in active markets to which the Corporation has access. In the absence of an active market, the Corporation determines fair values based on valuation models or by reference to other similar products in active markets.
Fair values determined using valuation models require the use of assumptions. In determining those assumptions, the Corporation looks primarily to external readily observable market inputs. However, if not available, the Corporation uses inputs that are not based on observable market data.  
I. Level I, II and III Fair Value Measurements
 
The Level I, II and III classifications in the fair value hierarchy utilized by the Corporation are defined below. The fair value measurement of a financial instrument is included in only one of the three levels, the determination of which is based on the lowest level input that is significant to the derivation of the fair value.
a. Level I
 
Fair values are determined using inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Corporation has the ability to access at the measurement date. In determining Level I fair values, the Corporation uses quoted prices for identically traded commodities obtained from active exchanges such as the New York Mercantile Exchange.
b. Level II
Fair values are determined, directly or indirectly, using inputs that are observable for the asset or liability.

Fair values falling within the Level II category are determined through the use of quoted prices in active markets, which in some cases are adjusted for factors specific to the asset or liability, such as basis, credit valuation and location differentials. 
The Corporation’s commodity risk management Level II financial instruments include over-the-counter derivatives with values based on observable commodity futures curves and derivatives with inputs validated by broker quotes or other publicly available market data providers. Level II fair values are also determined using valuation techniques, such as option pricing models and interpolation formulas, where the inputs are readily observable.
In determining Level II fair values of other risk management assets and liabilities, the Corporation uses observable inputs other than unadjusted quoted prices that are observable for the asset or liability, such as interest rate yield curves and currency rates. For certain financial instruments where insufficient trading volume or lack of recent trades exists, the Corporation relies on similar interest or currency rate inputs and other third-party information such as credit spreads.
c. Level III
 
Fair values are determined using inputs for the assets or liabilities that are not readily observable. 
The Corporation may enter into commodity transactions for which market-observable data is not available. In these cases, Level III fair values are determined using valuation techniques such as mark-to-forecast and mark-to-model. For mark-to-model valuations, derivative pricing models, regression-based models and historical bootstrap models may be employed. The model inputs may be based on historical data such as unit availability, transmission congestion, demand profiles for individual non-standard deals and structured products, and/or volatilities and correlations between products derived from historical price relationships.

The Corporation also has various commodity contracts with terms that extend beyond a liquid trading period. As forward market prices are not available for the full period of these contracts, the value of these contracts is derived by reference to a forecast that is based on a combination of external and internal fundamental modelling, including discounting. As a result, these contracts are classified in Level III.
The Corporation has a Commodity Exposure Management Policy that governs both the commodity transactions undertaken in its proprietary trading business and those undertaken to manage commodity price exposures in its




TRANSALTA CORPORATION F54
Notes to Consolidated Financial Statements
generation business. This Policy defines and specifies the controls and management responsibilities associated with commodity trading activities, as well as the nature and frequency of required reporting of such activities. 
Methodologies and procedures regarding commodity risk management Level III fair value measurements are determined by the Corporation’s risk management department. Level III fair values are primarily calculated within the Corporation’s energy trading risk management system. These calculations are based on underlying contractual data as well as observable and non-observable inputs. Development of non-observable inputs requires the use of judgment. To ensure reasonability, system-generated Level III fair value measurements are reviewed and validated by the risk management and finance departments. Review occurs formally on a quarterly basis or more frequently if daily review and monitoring procedures identify unexpected changes to fair value or changes to key parameters.
Information on risk management contracts or groups of risk management contracts that are included in Level III measurements and the related unobservable inputs and sensitivities, is as follows, and excludes the effects on fair value of certain unobservable inputs such as liquidity and credit discount (described as “base fair values”), as well as inception gains or losses. Sensitivity ranges for the base fair values are determined using reasonably possible alternative assumptions for the key unobservable inputs, which may include forward commodity prices, commodity volatilities and correlations, delivery volumes and shapes.
As at Dec. 31, 2020
Description Base fair value Sensitivity Valuation technique Unobservable input Range Reasonable possible change
Long-term power sale – US
598
+35
Long-term price forecast Illiquid future power prices (per MWh)
US$24 to US$32
Price decrease of US$3 or price increase of US$5
-59
Coal transportation – US
(16)
+3
Numerical derivative valuation Illiquid future power prices (per MWh)
US$24 to US$32
Price decrease of US$3 or price increase of US$5
Volatility
15% to 40%
80% to 120%
-5
Rail rate escalation
US$21 to US$24
zero to 4%
Full requirements – Eastern US
11
+3
Historical bootstrap Volume
95% to 105%
-3
Cost of supply
(+/-) US$1 per MWh
Long-term wind energy sale –Eastern US
(29)
+22
Long-term price forecast Illiquid future power prices (per MWh)
US$35 to US$52
Price increase or decrease of US$6
-22
Illiquid future REC prices (per unit)
US$11
Price increase or decrease of US$1
Others (4)
+5
-5

As at Dec. 31, 2019
Description Base fair value Sensitivity Valuation technique Unobservable input Range Reasonable possible change
Long-term power sale – US 737 
+46
Long-term price forecast Illiquid future power prices (per MWh)
US$20 to US$28
Price decrease of US$3 or a price increase of US$9
-139
Structured products – Eastern US 7 
+2
Option valuation techniques, historical bootstrap and historical price regression analysis Basis relationship
91% to 112%
4% to 6%
-2
Non-standard shape factors
63% to 116%
4% to 10%
Full requirements –Eastern US 10 
+3
Historical bootstrap Volume
95% to 105%
-3
Cost of supply
(+/-) US$1 per MWh
Long-term wind energy sale – Eastern US (28)
+20
Long-term price forecast Illiquid future power prices (per MWh)
US$38 to US$60
Price increase or decrease of US$6
-20
Illiquid future REC prices (per unit)
US$9
Price increase or decrease of US$1
Others (6)
+8
-8




TRANSALTA CORPORATION F55

Notes to Consolidated Financial Statements
i. Long-Term Power Sale – US
The Corporation has a long-term fixed price power sale contract in the US for delivery of power at the following capacity levels: 380 MW through Dec. 31, 2024, and 300 MW through Dec. 31, 2025. The contract is designated as an all-in-one cash flow hedge.
For periods beyond 2022, market forward power prices are not readily observable. For these periods, fundamental-based forecasts and market indications have been used to determine proxies for base, high and low power price scenarios. The base price forecast has been developed by using a fundamental-based forecast (the provider is an independent and widely accepted industry expert for scenario and planning views). Prior to the second quarter of 2018, the base price forecast was developed using an additional independent industry forecast.
The contract is denominated in US dollars. With the weakening of the US dollar relative to the Canadian dollar from Dec. 31, 2019, to Dec. 31, 2020, the base fair value and the sensitivity values have decreased by approximately $14 million and $1 million, respectively. 
ii. Structured Products – Eastern US
 
The Corporation has structured fixed priced power in the eastern United States. Under these contracts, the Corporation has agreed to buy or sell power at non-liquid locations or during non-standard hours. As at Dec. 31, 2020, the Corporation did not have any material open positions on structured fixed priced power contracts.

The key unobservable inputs in the valuation of the fixed priced power contracts are market forward spreads and non-standard shape factors. A historical regression analysis has been performed to model the spreads between non-liquid and liquid hubs. The non-standard shape factors have been determined using the historical data.
iii. Coal Transportation - US
The Corporation has a coal rail transport agreement that includes an upside sharing mechanism, with a contract start date of Jan. 1, 2021, and extending until Dec. 31, 2025. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.

The key unobservable inputs used in the valuation include non-liquid power prices, option volatility and rail rate escalation. Reasonably possible alternative inputs were used to determine sensitivity on the fair value measurements.

For periods beyond 2022, market forward power prices are not readily observable. For these periods, fundamental-based forecasts and market indications have been used to determine proxies for base, high and low power price scenarios. The base price forecast has been developed by using a fundamental-based forecast (the provider is an independent and widely accepted industry expert for scenario and planning views). Option volatility and rail rate escalation ranges have been determined based on historical data and professional judgement.

iv. Full Requirements – Eastern US
The Corporation has a portfolio of full requirement service contracts, whereby the Corporation agrees to supply specific utility customer needs for a range of products that may include electrical energy, capacity, transmission, ancillary services, renewable energy credits and independent system operator costs.

The key unobservable inputs used in the portfolio valuation include delivered volume and supply cost. Hourly shaping of consumption will result in a realized cost that may be at a premium (or discount) relative to the average settled price. Reasonable possible alternative inputs are used to determine sensitivity on the fair value measurement.

v. Long-Term Wind Energy Sale – Eastern US
In relation to the Big Level, the Corporation has a long-term contract for differences whereby the Corporation receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh as well as the physical delivery of renewable energy credits ("RECs") based on proxy generation. Commercial operation of the facility was achieved in December 2019, with the contract commencing on July 1, 2019, and extending for 15 years after the commercial operation date. The contract is accounted for at fair value through profit or loss.
The key unobservable inputs used in the valuation of the contract are expected proxy generation volumes and non-liquid forward prices for power and RECs. 




TRANSALTA CORPORATION F56
Notes to Consolidated Financial Statements
II. Commodity Risk Management Assets and Liabilities
 
Commodity risk management assets and liabilities include risk management assets and liabilities that are used in the energy marketing and generation businesses in relation to trading activities and certain contracting activities. To the extent applicable, changes in net risk management assets and liabilities for non-hedge positions are reflected within earnings of these businesses.
Commodity risk management assets and liabilities classified by fair value levels as at Dec. 31, 2020, are as follows: Level I — $13 million net liability (Dec. 31, 2019 — $3 million net liability), Level II — $27 million net liability (Dec. 31, 2019 — $9 million net asset) and Level III — $582 million net asset (Dec. 31, 2019 — $686 million net asset).

Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2020, are primarily attributable to contract settlements, unfavourable changes in market prices and unfavourable changes in foreign exchange rates.

The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification level during the years ended Dec. 31, 2020 and 2019, respectively:
Year ended Dec. 31, 2020 Year ended Dec. 31, 2019
Hedge Non-hedge Total Hedge Non-hedge Total
 Opening balance 678  8  686  689  6  695 
 Changes attributable to:
   Market price changes on existing contracts (18) 3  (15) 77  8  85 
   Market price changes on new contracts —  7  7  —  14  14 
   Contracts settled (71) (10) (81) (57) (19) (76)
   Change in foreign exchange rates (16) 1  (15) (31) (1) (32)
  Transfers into (out of) Level III —  —  —  —  —  — 
 Net risk management assets at end of period 573  9  582  678  8  686 
 Additional Level III information:
   Gains (losses) recognized in other comprehensive
      income
(34) —  (34) 46  —  46 
  Total gains included in earnings before income taxes 71  11  82  57  21  78 
  Unrealized gains included in earnings before income
taxes relating to net assets held at period end 		—  1  1  —  2  2 

III. Other Risk Management Assets and Liabilities
 
Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied.
Other risk management assets and liabilities with a total net liability fair value of $12 million as at Dec. 31, 2020 (Dec. 31, 2019 – $4 million net asset) are classified as Level II fair value measurements. The significant changes in other net risk management assets and liabilities during the year ended Dec. 31, 2020, are primarily attributable to favorable market prices on existing contracts.
IV. Other Financial Assets and Liabilities
 
The fair value of financial assets and liabilities measured at other than fair value is as follows:
 
Fair value(1)
Total
carrying
  Level I Level II Level III Total
value(1)
Exchangeables securities – Dec. 31, 2020 —  769  —  769  730 
Long-term debt – Dec. 31, 2020 —  3,480  —  3,480  3,227 
Exchangeable securities – Dec. 31, 2019 —  342  —  342  326 
Long-term debt – Dec. 31, 2019 —  3,157  —  3,157  3,070 
(1) Includes current portion.




TRANSALTA CORPORATION F57

Notes to Consolidated Financial Statements
The fair values of the Corporation’s debentures, senior notes and exchangeable securities are determined using prices observed in secondary markets. Non-recourse and other long-term debt fair values are determined by calculating an implied price based on a current assessment of the yield to maturity. 
The carrying amount of other short-term financial assets and liabilities (cash and cash equivalents, restricted cash, trade accounts receivable, collateral paid, accounts payable and accrued liabilities, collateral received and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the loan receivable (see Note 22) and the finance lease receivables (see Note 8) approximate the carrying amounts.
C. Inception Gains and Losses
The majority of derivatives traded by the Corporation are based on adjusted quoted prices on an active exchange or extend beyond the time period for which exchange-based quotes are available. The fair values of these derivatives are determined using inputs that are not readily observable. Refer to section B of this Note 15 above for fair value Level III valuation techniques used. In some instances, a difference may arise between the fair value of a financial instrument at initial recognition (the “transaction price”) and the amount calculated through a valuation model. This unrealized gain or loss at inception is recognized in net earnings (loss) only if the fair value of the instrument is evidenced by a quoted market price in an active market, observable current market transactions that are substantially the same, or a valuation technique that uses observable market inputs. Where these criteria are not met, the difference is deferred on the Consolidated Statements of Financial Position in risk management assets or liabilities, and is recognized in net earnings (loss) over the term of the related contract. The difference between the transaction price and the fair value determined using a valuation model, yet to be recognized in net earnings, and a reconciliation of changes is as follows:

As at Dec. 31 2020 2019 2018
Unamortized net gain at beginning of year 9  49  105 
New inception gains (losses)(1)
(13) 3  (14)
Change in foreign exchange rates —  —  5 
Amortization recorded in net earnings during the year (29) (43) (47)
Unamortized net gain (loss) at end of year(2)
(33) 9  49 

(1) During 2020, the Corporation entered into a coal rail transportation agreement that includes an upside sharing mechanism. Option pricing techniques have been utilized to value the obligation associated with this component of the deal.
(2) During 2020, the net inception gain on the long-term fixed price power sale contract in the US changed to a loss position based on the day 1 forward price curve at inception of the contract.

16. Risk Management Activities
A. Risk Management Strategy
The Corporation is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Corporation’s earnings and the value of associated financial instruments that the Corporation holds. In certain cases, the Corporation seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures. The Corporation’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Corporation’s internal objectives and its risk tolerance.

The Corporation has two primary streams of risk management activities: i) financial exposure management and ii) commodity exposure management. Within these activities, risks identified for management include commodity risk, interest rate risk, liquidity risk, equity price risk and foreign currency risk.

The Corporation seeks to minimize the effects of commodity risk, interest rate risk and foreign currency risk by using derivative financial instruments to hedge risk exposures. Of these derivatives, the Corporation may apply hedge accounting to those hedging commodity price risk and foreign currency risk.

The use of financial derivatives is governed by the Corporation’s policies approved by the Board, which provide written principles on commodity risk, interest rate risk, liquidity risk, equity price risk and foreign currency risk, as well as the use of financial derivatives and non-derivative financial instruments.

Liquidity risk, credit risk and equity price risk are managed through means other than derivatives or hedge accounting.

The Corporation enters into various derivative transactions as well as other contracting activities that do not qualify for hedge accounting or where a choice was made not to apply hedge accounting. As a result, the related assets and




TRANSALTA CORPORATION F58
Notes to Consolidated Financial Statements
liabilities are classified as derivatives at fair value through profit and loss. The net realized and unrealized gains or losses from changes in the fair value of these derivatives are reported in net earnings in the period the change occurs.

The Corporation designates certain derivatives as hedging instruments to hedge commodity price risk, foreign currency exchange risk in cash flow hedges, and hedges of net investments in foreign operations. Hedges of foreign exchange risk on firm commitments are accounted for as cash flow hedges.

At the inception of the hedge relationship, the Corporation documents the relationship between the hedging instrument and the hedged item, along with its risk management objectives and its strategy for undertaking various hedge transactions. At the inception of the hedge and on an ongoing basis, the Corporation also documents whether the hedging instrument is effective in offsetting changes in fair values or cash flows of the hedged item attributable to the hedged risk, which is when the hedging relationships meet all of the following hedge effectiveness requirements:

▪There is an economic relationship between the hedged item and the hedging instrument;
▪The effect of credit risk does not dominate the value changes that result from that economic relationship; and
▪The hedge ratio of the hedging relationship is the same as that resulting from the quantity of the hedged item that the Corporation actually hedges and the quantity of the hedging instrument that the entity actually uses to hedge that quantity of hedged item.

If a hedging relationship ceases to meet the hedge effectiveness requirement relating to the hedge ratio, but the risk management objective for that designated hedging relationship remains the same, the Corporation adjusts the hedge ratio of the hedging relationship so that it continues to meet the qualifying criteria.

B. Net Risk Management Assets and Liabilities
 
Aggregate net risk management assets and (liabilities) are as follows: 
As at Dec. 31, 2020
  Cash flow
hedges 		Not
designated
as a hedge 		Total
Commodity risk management      
Current 101  (11) 90 
Long-term 471  (19) 452 
Net commodity risk management assets (liabilities) 572  (30) 542 
Other      
Current (9) (4) (13)
Long-term —  1  1 
Net other risk management liabilities (9) (3) (12)
Total net risk management assets (liabilities) 563  (33) 530 


As at Dec. 31, 2019
  Cash flow
hedges 		Not
designated
as a hedge 		Total
Commodity risk management      
Current 70  15  85 
Long-term 606  1  607 
Net commodity risk management assets 676  16  692 
Other      
Current —  —  — 
Long-term —  4  4 
Net other risk management assets —  4  4 
Total net risk management assets 676  20  696 




TRANSALTA CORPORATION F59

Notes to Consolidated Financial Statements

I. Netting Arrangements
Information about the Corporation’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows:
As at Dec. 31 2020 2019
  Current
financial
assets 		Long-term
financial
assets 		Current
financial
liabilities 		Long-term
financial
liabilities 		Current
financial
assets 		Long-term
financial
assets 		Current
financial
liabilities 		Long-term
financial
liabilities
Gross amounts recognized 120  69  (132) (104) 316  631  (191) (100)
Gross amounts set-off (69) (10) 69  10  (140) (42) 140  42 
Net amounts as included in the
Consolidated Statements of
Financial Position 		51  59  (63) (94) 176  589  (51) (58)

C. Nature and Extent of Risks Arising from Financial Instruments
 
I. Market Risk
 
a. Commodity Price Risk Management
 
The Corporation has exposure to movements in certain commodity prices in both its electricity generation and proprietary trading businesses, including the market price of electricity and fuels used to produce electricity. Most of the Corporation’s electricity generation and related fuel supply contracts are considered to be contracts for delivery or receipt of a non-financial item in accordance with the Corporation’s expected own use requirements and are not considered to be financial instruments. As such, the discussion related to commodity price risk is limited to the Corporation’s proprietary trading business and commodity derivatives used in hedging relationships associated with the Corporation’s electricity generating activities.

To mitigate the risk of adverse commodity price changes, the Corporation uses three tools:
▪A framework of risk controls;
▪A pre-defined hedging plan, including fixed price financial power swaps and long-term physical power sale contracts to hedge commodity price for electricity generation; and
▪A committee dedicated to overseeing the risk and compliance program in trading and ensuring the existence of appropriate controls, processes, systems and procedures to monitor adherence to the program.

The Corporation has executed commodity price hedges for its Centralia thermal facility and for its portfolio of merchant power exposure in Alberta, including a long-term physical power sale contract at Centralia and fixed price financial swaps for the Alberta portfolio to hedge the prices. Both hedging strategies fall under the Corporation’s risk management strategy used to hedge commodity price risk.

There is no source of hedge ineffectiveness for the merchant power exposure in Alberta.

Market risk exposures are measured using Value at Risk ("VaR") supplemented by sensitivity analysis. There has been no change to the Corporation’s exposure to market risks or the manner in which these risks are managed or measured.

i. Commodity Price Risk Management – Proprietary Trading
 
The Corporation’s Energy Marketing segment conducts proprietary trading activities and uses a variety of instruments to manage risk, earn trading revenue and gain market information.
In compliance with the Commodity Exposure Management Policy, proprietary trading activities are subject to limits and controls, including VaR limits. The Board approves the limit for total VaR from proprietary trading activities. VaR is the most commonly used metric employed to track and manage the market risk associated with trading positions. A VaR measure gives, for a specific confidence level, an estimated maximum pre-tax loss that could be incurred over a specified period of time. VaR is used to determine the potential change in value of the Corporation’s proprietary trading portfolio, over a three-day period within a 95 per cent confidence level, resulting from normal market fluctuations. VaR is estimated using the historical variance/covariance approach. VaR is a measure that has certain inherent limitations. The use of historical information in the estimate assumes that price movements in the past will be indicative of future market risk. As such, it may only be meaningful under normal market conditions. Extreme market events are not addressed by this risk measure. In addition, the use of a three-day measurement period implies that positions can be unwound or hedged within three days, although this may not be possible if the market becomes illiquid.




TRANSALTA CORPORATION F60
Notes to Consolidated Financial Statements
Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at Dec. 31, 2020, associated with the Corporation’s proprietary trading activities was $1 million (2019 — $1 million, 2018 — $2 million).
ii. Commodity Price Risk – Generation 
The generation segments utilize various commodity contracts to manage the commodity price risk associated with electricity generation, fuel purchases, emissions and byproducts, as considered appropriate. A Commodity Exposure Management Policy is prepared and approved annually, which outlines the intended hedging strategies associated with the Corporation’s generation assets and related commodity price risks. Controls also include restrictions on authorized instruments, management reviews on individual portfolios and approval of asset transactions that could add potential volatility to the Corporation’s reported net earnings.
TransAlta has entered into various contracts with other parties whereby the other parties have agreed to pay a fixed price for electricity to TransAlta. While not all of the contracts create an obligation for the physical delivery of electricity to other parties, the Corporation has the intention and believes it has sufficient electrical generation available to satisfy these contracts and, where able, has designated these as cash flow hedges for accounting purposes. As a result, changes in market prices associated with these cash flow hedges do not affect net earnings in the period in which the price change occurs. Instead, changes in fair value are deferred until settlement through AOCI, at which time the net gain or loss resulting from the combination of the hedging instrument and hedged item affects net earnings.
VaR at Dec. 31, 2020, associated with the Corporation’s commodity derivative instruments used in generation hedging activities was $12 million (2019 — $25 million, 2018 — $18 million). For positions and economic hedges that do not meet hedge accounting requirements or for short-term optimization transactions such as buybacks entered into to offset existing hedge positions, these transactions are marked to the market value with changes in market prices associated with these transactions affecting net earnings in the period in which the price change occurs. VaR at Dec. 31, 2020, associated with these transactions was $15 million (2019— $8 million, 2018 — $13 million).
iii. Commodity Price Risk Management – Hedges
The Corporation’s outstanding commodity derivative instruments designated as hedging instruments are as follows:
As at Dec. 31 2020 2019
Type
(thousands) 		Notional
amount
sold 		Notional
amount
purchased 		Notional
amount
sold 		Notional
amount
purchased
Electricity (MWh)(1)
95  —  222  — 
(1) Excludes the long-term power sale - US contract. For further details on this contract, refer to Note 15(B)(I)(c)(i).

During 2020, unrealized pre-tax gains of $1 million (2019 — $1 million, 2018 — $4 million) related to certain power hedging relationships that were previously de-designated and deemed ineffective for accounting purposes were released from AOCI and recognized in net earnings.

iv. Commodity Price Risk Management – Non-Hedges
The Corporation’s outstanding commodity derivative instruments not designated as hedging instruments are as follows:
As at Dec. 31 2020 2019
Type
(thousands) 		Notional
amount
sold 		Notional
amount
purchased 		Notional
amount
sold 		Notional
amount
purchased
Electricity (MWh)
12,944  8,258  16,097  7,204 
Natural gas (GJ)
23,035  177,448  38,062  55,023 
Transmission (MWh)
—  1,578  —  1,818 
Emissions (MWh)
1,831  2,112  184  138 
Emissions (tonnes)
2,160  2,365  2,436  2,446 

b. Interest Rate Risk Management
 
Interest rate risk arises as the fair value of future cash flows from a financial instrument fluctuates because of changes in market interest rates. Changes in interest rates can impact the Corporation’s borrowing costs and the capacity payments received under the Alberta coal PPAs. Changes in the cost of capital may also affect the feasibility of new growth initiatives.




TRANSALTA CORPORATION F61

Notes to Consolidated Financial Statements
The Corporation's credit facility and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represent 7 per cent of the Corporation’s debt as at Dec. 31, 2020 (2019 – 11 per cent). Interest rate risk is managed with the use of derivatives. The Corporation's outstanding interest rate derivative instruments are as follows.
At Dec. 31, 2020, the Corporation had interest rate swap agreements in place with a notional amount of US$150 million whereby the Corporation receives a variable rate of interest equal to the three-month LIBOR rate and pays interest at a fixed rate equal to 0.94 per cent on the notional amount. The swap is being used to hedge interest rate exposure on a highly probable future US$400 million fixed rate debt issuance.
At Dec. 31, 2020, the Corporation had a bond lock agreement in place with a notional amount of $75 million whereby on the pricing date, if the difference between the underlying 5.75 per cent Government of Canada bond and the forward bond price of $150 million (forward yield 1.20 per cent) is positive, the Corporation receives settlement. If the difference is negative, the Corporation pays settlement. The swap is being used to hedge interest rate exposure on a highly probable future $150 million fixed rate debt issuance.

There were no interest rate derivative instruments outstanding in 2019 or 2018.

IBOR reform could impact interest rate risk with respect to the Corporation's credit facilities and the Poplar Creek non-recourse bond held by a TransAlta subsidiary. The facility references LIBOR for US dollar drawings and Canadian Dollar Offer Rate ("CDOR") for Canadian dollar drawings: in addition the non-recourse bond references the three month CDOR. To date, no US dollar drawings have been made on the facility and there is currently a plan to discontinue the six- twelve month CDOR, which does not impact the facility or the non-recourse bond.

Outstanding forward starting interest rate swaps in both Canadian and US dollars should not be affected as they are set to settle in 2021 prior to any IBOR changes being made. The Corporation is monitoring the reform and does not expect any material impacts.

c. Currency Rate Risk 
The Corporation has exposure to various currencies, such as the US dollar and the Australian dollar, as a result of investments and operations in foreign jurisdictions, the net earnings from those operations and the acquisition of equipment and services from foreign suppliers.
The Corporation may enter into the following hedging strategies to mitigate currency rate risk, including:
▪Foreign exchange forward contracts to mitigate adverse changes in foreign exchange rates on project-related expenditures and distributions received in foreign currencies;
▪Foreign exchange forward contracts and cross-currency swaps to manage foreign exchange exposure on foreign-denominated debt not designated as a net investment hedge; and
▪Designating foreign currency debt as a hedge of the net investment in foreign operations to mitigate the risk due to fluctuating exchange rates related to certain foreign subsidiaries.

The Corporation's target is to hedge a minimum of 60 per cent of our forecasted foreign operating cash flows over a four-year period, with a minimum of 90 per cent in the current year, 70 per cent in the next year, 50 per cent in the third year and 30 per cent in the fourth year. The US exposure will be managed with a combination of interest expense on our US-denominated debt and forward foreign exchange contracts and the Australian exposure will be managed with a combination of interest expense on our Australian-dollar denominated debt and forward foreign exchange contracts.

i. Net Investment Hedges
When designating foreign currency debt as a hedge of the Corporation’s net investment in foreign subsidiaries, the Corporation has determined that the hedge is effective if the foreign currency of the net investment is the same as the currency of the hedge, and therefore an economic relationship is present.

The Corporation’s hedges of its net investment in foreign operations were comprised of US-dollar-denominated long-term debt with a face value of US$370 million (2019 — US$370 million).
ii. Cash Flow Hedges
The Corporation uses foreign exchange forward contracts to hedge a portion of its future foreign-denominated receipts
and expenditures, and both foreign exchange forward contracts and cross-currency swaps to manage foreign exchange
exposure on foreign-denominated debt not designated as a net investment hedge.





TRANSALTA CORPORATION F62
Notes to Consolidated Financial Statements
As at Dec. 31 2020 2019
Notional
amount
sold 		Notional
amount
purchased 		Fair value
liability 		Maturity Notional
amount
sold 		Notional
amount
purchased 		Fair value
asset 		Maturity
Foreign Exchange Forward Contracts - foreign-denominated receipts/expenditures
CAD71  USD54  (2) 2021  CAD124  USD95  —  2020-2021

iii. Non-Hedges
As part of the sale of the Corporation's economic interest in the Australian Assets to TransAlta Renewables, the Corporation agreed to mitigate the risks to TransAlta Renewables' shareholders of adverse changes in the US and Australian in respect of cash flows from the Australian Assets in relation to the Canadian dollar to June 30, 2020. The financial effects of the agreements eliminate on consolidation.

In order to mitigate some of the risk that is attributable to non-controlling interests, the Corporation entered into foreign currency contracts with third parties to the extent of the non-controlling interest percentage of the expected cash flow over five years to June 30, 2020. Hedge accounting was not applied to these foreign currency contracts.

The Corporation also uses foreign currency contracts to manage its expected foreign operating cash flows. Hedge accounting is not applied to these foreign currency contracts.
As at Dec. 31   2020   2019
Notional
amount
sold 		Notional
amount
purchased 		Fair value
asset
(liability) 		Maturity Notional
amount
sold 		Notional
amount
purchased 		Fair value
asset
(liability) 		Maturity
Foreign exchange forward contracts – foreign-denominated receipts/expenditures
AUD197  CAD181  (14) 2021-2024 AUD286  CAD266  —  2020 - 2023
USD47  CAD72  9  2021-2024 USD108  CAD139  (4) 2020 - 2023
AUD4  USD3  —  2021
CAD1  EUR1  —  2021
Foreign exchange forward contracts – foreign-denominated debt
CAD191  USD150  2  2022  CAD191  USD150  6  2022

iv. Impacts of currency rate risk
The possible effect on net earnings and OCI, due to changes in foreign exchange rates associated with financial instruments denominated in currencies other than the Corporation’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average three cent (2019 — three cent, 2018 — four cent) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.
Year ended Dec. 31 2020 2019 2018
Currency
Net earnings
increase
(decrease)(1)
OCI gain(1),(2)
Net earnings
increase(1)
OCI gain(1),(2)
Net earnings
decrease(1)
OCI gain(1),(2)
USD (8) 1  (18) 2  (13) — 
AUD (4) —  (6) —  (7) — 
Total (12) 1  (24) 2  (20) — 
(1) These calculations assume an increase in the value of these currencies relative to the Canadian dollar.  A decrease would have the opposite effect.
(2) The foreign exchange impact related to financial instruments designated as hedging instruments in net investment hedges has been excluded.





TRANSALTA CORPORATION F63

Notes to Consolidated Financial Statements
II. Credit Risk
Credit risk is the risk that customers or counterparties will cause a financial loss for the Corporation by failing to discharge their obligations, and the risk to the Corporation associated with changes in creditworthiness of entities with which commercial exposures exist. The Corporation actively manages its exposure to credit risk by assessing the ability of counterparties to fulfil their obligations under the related contracts prior to entering into such contracts. The Corporation makes detailed assessments of the credit quality of all counterparties and, where appropriate, obtains corporate guarantees, cash collateral, third-party credit insurance and/or letters of credit to support the ultimate collection of these receivables. For commodity trading and origination, the Corporation sets strict credit limits for each counterparty and monitors exposures on a daily basis. TransAlta uses standard agreements that allow for the netting of exposures and often include margining provisions. If credit limits are exceeded, TransAlta will request collateral from the counterparty or halt trading activities with the counterparty.
The Corporation uses external credit ratings, as well as internal ratings in circumstances where external ratings are not available, to establish credit limits for customers and counterparties. The following table outlines the Corporation’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2020:
 
Investment grade
 (Per cent)
Non-investment grade
 (Per cent)
Total
 (Per cent)
Total
amount
Trade and other receivables(1)
92  8  100  583 
Long-term finance lease receivable 100  —  100  228 
Risk management assets(1)
93  7  100  692 
Loan receivable(2)
—  100  100  52 
Total       1,555 
 
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. 
(2) The counterparty has no external credit rating. Refer to Note 22 for further details.

An impairment analysis is performed at each reporting date using a provision matrix to measure expected credit losses. The provision rates are based on segment historical rates of default of trade receivables as well as incorporating forward-looking credit ratings and forecasted default rates. In addition to the calculation of expected credit losses, TransAlta monitors key forward-looking information as potential indicators that historical bad debt percentages, forward-looking S&P credit ratings and forecasted default rates would no longer be representative of future expected credit losses. The calculation reflects the probability-weighted outcome, the time value of money and reasonable and supportable information that is available at the reporting date about past events, current conditions and forecasts of future economic conditions. TransAlta evaluates the concentration of risk with respect to trade receivables as low, as its customers are located in several jurisdictions and industries. The Corporation did not have significant expected credit losses as at Dec. 31, 2020.

The Corporation’s maximum exposure to credit risk at Dec. 31, 2020, without taking into account collateral held or right of set-off, is represented by the current carrying amounts of receivables and risk management assets as per the Consolidated Statements of Financial Position. Letters of credit and cash are the primary types of collateral held as security related to these amounts. The maximum credit exposure to any one customer for commodity trading operations and hedging, including the fair value of open trading, net of any collateral held, at Dec. 31, 2020, was $22 million (2019 — $5 million).
Amidst the current economic conditions resulting from the COVID-19 pandemic, TransAlta has implemented the following additional measures to monitor its counterparties for changes in their ability to meet obligations:
▪Daily monitoring of events impacting counterparty creditworthiness and counterparty credit downgrades;
▪Weekly oversight and follow-up, if applicable, of accounts receivables; and
▪Review and monitoring of key suppliers, counterparties and customers (i.e., off-takers).

As needed, additional risk mitigation tactics will be taken to reduce the risk to TransAlta. These risk mitigation tactics may include, but are not limited to, immediate follow-up on overdue amounts, adjusting payment terms to ensure a portion of funds are received sooner, requiring additional collateral, reducing transaction terms and working closely with impacted counterparties on negotiated solutions.





TRANSALTA CORPORATION F64
Notes to Consolidated Financial Statements
III. Liquidity Risk
 
Liquidity risk relates to the Corporation’s ability to access capital to be used for proprietary trading activities, commodity hedging, capital projects, debt refinancing and general corporate purposes. As at Dec. 31, 2020, TransAlta maintains an investment grade rating from one credit rating agency and below investment grade ratings from two credit rating agencies. Between 2021 and 2023, the Corporation has approximately $1 billion of debt maturing, comprised of approximately $631 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. We expect to refinance the debt maturing in 2022.
Collateral is posted based on negotiated terms with counterparties, which can include the Corporation’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Corporation’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs.

TransAlta manages liquidity risk by monitoring liquidity on trading positions; preparing and revising longer-term financing plans to reflect changes in business plans and the market availability of capital; reporting liquidity risk exposure for proprietary trading activities on a regular basis to the Risk Management Committee, senior management and the Board; and maintaining sufficient undrawn committed credit lines to support potential liquidity requirements. The Corporation does not use derivatives or hedge accounting to manage liquidity risk.

A maturity analysis of the Corporation's financial liabilities is as follows:

  2021 2022 2023 2024 2025 2026 and thereafter Total
Accounts payable and accrued liabilities 599  —  —  —  —  —  599 
Long-term debt(1)
96  626  277  119  136  2,010  3,264 
Exchangeable securities(2)
—  —  —  —  750  —  750 
Commodity risk management (assets)
liabilities 		(92) (87) (131) (131) (103) 2  (542)
Other risk management (assets) liabilities 14  —  1  (2) —  (1) 12 
Lease liabilities(3)
(5) 6  5  5  5  118  134 
Interest on long-term debt and lease
  liabilities(4)
161  153  126  119  113  893  1,565 
Interest on exchangeable securities(2, 4)
53  52  53  52  —  —  210 
Dividends payable 59  —  —  —  —  —  59 
Total 885  750  331  162  901  3,022  6,051 
(1) Excludes impact of hedge accounting and derivatives.
(2) Assumes the exchangeable securities will be exchanged on Jan. 1, 2025. Refer to Note 25 for further details.
(3) Lease liabilities include a lease incentive of $13 million, expected to be received in 2021.
(4) Not recognized as a financial liability on the Consolidated Statements of Financial Position.

IV. Equity Price Risk
a. Total Return Swaps 
The Corporation has certain compensation, deferred and restricted share unit programs, the values of which depend on the common share price of the Corporation. The Corporation has fixed a portion of the settlement cost of these programs by entering into a total return swap for which hedge accounting has not been applied. The total return swap is cash settled every quarter based upon the difference between the fixed price and the market price of the Corporation’s common shares at the end of each quarter.




TRANSALTA CORPORATION F65

Notes to Consolidated Financial Statements
D. Hedging Instruments – Uncertainty of Future Cash Flows
The following table outlines the terms and conditions of derivative hedging instruments and how they affect the amount, timing and uncertainty of future cash flows:
Maturity
2021 2022 2023 2024 2025 2026 and thereafter
Cash flow hedges(1)
         
Foreign currency forward contracts
        Notional amount ($ millions)
                 CAD/USD 54  —  —  —  —  — 
        Average Exchange Rate
                 CAD/USD 0.7648  —  —  —  —  — 
Commodity derivative instruments
   Electricity
        Notional amount (thousands MWh) 3,424  3,329  3,329  3,338  2,628  — 
        Average Price ($ per MWh) 69.51  71.91  73.72  75.56  77.44  — 
(1) The interest rate swaps detailed above both settle in 2021.

E. Effects of Hedge Accounting on the Financial Position and Performance

I. Effect of Hedges
The impact of the hedging instruments on the statement of financial position is as follows:
As at Dec. 31, 2020
Notional amount Carrying amount Line item in the statement of financial position Change in fair value used for measuring ineffectiveness
Commodity price risk
Cash flow hedges
Physical power sales
16 MMWh
573  Risk management assets (33)
Interest rate risk
Cash flow hedges
Interest rate swap
USD150
(3) Risk management liabilities 3 
Interest rate swap
CAD75
(4) Risk management liabilities 4 
Foreign currency risk
Net investment hedges
Foreign-denominated debt
USD370
CAD472
Credit facilities, long-term debt and lease liabilities 11 

As at Dec. 31, 2019
Notional amount Carrying amount Line item in the statement of financial position Change in fair
value used for measuring ineffectiveness
Commodity price risk
Cash flow hedges
Physical power sales
19 MMWh
678  Risk management assets 47 
Foreign currency risk
Net investment hedges
Foreign-denominated debt
USD370
CAD483
Credit facilities, long-term debt and lease liabilities 21 





TRANSALTA CORPORATION F66
Notes to Consolidated Financial Statements
The impact of the hedged items on the statement of financial position is as follows:
As at Dec. 31 2020 2019
Change in fair value used for measuring ineffectiveness
Cash flow hedge reserve(1)
Change in fair value used for measuring ineffectiveness
Cash flow hedge reserve(1)
Commodity price risk
Cash flow hedges
Power forecast sales – Centralia (33) 417  47  527 
Interest rate risk
Cash flow hedges
Interest expense on long-term
debt 		7 19 —  — 
Change in fair value used for measuring ineffectiveness
Foreign currency translation reserve(1)
Change in fair value used for measuring ineffectiveness
Foreign currency translation reserve(1)
Foreign currency risk
Net investment hedges
Net investment in foreign
subsidiaries 		11  (21) 21  (21)
(1) Included in AOCI.

The hedging gain recognized in OCI before tax is equal to the change in fair value used for measuring effectiveness for the net investment hedge. There is no ineffectiveness recognized in profit or loss.

The impact of hedged items designated in hedging relationships on OCI and net earnings is:
Year ended Dec. 31, 2020
    Effective portion   Ineffective portion  
Derivatives in cash
flow hedging
relationships 		Pre-tax
gain (loss)
recognized in OCI 		Location of (gain) loss
reclassified
from OCI 		Pre-tax (gain) loss
reclassified
from OCI 		Location of (gain) loss
reclassified
from OCI 		Pre-tax
(gain) loss
recognized in
earnings
Commodity contracts 41  Revenue (137) Revenue — 
Foreign exchange forwards on project hedges (1) Property, plant and equipment —  Foreign exchange (gain) loss — 
Forward starting interest rate swaps (12) Interest expense (4) Interest expense — 
OCI impact 28  OCI impact (141) Net earnings impact — 

Over the next 12 months, the Corporation estimates that approximately $72 million of after-tax gains will be reclassified from AOCI to net earnings. These estimates assume constant natural gas and power prices, interest rates and exchange rates over time; however, the actual amounts that will be reclassified may vary based on changes in these factors.

Year ended Dec. 31, 2019
    Effective portion   Ineffective portion  
Derivatives in cash
flow hedging
relationships 		Pre-tax
gain (loss)
recognized in 
OCI 		Location of (gain) 
loss
reclassified
from OCI 		Pre-tax
 (gain) loss
reclassified
from OCI 		Location of (gain) loss
reclassified
from OCI 		Pre-tax
(gain) loss
recognized in 
earnings
Commodity contracts 77  Revenue (59) Revenue — 
Forward starting interest rate swaps —  Interest expense 6  Interest expense — 
OCI impact 77  OCI impact (53) Net earnings impact — 






TRANSALTA CORPORATION F67

Notes to Consolidated Financial Statements
Year ended Dec. 31, 2018
    Effective portion   Ineffective portion  
Derivatives in cash
flow hedging
relationships 		Pre-tax
gain (loss)
recognized 
in OCI 		Location of (gain) loss reclassified from OCI Pre-tax
(gain) loss
reclassified
from OCI 		Location of (gain) loss
reclassified from OCI 		Pre-tax
(gain) loss
recognized in
earnings
Commodity contracts (9) Revenue (67) Revenue — 
Foreign exchange forwards on US debt —  Foreign exchange (gain) loss 3  Foreign exchange (gain) loss — 
Forward starting interest rate swaps —  Interest expense 7  Interest expense — 
OCI impact (9) OCI impact (57) Net earnings impact — 

II. Effect of Non-Hedges
For the year ended Dec. 31, 2020, the Corporation recognized a net unrealized gain of $43 million (2019 — gain of $33 million, 2018 — loss of $29 million) related to commodity derivatives.

For the year ended Dec. 31, 2020, a gain of $11 million (2019 — gain of $24 million, 2018 —gain of $3 million) related to foreign exchange and other derivatives was recognized, which is comprised of net unrealized loss of $2 million (2019 — gains of $6 million, 2018 — gains of $4 million) and net realized gains of $13 million (2019 — gains of $18 million, 2018 — losses of $1 million).

F. Collateral
 
I. Financial Assets Provided as Collateral
 
At Dec. 31, 2020, the Corporation provided $49 million (2019 – $42 million) in cash and cash equivalents as collateral to regulated clearing agents as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. Collateral provided is included in accounts receivable in the Consolidated Statements of Financial Position.
II. Financial Assets Held as Collateral 
At Dec. 31, 2020, the Corporation held nil (2019 – $3 million) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Corporation may be obligated to pay interest on the outstanding balances and to return the principal when the counterparties have met their contractual obligations or when the amount of the obligation declines as a result of changes in market value. Interest payable to the counterparties on the collateral received is calculated in accordance with each contract. Collateral held is included in accounts payable in the Consolidated Statements of Financial Position.
III. Contingent Features in Derivative Instruments 
Collateral is posted in the normal course of business based on the Corporation’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Corporation’s derivative instruments contain financial assurance provisions that require collateral to be posted only if a material adverse credit-related event occurs.
As at Dec. 31, 2020, the Corporation had posted collateral of $163 million (Dec. 31, 2019 – $112 million) in the form of letters of credit on derivative instruments in a net liability position. Certain derivative agreements contain credit-risk-contingent features, which if triggered could result in the Corporation having to post an additional $85 million (Dec. 31, 2019 – $51 million) of collateral to its counterparties.






TRANSALTA CORPORATION F68
Notes to Consolidated Financial Statements
17. Inventory
Inventory held in the normal course of business, which includes coal, emission credits, parts and materials, and natural gas, is valued at the lower of cost and net realizable value. Inventory held for trading, which includes natural gas and emission credits and allowances, is valued at fair value less costs to sell.

In the third quarter of 2020, the Corporation adjusted the useful life of its Highvale mine assets to align with the Corporation's conversion to gas plans. The standard cost of coal has increased as a result of the increased depreciation costs, in addition to reduced coal consumption. As the cost is not expected to be recovered based on current power pricing, the Corporation recognized a $37 million writedown to net realizable value on its internally produced coal inventory for the year ended Dec. 31, 2020.

The components of inventory are as follows:
As at Dec. 31 2020 2019
Parts and materials 107  108 
Coal 83  130 
Deferred stripping costs 8  6 
Natural gas 2  3 
Purchased emission credits(1)
38  4 
Total 238  251 
(1) Purchased emissions credits increased due to trading and compliance credits purchased, including those for Alberta compliance under the Technology Innovation and Emissions Reduction program.

The change in inventory is as follows:
Balance, Dec. 31, 2018 242 
Net addition 12 
Change in foreign exchange rates (3)
Balance, Dec. 31, 2019 251 
Net addition 26 
Writedowns (37)
Change in foreign exchange rates (2)
Balance, Dec. 31, 2020 238 

No inventory is pledged as security for liabilities.

The Corporation purchases emissions credits and also generates emissions credits from its Wind and Solar and Hydro segments. Emission credits generated from our business have no recorded book value but will be used to offset other emissions obligations in the future, resulting in reduced fuel compliance costs. At Dec. 31, 2020, we currently hold 1,434,761 purchased emission credits (2019 — 388,155) recorded at $38 million (2019 — $4 million) and approximately 502,653 (2019 — 411,115) emission credits with no recorded book value.




TRANSALTA CORPORATION F69

Notes to Consolidated Financial Statements
18. Property, Plant and Equipment
A reconciliation of the changes in the carrying amount of PP&E is as follows:
  Land Coal
generation 		Gas generation Renewable
generation 		Mining property
and equipment 		Assets under
construction
Capital spares

and other(1)
Total
Cost                
As at Dec. 31, 2018 94  5,937  1,964  3,286  1,338  200  383  13,202 
Adjustments on implementation of IFRS 16 —  —  —  (7) (101) —  —  (108)
Additions —  —  —  —  407  115  522 
Acquisitions (Note 4(R) and 4(T))(2)
—  300  —  —  —  139  —  439 
Disposals(3)
(2) (389) (260) —  (34) —  (19) (704)
(Impairment) reversals (Note 7) —  448  —  (2) (15) —  —  431 
Revisions and additions to decommissioning
   and restoration costs (Note 23)
—  (62) 11  2  26  —  —  (23)
Retirement of assets —  (158) (26) (7) (10) —  —  (201)
Change in foreign exchange rates (1) (63) (40) (17) (3) (4) (6) (134)
Transfers(4)
—  103  22  319  25  (514) 16  (29)
As at Dec. 31, 2019 91  6,116  1,671  3,574  1,226  228  489  13,395 
Additions —  —  —  —  —  478  8  486 
Acquisitions (Note 4(K))
—  —  1  —  —  —  —  1 
Disposals (2) (1) —  —  —  —  (2) (5)
Impairment (Note 7) (9) (69) —  (2) —  —  (1) (81)
Revisions and additions to decommissioning
   and restoration costs (Note 23)
—  21  (11) 8  76  —  —  94 
Retirement of assets —  (35) (12) (7) (3) —  (1) (58)
Change in foreign exchange rates (1) (37) 45  (14) (2) —  6  (3)
Transfers(4)
17  142  (263) 33  (29) (211) (120) (431)
As at Dec. 31, 2020 96  6,137  1,431  3,592  1,268  495  379  13,398 
Accumulated depreciation                
As at Dec. 31, 2018 —  3,765  1,128  1,161  830  —  154  7,038 
Adjustments on implementation of IFRS 16 —  —  —  (3) (43) —  —  (46)
Depreciation —  304  77  136  97  —  16  630 
Retirement of assets —  (158) (23) (3) (6) —  —  (190)
Disposals(3)
—  (170) (255) —  (14) —  —  (439)
Impairment reversal (Note 7) —  297  —  —  —  —  —  297 
Change in foreign exchange rates —  (52) (16) (4) (2) —  (2) (76)
Transfers —  10  (11) (3) (22) —  —  (26)
As at Dec. 31, 2019 —  3,996  900  1,284  840  —  168  7,188 
Depreciation —  352  76  142  133  —  14  717 
Retirement of assets —  (31) (10) (6) (4) —  —  (51)
Disposals —  (1) —  —  —  —  (1) (2)
Change in foreign exchange rates —  (35) 18  (4) (2) —  2  (21)
Transfers —  —  (212) —  (29) —  (14) (255)
As at Dec. 31, 2020 —  4,281  772  1,416  938  —  169  7,576 
Carrying amount                
As at Dec. 31, 2018 94  2,172  836  2,125  508  200  229  6,164 
As at Dec. 31, 2019 91  2,120  771  2,290  386  228  321  6,207 
As at Dec. 31, 2020 96  1,856  659  2,176  330  495  210  5,822 
(1) Includes major spare parts and stand-by equipment available, but not in service, and spare parts used for routine, preventive or planned maintenance, and the Australian gas pipeline.
(2) 2019 includes $308 million related to the acquisition of the Keephills 3 facility with $300 million included in coal generation and the remainder in assets under construction.
(3) In 2019, we sold the Genesee 3 facility and sold the major components of the Mississauga facility. In addition, Centralia sold boiler parts included in capital spares and other for a net loss of $17 million. The Highvale mine also sold trucks included in mining property and equipment for a net loss of $18 million. Both were recognized in other gains on the statement of earnings (loss).
(4) 2020 transfers out of PP&E mainly relate to removing the Southern Cross assets from PP&E to a finance lease receivable and moving the Pioneer Pipeline and mine equipment to assets held for sale. 2020 transfers between the classifications of PP&E relate to the Centralia land purchase, the Sundance Unit 6 conversion to gas, the WindCharger project and planned major maintenance. 2019 transfers mainly relate to transferring the Pioneer Pipeline and US Wind Projects from assets under construction to coal generation and renewable generation, respectively.






TRANSALTA CORPORATION F70
Notes to Consolidated Financial Statements
Additions in 2020 included cash additions related to the conversions to gas of $93 million, the Windrise wind project of $156 million, the WindCharger battery storage project of $6 million, the Kaybob cogeneration project of $31 million, Centralia mine land of $17 million and planned major maintenance expenditures. Additions in 2019 included cash additions of $417 million (including $169 million related to the construction of the US Wind Projects), $100 million related to the Pioneer Pipeline (including $15 million transferred from other assets) and $5 million related to the Keephills 3 and Genesee 3 asset swap. Refer to Note 4 for further details of these transactions.

Depreciation expense increased mainly as a result of decisions to accelerate the Highvale mine shutdown to align with our conversion to gas plans, reflecting our transition away from coal. Depreciation expense also increased due to the Keephills 3 and Genesee 3 swap, the reversal of the impairment at Centralia and the changes in useful lives, all of which were effective in the second half of 2019. For further details on these changes, refer to Note 3(A)(III) and Note 4(R).

In 2020, the Corporation capitalized $8 million (2019 — $6 million) of interest to PP&E in at a weighted average rate of 6.0 per cent (2019 —5.9 per cent).

19. Right-of-Use Assets
The Corporation leases various properties and types of equipment. Lease contracts are typically made for fixed periods. Leases are negotiated on an individual basis and contain a wide range of terms and conditions. The lease agreements do not impose covenants, but leased assets may not be used as security for borrowing purposes.

A reconciliation of the changes in the carrying amount of the right-of-use assets is as follows:

Land Buildings Vehicles Equipment Pipeline Total
New leases recognized Jan. 1, 2019 29  22  1  —  —  52 
Adjustments on recognition(1)
(1) (4) —  —  —  (5)
Transfers from PP&E, intangibles
and other assets 		—  —  3  35  —  38 
As at Jan. 1, 2019 28  18  4  35  —  85 
Additions 32  2  —  2  45  81 
Depreciation (1) (4) (2) (11) —  (18)
Changes in foreign exchange rates (1) —  —  —  —  (1)
Transfers —  —  —  (1) —  (1)
As at Dec. 31, 2019 58  16  2  25  45  146 
Additions 3  13  —  —  —  16 
Depreciation (3) (5) (1) (9) (3) (21)
As at Dec. 31, 2020 58  24  1  16  42  141 
(1) Adjusted by the amount of any prepaid or accrued lease payments, onerous contract provisions and lease inducements.

In November 2019, the Corporation recognized a right-of-use asset and corresponding lease liability related to the initial 15-year term of its contract for transporting natural gas on the Pioneer Pipeline. The transportation contract provides the Corporation with the right to extend the contract for up to eight additional renewal periods of 24-months each. The amounts recognized represent the 50 per cent of the pipeline that is not owned by the Corporation.

In December 2019, the Corporation recognized an additional $31 million of right-of-use assets and $31 million of lease liabilities for land leases at certain wind facilities as a result of revised interpretations of the unit of account identified asset concepts present in IFRS 16.

For the year ended Dec. 31, 2020, TransAlta paid $33 million (2019 — $25 million) related to recognized lease liabilities, consisting of $8 million in interest (2019 —$4 million) and $25 million (2019 — $21 million) in principal repayments.

For the year ended Dec. 31, 2020, the Corporation expensed nil related to short-term (2019 — $2 million) and nil related to low-value leases (2019 — $1 million). Short-term leases (term of less than 12 months) and leases with total lease payments below the Corporation's capitalization threshold do not require recognition as lease liabilities and right-of-use assets.





TRANSALTA CORPORATION F71

Notes to Consolidated Financial Statements
Some of the Corporation's land leases that met the definition of a lease were not recognized as they require variable payments based on production or revenue. Additionally, certain land leases require payments to be made on the basis of the greater of the minimum fixed payments and variable payments based on production or revenue. For these leases, lease liabilities have been recognized on the basis of the minimum fixed payments. For the year ended Dec. 31, 2020, the Corporation expensed $7 million (2019 — $6 million) in variable land lease payments for these leases. For further information regarding leases refer to Note 5, 11, 24 and 36.

20. Intangible Assets
A reconciliation of the changes in the carrying amount of intangible assets is as follows:
  Coal rights Software
and other 		Power
sale
contracts 		Intangibles
under
development 		Total
Cost          
As at Dec. 31, 2018 185  339  237  46  807 
Assets transferred to right-of-use assets on
   implementation of IFRS 16 (Note 19)
—  (5) —  —  (5)
Additions —  —  —  14  14 
Acquisition —  1  —  15  16 
Disposals (Note 4(R))
(37) (1) —  —  (38)
Change in foreign exchange rates —  (4) (1) (1) (6)
Transfers 1  48  14  (63) — 
As at Dec. 31, 2019 149  378  250  11  788 
Additions —  —  —  14  14 
Acquisition (Note 4(K))
—  —  37  —  37 
Disposals —  (1) —  —  (1)
Change in foreign exchange rates —  —  (2) —  (2)
Transfers —  35  (16) (22) (3)
As at Dec. 31, 2020 149  412  269  3  833 
Accumulated amortization          
As at Dec. 31, 2018 117  221  96  —  434 
Assets transferred to right-of-use assets on
implementation of IFRS 16 (Note 19) 		—  (3) —  —  (3)
Amortization 8  31  11  —  50 
Disposals (Note 4(R))
(9) (1) —  —  (10)
Change in foreign exchange rates —  (1) —  —  (1)
Transfers 1  (1) —  —  — 
As at Dec. 31, 2019 117  246  107  —  470 
Amortization 8  28  15  —  51 
Disposals —  (1) —  —  (1)
Transfers —  (1) 1  —  — 
As at Dec. 31, 2020 125  272  123  —  520 
Carrying amount          
As at Dec. 31, 2018 68  118  141  46  373 
As at Dec. 31, 2019 32  132  143  11  318 
As at Dec. 31, 2020 24  140  146  3  313 





TRANSALTA CORPORATION F72
Notes to Consolidated Financial Statements
21. Goodwill
Goodwill acquired through business combinations has been allocated to CGUs that are expected to benefit from the synergies of the acquisitions. Goodwill by segments are as follows:
As at Dec. 31 2020 2019
Hydro 258  258 
Wind and Solar 175  176 
Energy Marketing 30  30 
Total goodwill 463  464 

For the purposes of the 2020 annual goodwill impairment review, the Corporation determined the recoverable amounts of the Wind and Solar segment by calculating the fair value less costs of disposal using discounted cash flow projections based on the Corporation's long-range forecasts for the period extending to the last planned asset retirement in 2073. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. No impairment of goodwill arose for any segment. In 2020, the Corporation relied on the recoverable amounts determined in 2019 for the Hydro and Energy Marketing segments in performing the 2020 annual goodwill impairment review. No impairment of goodwill arose for any segment.

The key assumptions impacting the determination of fair value for the Wind and Solar and Hydro segments are electricity production and sales prices. Forecasts of electricity production for each facility are determined taking into consideration contracts for the sale of electricity, historical production, regional supply-demand balances and capital maintenance and expansion plans. Forecasted sales prices for each facility are determined by taking into consideration contract prices for facilities subject to long- or short-term contracts, forward price curves for merchant plants and regional supply-demand balances. Where forward price curves are not available for the duration of the facility’s useful life, prices are determined by extrapolation techniques using historical industry and company-specific data. Electricity prices used in these 2020 models ranged between $6 to $160 per MWh during the forecast period (2019 – $5 to $183 per MWh). Discount rates used for the goodwill impairment calculation in 2020 ranged from 4.8 per cent to 6.3 per cent (2019 – 3.6 per cent to 7.0 per cent). No reasonable possible change in the assumptions would have resulted in an impairment of goodwill.




TRANSALTA CORPORATION F73

Notes to Consolidated Financial Statements
22. Other Assets
The components of other assets are as follows:
As at Dec. 31 2020 2019
South Hedland prepaid transmission access and distribution costs 70  67 
Deferred licence fees —  9 
Project development costs 25  19 
Long-term prepaids and other assets 59  56 
Loan receivable 52  47 
Total other assets 206  198 

South Hedland prepaid transmission access and distribution costs are costs that are amortized on a straight-line basis over the South Hedland PPA contract life.

Deferred licence fees consist primarily of licences to lease the land on which certain generating assets are located, and are amortized on a straight-line basis over the useful life of the generating assets to which the licences relate.

Project development costs primarily include the project costs for US wind development projects (Note 4(F)) and an Alberta Hydro development project. Some projects were written off in 2019 and 2018 as they are no longer proceeding (see Note 7(D)).

Long-term prepaids and other assets includes: the funded portion of rail transportation commitments discussed in Note 36(C), the funded portion of the TransAlta Energy Transition Bill commitments discussed in Note 36(G) and other contractually required prepayments and deposits.

The loan receivable relates to the advancement by the Corporation's subsidiary, Kent Hills Wind LP, of $52 million (2019 – $47 million) (net) of the Kent Hills Wind bond financing proceeds to its 17 per cent partner. The loan bears interest at 4.55 per cent, with interest payable quarterly, commencing on Dec. 31, 2017, is unsecured and matures on Oct. 2, 2022.






TRANSALTA CORPORATION F74
Notes to Consolidated Financial Statements
23. Decommissioning and Other Provisions
The change in decommissioning and other provision balances is as follows:
 
Decommissioning and
restoration
Other Total
Balance, Dec. 31, 2018 407  49  456 
IFRS 16 transition adjustment —  (2) (2)
Liabilities incurred 7  7  14 
Liabilities settled (34) (9) (43)
Accretion 23  —  23 
Acquisition of liabilities 16  3  19 
Disposition of liabilities (23) (9) (32)
Revisions in estimated cash flows(1)
96  7  103 
Revisions in discount rates(1)
16  —  16 
Reversals —  (1) (1)
Change in foreign exchange rates (7) —  (7)
Balance, Dec. 31, 2019 501  45  546 
Liabilities incurred 1  34  35 
Liabilities settled (18) (19) (37)
Accretion 30  —  30 
Acquisition of liabilities 1  —  1 
Revisions in estimated cash flows(2)
61  11  72 
Revisions in discount rates(3)
36  —  36 
Reversals —  (6) (6)
Change in foreign exchange rates (4) —  (4)
Balance, Dec. 31, 2020 608  65  673 
(1) During 2019, the Corporation adjusted the Centralia mine decommissioning and restoration provision as management no longer believes that the fine coal recovery and reclamation work will occur as originally proposed. Refer to Note 3(A)(III) for further details. In addition, due to the changes in estimated useful lives, the discount rates used for the Alberta Thermal and mining operations decommissioning provisions were changed. The use of a lower inflation rate decreased the corresponding liabilities.
(2) During 2020, the Corporation adjusted the Highvale mine decommissioning and restoration provision to reflect the mine closure advancement, an updated mine plan and current mining activity including increased volume of material movement. Refer to Note 3(A)(III) for further details. This increase was partially offset by a decrease in the Sarnia decommissioning and restoration provision as a result of an updated engineering study.
(3) Discount rates at Dec. 31, 2020 are generally lower than those at Dec. 31, 2019, due to decreases in the underlying risk-free US and Canadian benchmark yields and changes in credit spreads due to volatility within the market as a result of COVID-19. On average, these rates decreased by approximately 0.3 to 0.9 per cent.

  Decommissioning and
restoration 		Other Total
Balance, Dec. 31, 2019 501  45  546 
Current portion 36  22  58 
Non-current portion 465  23  488 
Balance, Dec. 31, 2020 608  65  673 
Current portion 21  38  59 
Non-current portion 587  27  614 

A. Decommissioning and Restoration
 
A provision has been recognized for all generating facilities and mines for which TransAlta is legally, or constructively, required to remove the facilities at the end of their useful lives and restore the sites to their original condition. TransAlta estimates that the undiscounted amount of cash flow required to settle these obligations is approximately $1.4 billion, which will be incurred between 2021 and 2073. The majority of the costs will be incurred between 2025 and 2050. At Dec. 31, 2020, the Corporation had provided a surety bond in the amount of US$147 million (2019 – US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2020, the Corporation had provided letters of credit in the amount of $131 million (2019 – $128 million) in support of future decommissioning obligations at the Alberta Highvale mine.




TRANSALTA CORPORATION F75

Notes to Consolidated Financial Statements
B. Other Provisions
 
Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial disputes between the Corporation and customers or suppliers. Information about the expected timing of settlement and uncertainties that could impact the amount or timing of settlement has not been provided as this may impact the Corporation’s ability to settle the provisions in the most favourable manner.
In addition, during the fourth quarter of 2020 an onerous contract provision of $29 million was recognized as a result of a decision to accelerate our plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. The last coal shipment is expected to be received during the first quarter of 2021, while payments required under the contract will continue until 2025.

24. Credit Facilities, Long-Term Debt and Lease Liabilities
A. Amounts Outstanding
 
The amounts outstanding are as follows:
As at Dec. 31 2020 2019
  Carrying
value 		Face
value
Interest(1)
Carrying
value 		Face
value
Interest(1)
Credit facilities(2)
114  114  2.7  % 220  220  3.5  %
Debentures 249  251  7.1  % 647  651  5.8  %
Senior notes(3)
886  894  5.4  % 905  914  5.4  %
Non-recourse(4)
1,837  1,858  4.1  % 1,144  1,157  4.3  %
Other(5)
141  147  7.1  % 154  162  7.1  %
  3,227  3,264    3,070  3,104   
Lease liabilities 134      142     
  3,361      3,212     
Less: current portion of long-term debt (97)     (494)    
Less: current portion of lease liabilities (8)     (19)    
Total current long-term debt and lease liabilities (105)     (513)    
Total credit facilities, long-term debt and lease
liabilities 		3,256      2,699     
 
(1) Interest is an average rate weighted by principal amounts outstanding before the effect of hedging.
(2) Composed of bankers’ acceptances and other commercial borrowings under long-term committed credit facilities.
(3) US face value at Dec. 31, 2020 — US$700 million (Dec. 31, 2019 — US$700 million).
(4) Includes AU$800 million TEC offering.
(5) Includes US$110 million at Dec. 31, 2020 (Dec. 31, 2019 — US$117 million) of tax equity financing.

The Corporation's credit facilities are summarized in the table below:
As at Dec. 31, 2020 Facility
size 		Utilized Available
capacity 		Maturity
date
Outstanding letters of credit(1)
Actual drawings
TransAlta Corporation
Committed syndicated bank facility(2)
1,250  379  114  757  Q2 2023
Canadian committed bilateral credit facilities(3)
240  150  —  90  Q2 2021 & 2022
TransAlta Renewables
Committed credit facility(2)
700  92  —  608  Q2 2023
Total 2,190  621  114  1,455 
(1) TransAlta has obligations to issue letters of credit and cash collateral to secure potential liabilities to certain parties, including those related to potential environmental obligations, commodity risk management and hedging activities, pension plan obligations, construction projects and purchase obligations. At Dec. 31, 2020, we provided cash collateral of $49 million.
(2) TransAlta has letters of credit of $89 million and TransAlta Renewables has letters of credit of $92 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities.
(3) One of the bilateral $80 million credit facilities has a maturity date of Q2 2021;the remaining two bilateral credit facilities has a maturity date of Q2, 2022.




TRANSALTA CORPORATION F76
Notes to Consolidated Financial Statements
The $1.95 billion (Dec. 31, 2019 – $1.95 billion) committed syndicated bank facilities are the primary source for short-term liquidity after the cash flow generated from the Corporation's business. Interest rates on the credit facilities vary depending on the option selected – Canadian prime, bankers' acceptances, US LIBOR or US base rate – in accordance with a pricing grid that is standard for such facilities.
In 2019, the Corporation renewed these credit facilities and TransAlta Renewables' facility was increased by $200 million to $700 million.
The Corporation is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $1.5 billion available under the credit facilities, the Corporation also has $703 million of available cash and cash equivalents and $17 million ($11 million principal portion) in cash restricted for repayment of the OCP bonds (refer to section E below).
Debentures bear interest at fixed rates ranging from 6.9 per cent to 7.3 per cent and have maturity dates ranging from 2029 to 2030.
On Nov. 25, 2020, the Corporation redeemed $400 million of its then due 5.0 per cent medium term notes.

On Aug. 2, 2018, the Corporation early redeemed all of its outstanding 6.40 per cent debentures, which were due Nov. 18, 2019, for the principal amount of $400 million. The redemption price was $425 million in aggregate, including a $19 million prepayment premium recognized in net interest expense and $6 million in accrued and unpaid interest to the redemption date.

Senior notes bear interest at rates ranging from 4.5 per cent to 6.5 per cent and have maturity dates ranging from 2022 to 2040.

During 2018, the Corporation early redeemed its outstanding 6.650 per cent US$500 million senior notes due May 15, 2018. The repayment was hedged with foreign exchange forwards and cross-currency swaps. The redemption price for the notes was approximately $617 million (US$516 million), including a $5 million early redemption premium, recognized in net interest expense, and $14 million in accrued and unpaid interest to the redemption date.

A total of US$370 million (2019 — US$370 million) of the senior notes has been designated as a hedge of the Corporation’s net investment in US foreign operations.

Non-recourse debt consists of bonds and debentures that have maturity dates ranging from 2023 to 2042 and bear interest at rates ranging from 2.95 per cent to 4.51 per cent.

On Oct. 22, 2020, TEC closed an AU$800 million senior secured note offering, by way of a private placement, which is secured by, among other things, a first ranking charge over all assets of TEC. The notes bear interest at 4.07 per cent per annum, payable quarterly and matures on June 30, 2042,with principal payments starting on March 31, 2022. Funds were used repay indebtedness on the credit facility and to fund future growth opportunities within TransAlta Renewables.

During 2018, the Corporation:
▪Paid out the US$25 million non-recourse debt related to its Mass Solar projects.
▪Monetized the OCA and closed a $345 million bond offering through its indirect wholly owned subsidiary TransAlta OCP by way of private placement. The non-recourse amortizing bonds bear interest from their date of issuance at a rate of 4.509 per cent per annum, payable semi-annually and maturing on Aug. 5, 2030.

Other consists of an unsecured commercial loan obligation that bears interest at 5.9 per cent and matures in 2023, requiring annual payments of interest and principal, and tax equity financings related to Big Level and Antrim of $112 million (2019 — $122 million) and Lakeswind of $22 million (2019 — $23 million).

During 2019, coinciding with Antrim and Big Level each achieving commercial operation, TransAlta received tax equity funding of approximately US$41 million and US$85 million, respectively. Refer to Note 4(T) for further details.

Tax equity financings are typically represented by the initial equity investments made by the project investors at each project (net of financing costs incurred), except for the Lakeswind acquired tax equity which was initially recognized at its fair value. Tax equity financing balances are reduced by the value of tax benefits (production tax credits and tax depreciation) allocated to the investor and by cash distributions paid to the investor for their share of net earnings and




TRANSALTA CORPORATION F77

Notes to Consolidated Financial Statements
cash flow generated at each project. Tax equity financing balances are increased by interest recognized at the implicit interest rate. In 2019, the Big Level and Antrim projects claimed accelerated (bonus) tax depreciation of $35 million in total, which was allocated to the tax equity investor, and had the effect of reducing the tax equity financing balance. The maturity dates of each financing are subject to change and primarily dependent upon when the project investor achieves the agreed upon targeted rate of return. The Corporation anticipates the maturity dates of the tax equity financings will be: Big Level and Antrim - in December 2029, 10 years from commercial operation of the projects; and Lakeswind - March 31, 2029.

TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2020, the Corporation was in compliance with all debt covenants.
B. Restrictions related to Non-Recourse Debt and Other Debt
 
The Melancthon Wolfe Wind, Pingston, TAPC Holdings LP, New Richmond, KHWLP, TEC Hedland and TransAlta OCP non-recourse bonds with a carrying value of $1.8 billion as at Dec. 31, 2020 (Dec. 31, 2019 - $1.1 billion) are subject to customary financing conditions and covenants that may restrict the Corporation’s ability to access funds generated by the facilities’ operations. Upon meeting certain distribution tests, typically performed once per quarter, the funds are able to be distributed by the subsidiary entities to their respective parent entity. These conditions include meeting a debt service coverage ratio prior to distribution, which was met by these entities in the third quarter of 2020. However, funds in these entities that have accumulated since the third quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2021. At Dec. 31, 2020, $73 million (Dec. 31, 2019 –$42 million) of cash was subject to these financial restrictions.

Proceeds received from the TEC Notes in the amount of AU$7 million are not able to be accessed by other Corporate entities as the funds must be solely used by the project entities for the purpose of paying major maintenance costs.

Additionally, certain non-recourse bonds require that certain reserve accounts be established and funded through cash held on deposit and/or by providing letters of credit.

C. Security
Non-recourse debts totalling $1,441 million as at Dec. 31, 2020 (Dec. 31, 2019 – $719 million) are each secured by a first ranking charge over all of the respective assets of the Corporation’s subsidiaries that issued the bonds, which include PPE with total carrying amounts of $1,277 million at Dec. 31, 2020 (Dec. 31, 2019 – $967 million) and intangible assets with total carrying amounts of $88 million (Dec. 31, 2019 – $63 million). At Dec. 31, 2020, a non-recourse bond of approximately $111 million (Dec. 31, 2019 – $119 million) was secured by a first ranking charge over the equity interests of the issuer that issued the non-recourse bond.
The TransAlta OCP bonds have a carrying value of $285 million (Dec. 31, 2019 – $305 million) and are secured by the assets of TransAlta OCP, including the right to annual capital contributions and OCA payments from the Government of Alberta. Under the OCA, the Corporation receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million, net to the Corporation), commencing Jan. 1, 2017, and terminating at the end of 2030.

D. Principal Repayments
  2021 2022 2023 2024 2025 2026 and thereafter Total
Principal repayments(1)
96  626  277  119  136  2,010  3,264 
Lease liabilities(2)
(5) 6  5  5  5  118  134 
 
(1) Excludes impact of hedge accounting and derivatives.
(2) Lease liabilities include a lease incentive of $13 million, expected to be received in 2021.

E. Restricted Cash
At Dec. 31, 2020, the Corporation had $9 million (Dec. 31, 2019 – $15 million) in restricted cash related to the Big Level tax equity financing that is held in a construction reserve account. The proceeds will be released from the construction reserve account upon certain conditions being met, which are expected to be finalized in 2021.

The Corporation had $17 million (Dec. 31, 2019 – $17 million) of restricted cash related to the TransAlta OCP bonds, which is required to be held in a debt service reserve account to fund the next scheduled debt repayment in February 2021.




TRANSALTA CORPORATION F78
Notes to Consolidated Financial Statements

The Corporation also had $45 million (Dec. 31, 2019 – nil) of restricted cash related to the TEC Notes; reserves are required to be held under TEC commercial arrangements and for debt service. Cash reserves may be replaced by letters of credit in the future.

F. Letters of Credit
 
Letters of credit issued by TransAlta are drawn on its committed syndicated credit facility, its $240 million bilateral committed credit facilities and its two uncommitted $100 million demand letters of credit facilities. Letters of credit issued by TransAlta Renewables are drawn on its uncommitted $100 million demand letter of credit facility.
Letters of credit are issued to counterparties under various contractual arrangements with the Corporation and certain subsidiaries of the Corporation. If the Corporation or its subsidiary does not perform under such contracts, the counterparty may present its claim for payment to the financial institution through which the letter of credit was issued. Any amounts owed by the Corporation or its subsidiaries under these contracts are reflected in the Consolidated Statements of Financial Position. All letters of credit expire within one year and are expected to be renewed, as needed, in the normal course of business. The total outstanding letters of credit as at Dec. 31, 2020, was $621 million (2019 – $690 million) with no (2019 – nil) amounts exercised by third parties under these arrangements.

25. Exchangeable Securities
On March 22, 2019, the Corporation entered into an Investment Agreement whereby Brookfield agreed to invest $750 million in TransAlta through the purchase of exchangeable securities, which are exchangeable into an equity ownership interest in TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted EBITDA ("Option to Exchange"). On May 1, 2019, Brookfield invested the initial tranche of $350 million in exchange for seven per cent unsecured subordinated debentures due May 1, 2039. On Oct. 30, 2020, Brookfield invested the second tranche of $400 million in exchange for redeemable, retractable first preferred shares.

A. $750 million Exchangeable Securities

As at Dec. 31, 2020 Dec. 31, 2019
Carrying value Face value Interest Carrying value Face value Interest
Exchangeable debentures – due May 1, 2039 330  350  7  % 326 350 7  %
Exchangeable preferred shares(1)
400  400  7  % —  —  7  %
Total long term debt 730  750  326  350 

(1) Exchangeable preferred share dividends are reported as interest expense.

If Brookfield chooses not to exercise its Option to Exchange as outlined below, TransAlta has the right after Dec. 31, 2028 to redeem for cash all or any portion of the Exchangeable Securities for the original subscription price, plus any accrued but unpaid interest or dividends payable, provided the minimum proceeds to Brookfield for each redemption (other than the final redemption) is not less than $100 million and provided all Exchangeable Securities must be redeemed within 36 months of the first optional redemption.

B. Option to Exchange

As at Dec. 31, 2020 Dec. 31, 2019
Description Base fair value Sensitivity Base fair value Sensitivity
Option to exchange – embedded derivative — 
nil
-33
— 
nil
-27

The Investment Agreement allows Brookfield the Option to Exchange all of the outstanding exchangeable securities into an equity ownership interest of up to a maximum 49 per cent in an entity formed to hold TransAlta’s Alberta Hydro Assets after Dec. 31, 2024. The fair value of the Option to Exchange is considered a Level III fair value measurement as there is no available market-observable data. It is therefore valued using a mark-to-forecast model with inputs that are




TRANSALTA CORPORATION F79

Notes to Consolidated Financial Statements
based on historical data and changes in underlying discount rates only when it represents a long-term change in the value of the Option to Exchange.

Sensitivity ranges for the base fair value are determined using reasonably possible alternative assumptions for key unobservable inputs, which is mainly the change in the implied discount rate of the future cash flow. The sensitivity analysis has been prepared using the Corporation’s assessment that a change in the implied discount rate of the future cash flow of 1 per cent is a reasonably possible change.

The maximum equity interest Brookfield can own with respect to the Hydro Assets is 49 per cent. If Brookfield’s ownership interest is less than 49 per cent at conversion, Brookfield has a one-time option payable in cash to increase its ownership to up to 49 per cent, exercisable up until Dec. 31, 2028, and provided Brookfield holds at least 8.5 per cent of TransAlta’s common shares. Under this top-up option, Brookfield will be able to acquire an additional 10 per cent interest in the entity holding the Hydro Assets, provided the 20-day volume-weighted average price (“VWAP”) of TransAlta’s common shares is not less than $14 per share prior to the exercise of the option, and up to the full 49 per cent if the 20-day VWAP of TransAlta’s common shares at that time is not less than $17 per share. To the extent the value of the Investment would exceed a 49 equity interest, Brookfield will be entitled to receive the balance of the redemption price in cash.

26. Defined Benefit Obligation and Other Long-Term Liabilities
The components of defined benefit obligation and other long-term liabilities are as follows:
As at Dec. 31 2020 2019
Defined benefit obligation (Note 31) 282  268 
Long-term incentive accruals (Note 30) 4  4 
Other 12  29 
Total 298  301 

27. Common Shares
A. Issued and Outstanding
 TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.
As at Dec. 31 2020 2019
 
Common
shares
 (millions)
Amount
Common
shares
(millions)
Amount
Issued and outstanding, beginning of year 277.0  2,978  284.6  3,059 
Purchased and cancelled under the NCIB (7.3) (79) (7.7) (83)
Effects of share-based payment plans —  (3) —  — 
Stock options exercised 0.1  —  0.1  2 
Issued and outstanding, end of year 269.8  2,896  277.0  2,978 

B. NCIB Program
Shares purchased by the Corporation under the NCIB are recognized as a reduction to share capital equal to the average carrying value of the common shares. Any difference between the aggregate purchase price and the average carrying value of the common shares is recorded in deficit.





TRANSALTA CORPORATION F80
Notes to Consolidated Financial Statements
The following are the effects of the Corporation's purchase and cancellation of the common shares during the year:
For the year ended Dec. 31 2020 2019
Total shares purchased(1)
7,352,600  7,716,300 
Average purchase price per share $ 8.33  $ 8.80 
Total cost 61  68 
Weighted average book value of shares cancelled 79  83 
Amount recorded in deficit 18  15 
(1) As at Dec. 31, 2020, includes 456,200 (2019 -189,900) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date.

C. Shareholder Rights Plan 
The Corporation initially adopted the Shareholder Rights Plan in 1992, which was amended and restated on April 26, 2019, to reflect current market practice and to reflect changes to the take-over bid regime. As required, the Shareholder Rights Plan must be put before the Corporation’s shareholders every three years for approval, and it was last approved on April 26, 2019. The primary objective of the Shareholder Rights Plan is to encourage a potential acquirer to meet certain minimum standards designed to promote the fair and equal treatment of all common shareholders. When an acquiring shareholder acquires 20 per cent or more of the Corporation’s common shares, except in limited circumstances including by way of a “permitted bid” or a "competing permitted bid" (as defined in the Shareholder Rights Plan), the rights granted under the Shareholder Rights Plan become exercisable by all shareholders except those held by the acquiring shareholder. Each right will entitle a shareholder, other than the acquiring shareholder, to purchase additional common shares at a significant discount to market, thus exposing the person acquiring 20 per cent or more of the shares to substantial dilution of their holdings.
D. Earnings per Share
Year ended Dec. 31 2020 2019 2018
Net earnings (loss) attributable to common shareholders (336) 52  (248)
Basic and diluted weighted average number of common shares outstanding (millions) 275  283  287 
Net earnings (loss) per share attributable to common shareholders, basic and diluted (1.22) 0.18  (0.86)

E. Dividends 
On Dec. 23, 2020, the Corporation declared a quarterly dividend of $0.0450 per common share, payable on April 1, 2021. On Nov. 3, 2020, the Corporation declared a quarterly dividend of $0.0425 per common share, payable on Jan. 1, 2021.
There have been no other transactions involving common shares between the reporting date and the date of completion of these consolidated financial statements.

28. Preferred Shares
A. Issued and Outstanding
All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares.
As at Dec. 31 2020 2019
Series
Number of shares
 (millions)
Amount
Number of shares
(millions)
Amount
Series A 10.2  248  10.2  248 
Series B 1.8  45  1.8  45 
Series C 11.0  269  11.0  269 
Series E 9.0  219  9.0  219 
Series G 6.6  161  6.6  161 
Issued and outstanding, end of year 38.6  942  38.6  942 




TRANSALTA CORPORATION F81

Notes to Consolidated Financial Statements

I. Series G Cumulative Redeemable Rate Reset Preferred Shares Conversion
On Aug. 30, 2019, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2019, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series G (the “Series G Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series H (the “Series H Shares”), there were 140,730 Series G Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series H Shares. Therefore, none of the Series G Shares were converted into Series H Shares on Sept. 30, 2019. As a result, the Series G Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series G Shares for the five-year period from and including Sept. 30, 2019, to, but excluding, Sept. 30, 2024, will be 4.988 per cent, which is equal to the five-year Government of Canada bond yield of 1.188 per cent, determined as of Aug. 30, 2019, plus 3.80 per cent, in accordance with the terms of the Series G Shares.
II. Series E Cumulative Redeemable Rate Reset Preferred Shares Conversion
On Sept. 17, 2017, the Corporation announced that, after taking into account all election notices received by the Sept. 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series E (the “Series E Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series F (the “Series F Shares”), there were 133,969 Series E Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series F Shares. Therefore, none of the Series E Shares were converted into Series F Shares on Sept. 30, 2017. As a result, the Series E Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series E Shares for the five-year period from and including Sept. 30, 2017, to, but excluding, Sept. 30, 2022, will be 5.194 per cent, which is equal to the five-year Government of Canada bond yield of 1.544 per cent, determined as of Aug. 31, 2017, plus 3.65 per cent, in accordance with the terms of the Series E Shares.
III. Series C Cumulative Redeemable Rate Reset Preferred Shares Conversion
On June 16, 2017, the Corporation announced that, after taking into account all election notices received by the June 15, 2017, deadline for the conversion of the Cumulative Redeemable Rate Reset Preferred Shares, Series C (the “Series C Shares”) into Cumulative Redeemable Floating Rate Preferred Shares Series D (the “Series D Shares”), there were 827,628 Series C Shares tendered for conversion, which was less than the one million shares required to give effect to conversions into Series D Shares. Therefore, none of the Series C Shares were converted into Series D Shares on June 30, 2017. As a result, the Series C Shares will be entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The annual dividend rate for the Series C Shares for the five-year period from and including June 30, 2017, to, but excluding, June 30, 2022, will be 4.027 per cent, which is equal to the five-year Government of Canada bond yield of 0.927 per cent, determined as of May 31, 2017, plus 3.10 per cent, in accordance with the terms of the Series C Shares.
IV. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion 
On March 17, 2016, the Corporation announced that 1,824,620 of its 12.0 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") were tendered for conversion, on a one-for-one basis, into Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares") after having taken into account all election notices. As a result of the conversion, the Corporation had 10.2 million Series A Shares and 1.8 million Series B Shares issued and outstanding at Dec. 31, 2020.
The Series A Shares pay fixed cumulative preferential cash dividends on a quarterly basis for the five-year period from and including March 31, 2016, to, but excluding, March 31, 2021, if, as and when declared by the Board based on an annual fixed dividend rate of 2.709 per cent.
The Series B Shares pay quarterly floating rate cumulative preferential cash dividends for the five-year period from and including March 31, 2016, to, but excluding, March 31, 2021, if, as and when declared by the Board based on the 90-day Treasury Bill rate plus 2.03 per cent.
On March 1, 2021, the Corporation announced that it does not intend to exercise its right to redeem all or any part of the currently outstanding Series A Shares and Series B Shares. The Corporation has provided a notice to the registered shareholders of Series A Shares of the conversion right, on a one-for-one basis, into Series B Shares, and vice versa, providing Series B shareholders the right to exchange Series B Shares, on a one-for-one basis, into Series A Shares. Series A shareholders may elect to retain any or all of their current share holdings and continue to receive a fixed rate quarterly dividend. Series B shareholder may also elect to retain any or all of their current share holdings and continue to receive a floating rate quarterly dividend. After exercising conversion rights, if the balance that remains for either




TRANSALTA CORPORATION F82
Notes to Consolidated Financial Statements
Series A Shares or Series B Shares is less than 1 million, that remaining balance of will automatically convert to the other Series. Shareholders' notice of intention to convert must be received by the transfer agent no later than March 16, 2021 and the conversion date will be effective March 31, 2021. The annual dividend rate for the Series A Shares for the five-year period from and including March 31, 2021, to, but excluding, March 31, 2026, will be 2.877 per cent, which is equal to the five-year Government of Canada Bond yield of 0.847 per cent, determined as of March 1, 2021, plus 2.03 per cent. The annual dividend rate for the Series B Shares for the three month floating rate period from and including March 31, 2021, to, but excluding, June 30, 2021, will be 2.103 per cent based on the most recent auction of 90-day Government of Canada Treasury Bills of 0.073 per cent plus 2.03 per cent. The Floating Quarterly Dividend Rate will be reset every quarter.
V. Preferred Share Series Information 
The holders are entitled to receive cumulative fixed quarterly cash dividends at a specified rate, as approved by the Board. After an initial period of approximately five years from issuance and every five years thereafter (“Rate Reset Date”), the fixed rate resets to the sum of the then five-year Government of Canada bond yield (the fixed rate “Benchmark”) plus a specified spread. Upon each Rate Reset Date, the shares are also:
▪Redeemable at the option of the Corporation, in whole or in part, for $25.00 per share, plus all declared and unpaid dividends at the time of redemption. 
▪Convertible at the holder’s option into a specified series of non-voting cumulative redeemable floating rate first preferred shares that pay cumulative floating rate quarterly cash dividends, as approved by the Board, based on the sum of the then Government of Canada 90-day Treasury Bill rate (the floating rate “Benchmark”) plus a specified spread. The cumulative floating rate first preferred shares are also redeemable at the option of the Corporation and convertible back into each original cumulative fixed rate first preferred share series, at each subsequent Rate Reset Date, on the same terms as noted above.

Characteristics specific to each first preferred share series as at Dec. 31, 2020, are as follows:
Series Rate during term
Annual dividend
rate per share ($)
Next
conversion
date
Rate spread
over Benchmark
 (per cent)
Convertible to
Series
A Fixed 0.67724  March 31, 2021 2.03  B
B Floating 0.73801  March 31, 2021 2.03  A
C Fixed 1.00676  June 30, 2022 3.10  D
D Floating —  —  3.10  C
E Fixed 1.29852  Sept. 30, 2022 3.65  F
F Floating —  —  3.65  E
G Fixed 1.24700  Sept. 30, 2024 3.80  H
H Floating —  —  3.80  G

B. Dividends 
The following table summarizes the value of the preferred share dividends declared in 2020, 2019 and 2018:
  Total dividends declared
Series 2020
2019(1)
2018
A 9  5  9 
B(2)
1  1  1 
C 14  8  14 
E 15  9  15 
G 10  7  11 
Total for the year 49  30  50 
(1) No dividends were declared in the first quarter of 2019 as the quarterly dividend related to the period covering the first quarter of 2019 was declared in December 2018.
(2) Series B Preferred Shares pay quarterly dividends at a floating rate based on the 90-day Government of Canada Treasury Bill rate, plus 2.03 per cent.

On Dec. 23, 2020, the Corporation declared a quarterly dividend of $0.16931 per share on the Series A preferred shares, $0.13186 per share on the Series B preferred shares, $0.25169 per share on the Series C preferred shares, $0.32463 per share on the Series E preferred shares, and $0.31175 per share on the Series G preferred shares, all payable on March 31, 2021.





TRANSALTA CORPORATION F83

Notes to Consolidated Financial Statements
29. Accumulated Other Comprehensive Income
The components of, and changes in, accumulated other comprehensive income (loss) are as follows:
  2020 2019
Currency translation adjustment    
Opening balance, Jan. 1 (21) 17 
Gains (losses) on translating net assets of foreign operations, net of reclassifications to net earnings,
net of tax 		(11) (59)
Gains (losses) on financial instruments designated as hedges of foreign operations, net of
reclassifications to net earnings, net of tax 		11  21 
Balance, Dec. 31 (21) (21)
Cash flow hedges    
Opening balance, Jan. 1 527  508 
Gains (losses) on derivatives designated as cash flow hedges, net of reclassifications to net earnings and
   to non-financial assets, net of tax(1)
(91) 19 
Balance, Dec. 31 436  527 
Employee future benefits    
Opening balance, Jan. 1 (55) (29)
Net actuarial gains (losses) on defined benefit plans, net of tax(2)
(11) (26)
Balance, Dec. 31 (66) (55)
Other    
Opening balance, Jan. 1 3  (15)
Change in ownership of TransAlta Renewables —  1 
Intercompany investments at FVOCI (50) 17 
Balance, Dec. 31 (47) 3 
Accumulated other comprehensive income 302  454 
(1) Net of income tax of $23 million for the year ended Dec. 31, 2020 (2019 — $6 million).
(2) Net of income tax of $3 million for the year ended Dec. 31, 2020 (2019 — $7 million).




TRANSALTA CORPORATION F84
Notes to Consolidated Financial Statements
30. Share-Based Payment Plans
The Corporation has the following share-based payment plans:

A. Performance Share Unit (“PSU”) and Restricted Share Unit (“RSU”) Plan 
Under the PSU and RSU Plan, grants may be made annually, but are measured and assessed over a three-year performance period. Grants are determined as a percentage of participants’ base pay and are converted to PSUs or RSUs on the basis of the Corporation’s common share price at the time of grant. Vesting of PSUs is subject to achievement over a three-year period of two to three performance measures that are established at the time of each grant. RSUs are subject to a three-year cliff-vesting requirement. RSUs and PSUs track the Corporation’s share price over the three-year period and accrue dividends as additional units at the same rate as dividends paid on the Corporation’s common shares.
During 2019, as a result of the Corporation's change in its intended settlement policy, the accounting classification of the RSUs and PSUs changed from cash-settled to equity-settled. The RSUs and PSUs have been accounted for as equity-settled grants from the dates of the policy change, with fair values determined as at that date. On average, the fair value of outstanding grants used in accounting for the change was $8.29, measured using the Black-Scholes option pricing model. As a result of this change, the liability for the cash-settled grants ($25 million) has been derecognized and the equity-settled fair value ($24 million) has been recognized in contributed surplus, with the net difference of $1 million representing the cumulative change in compensation expense. No changes were made to the vesting or performance conditions associated with the awards. The Human Resources Committee of the Board has the discretion to determine whether payments on settlement are made through purchase of shares on the open market or in cash. The expenses related to this plan are recognized during the period earned, with the corresponding amounts due under the plan recorded in contributed surplus (2018 — liabilities). Prior to this change, the liability was valued at the end of each reporting period using the closing price of the Corporation’s common shares on the TSX.
The pre-tax compensation expense related to PSUs and RSUs in 2020 was $15 million (2019 — $19 million, 2018 — $8 million), which is included in operations, maintenance and administration expense in the Consolidated Statements of Earnings (Loss).
B. Deferred Share Unit (“DSU”) Plan 
Under the DSU Plan, members of the Board and executives may, at their option, purchase DSUs using certain components of their fees or pay. A DSU is a notional share that has the same value as one common share of the Corporation and fluctuates based on the changes in the value of the Corporation’s common shares in the marketplace. DSUs accrue dividends as additional DSUs at the same rate as dividends are paid on the Corporation’s common shares. DSUs are redeemable in cash and may not be redeemed until the termination or retirement of the director or executive from the Corporation.
The Corporation accrues a liability and expense for the appreciation in the common share value in excess of the DSU’s purchase price and for dividend equivalents earned. The pre-tax compensation expense related to the DSUs was $1 million in 2020 (2019 — $2 million, 2018 — nil).
C. Stock Option Plans 
The Corporation is authorized to grant options to purchase up to an aggregate of 16.5 million common shares at prices based on the market price of the shares on the TSX as determined on the grant date. The plan provides for grants of options to all full-time employees, including executives, designated by the Human Resources Committee from time to time.
In 2020, the Corporation granted executive officers of the Corporation a total of 0.7 million stock options with a weighted average exercise price of $9.17 that vest after a three-year period and expire seven years after issuance (2019 — 1.4 million stock options at $5.65; 2018 — 0.7 million stock options at $7.45). The expense recognized relating to these grants during 2020 was approximately $2 million (2019 — approximately $1 million, 2018 — approximately $1 million).




TRANSALTA CORPORATION F85

Notes to Consolidated Financial Statements
The total options outstanding and exercisable under these stock option plans at Dec. 31, 2020, are outlined below:
  Options outstanding
Range of exercise prices(1)
($ per share)
Number of options (millions)
Weighted
average
remaining
contractual
life (years)
Weighted
average
exercise
price
 ($ per share)
5.00 - 10.00
4.0  4.2  6.85 
 (1) Options currently exercisable as at Dec. 31, 2020.

31. Employee Future Benefits
A. Description 
The Corporation sponsors registered pension plans in Canada and the US covering substantially all employees of the Corporation in these countries and specific named employees working internationally. These plans have defined benefit and defined contribution options, and in Canada there is an additional non-registered supplemental plan for eligible employees whose annual earnings exceed the Canadian income tax limit. Except for the Highvale pension plan acquired in 2013, the Canadian and US defined benefit pension plans are closed to new entrants. The US defined benefit pension plan was frozen effective Dec. 31, 2010, resulting in no future benefits being earned. The supplemental pension plan was closed as of Dec. 31, 2015, and a new defined contribution supplemental pension plan commenced for executive members effective Jan. 1, 2016. Current executives as of Dec. 31, 2015, were grandfathered into the old supplemental plan.
The latest actuarial valuation for accounting purposes of the US pension plan was at Jan. 1, 2020. The latest actuarial valuation for accounting purposes of the Highvale and Canadian pension plans was at Dec. 31, 2019. The measurement date used for all plans to determine the fair value of plan assets and the present value of the defined benefit obligation was Dec. 31, 2020.
Funding of the registered pension plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, or more, depending on funding status, and every year in the US. The supplemental pension plan is solely the obligation of the Corporation. The Corporation is not obligated to fund the supplemental plan but is obligated to pay benefits under the terms of the plan as they come due. The Corporation posted a letter of credit in March 2020 for the amount of $89 million to secure the obligations under the supplemental plan.
The Corporation provides other health and dental benefits to the age of 65 for both disabled members and retired members through its other post-employment benefits plans. The latest actuarial valuations for accounting purposes of the Canadian and US plans were as at Dec. 31, 2019, and Jan. 1, 2020, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2020.
The Corporation provides several defined contribution plans, including an Australian superannuation plan and a US 401(k) savings plan, that provide for company contributions from 5 per cent to 10 per cent, depending on the plan. Optional employee contributions are allowed for all the defined contribution plans.




TRANSALTA CORPORATION F86
Notes to Consolidated Financial Statements
B. Costs Recognized
 
The costs recognized in net earnings during the year on the defined benefit, defined contribution and other post-employment benefits plans are as follows:
Year ended Dec. 31, 2020 Registered Supplemental Other Total
Current service cost 5  2  1  8 
Administration expenses 1  —  —  1 
Interest cost on defined benefit obligation 16  3  1  20 
Interest on plan assets (11) (1) —  (12)
Curtailment and amendment gain (2) —  —  (2)
Defined benefit expense 9  4  2  15 
Defined contribution expense 9  —  —  9 
Net expense 18  4  2  24 
Year ended Dec. 31, 2019 Registered Supplemental Other Total
Current service cost 7  2  1  10 
Administration expenses 2  —  —  2 
Interest cost on defined benefit obligation 19  3  1  23 
Interest on plan assets (12) (1) —  (13)
Curtailment and amendment gain (3) —  —  (3)
Defined benefit expense 13  4  2  19 
Defined contribution expense 9  —  —  9 
Net expense 22  4  2  28 


Year ended Dec. 31, 2018 Registered Supplemental Other Total
Current service cost 9  2  1  12 
Administration expenses 1  —  —  1 
Interest cost on defined benefit obligation 18  3  1  22 
Interest on plan assets (13) —  —  (13)
Defined benefit expense 15  5  2  22 
Defined contribution expense 10  —  —  10 
Net expense 25  5  2  32 





TRANSALTA CORPORATION F87

Notes to Consolidated Financial Statements
C. Status of Plans
 
The status of the defined benefit pension and other post-employment benefit plans is as follows:
Year ended Dec. 31, 2020 Registered Supplemental Other Total
Fair value of plan assets 367  14  —  381 
Present value of defined benefit obligation (542) (109) (24) (675)
Funded status – plan deficit (175) (95) (24) (294)
Amount recognized in the consolidated financial statements:        
Accrued current liabilities (5) (5) (2) (12)
Other long-term liabilities (170) (90) (22) (282)
Total amount recognized (175) (95) (24) (294)
Year ended Dec. 31, 2019 Registered Supplemental Other Total
Fair value of plan assets 373  13  —  386 
Present value of defined benefit obligation (543) (99) (22) (664)
Funded status – plan deficit (170) (86) (22) (278)
Amount recognized in the consolidated financial statements:        
Accrued current liabilities (3) (5) (2) (10)
Other long-term liabilities (167) (81) (20) (268)
Total amount recognized (170) (86) (22) (278)

D. Plan Assets
 
The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows:
  Registered Supplemental Other Total
As at Dec. 31, 2018 368  13  —  381 
Interest on plan assets 12  1  —  13 
Net return on plan assets 40  —  —  40 
Contributions 6  4  1  11 
Benefits paid (50) (5) (1) (56)
Administration expenses (2) —  —  (2)
Effect of translation on US plans (1) —  —  (1)
As at Dec. 31, 2019 373  13  —  386 
Interest on plan assets 11  1  —  12 
Net return on plan assets 25  (1) —  24 
Contributions 6  6  1  13 
Benefits paid (45) (5) (1) (51)
Administration expenses (1) —  —  (1)
Effect of translation on US plans (2) —  —  (2)
As at Dec. 31, 2020 367  14  —  381 





TRANSALTA CORPORATION F88
Notes to Consolidated Financial Statements
The fair value of the Corporation’s defined benefit plan assets by major category is as follows:
Year ended Dec. 31, 2020 Level I Level II Level III Total
Equity securities        
Canadian —  64  —  64 
US —  30  —  30 
International —  103  —  103 
Private —  —  1  1 
Bonds        
AAA —  36  —  36 
AA —  67  —  67 
A —  34  —  34 
BBB 1  22  —  23 
Below BBB —  4  —  4 
Money market and cash and cash equivalents —  19  —  19 
Total 1  379  1  381 

Year ended Dec. 31, 2019 Level I Level II Level III Total
Equity securities        
Canadian —  66  —  66 
US —  28  —  28 
International —  102  —  102 
Private —  —  1  1 
Bonds        
AAA —  40  —  40 
AA —  68  —  68 
A —  37  —  37 
BBB 1  21  —  22 
Below BBB —  3  —  3 
Money market and cash and cash equivalents —  19  —  19 
Total 1  384  1  386 
Plan assets do not include any common shares of the Corporation at Dec. 31, 2020 and Dec. 31, 2019. The Corporation charged the registered plan nil for administrative services provided for the year ended Dec. 31, 2020 (2019 — nil).




TRANSALTA CORPORATION F89

Notes to Consolidated Financial Statements
E. Defined Benefit Obligation
 
The present value of the obligation for the defined benefit pension and other post-employment benefit plans is as follows:
  Registered Supplemental Other Total
Present value of defined benefit obligation as at Dec. 31, 2018 514  80  25  619 
Current service cost 7  2  1  10 
Interest cost 19  3  1  23 
Benefits paid (51) (4) (1) (56)
Curtailment (3) —  —  (3)
Actuarial gain arising from demographic assumptions —  —  (2) (2)
Actuarial loss arising from financial assumptions 57  9  2  68 
Actuarial gain (loss) arising from experience adjustments 2  9  (4) 7 
Effect of translation on US plans (2) —  —  (2)
Present value of defined benefit obligation as at Dec. 31, 2019 543  99  22  664 
Current service cost 5  2  1  8 
Interest cost 16  3  1  20 
Benefits paid (45) (5) (1) (51)
Curtailment (2) —  —  (2)
Actuarial loss arising from demographic assumptions —  —  —  — 
Actuarial loss arising from financial assumptions 43  10  2  55 
Actuarial gain arising from experience adjustments (17) —  —  (17)
Effect of translation on US plans (1) —  (1) (2)
Present value of defined benefit obligation as at Dec. 31, 2020 542  109  24  675 

The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2020 is 14.4 years.

F. Contributions
 
The expected employer contributions for 2021 for the defined benefit pension and other post-employment benefit plans are as follows:
  Registered Supplemental Other Total
Expected employer contributions 5  5  2  12 





TRANSALTA CORPORATION F90
Notes to Consolidated Financial Statements
G. Assumptions
 
The significant actuarial assumptions used in measuring the Corporation’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows:
  As at Dec. 31, 2020 As at Dec. 31, 2019
(per cent) Registered Supplemental Other  Registered Supplemental Other
Accrued benefit obligation            
Discount rate 2.4  2.3  2.3  3.0  3.0  3.0 
Rate of compensation increase 2.9  3.0  —  2.8  3.0  — 
Assumed health-care cost trend rate            
Health-care cost escalation(1)(3)
—  —  6.8  —  —  7.0 
Dental-care cost escalation —  —  4.0  —  —  4.0 
Benefit cost for the year            
Discount rate 3.0  3.0  3.0  3.9  3.8  3.9 
Rate of compensation increase 2.9  3.0  —  2.5  3.0  — 
Assumed health-care cost trend rate            
Health-care cost escalation(2)(4)
—  —  7.1  —  —  7.4 
Dental-care cost escalation —  —  4.0  —  —  4.0 
(1) 2020 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada.
(2) 2020 Post- and pre-65 rates: decreasing gradually to 4.5% by 2029 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2030 for Canada.
(3) 2019 Post- and pre-65 rates: decreasing gradually to 4.5% by 2030 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2027 for Canada.
(4) 2019 Post- and pre-65 rates: decreasing gradually to 4.5% by 2027 and remaining at that level thereafter for the US and decreasing gradually by 0.3% per year to 4.5% in 2027 for Canada.

H. Sensitivity Analysis
 
The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key assumptions:
  Canadian plans US plans
Year ended Dec. 31, 2020 Registered   Supplemental   Other  Pension Other
1% decrease in the discount rate
74  17  2  3  1 
1% increase in the salary scale
5  —  —  4  1 
1% increase in the health-care cost trend rate
—  —  2  —  — 
10% improvement in mortality rates
20  4  —  1  — 





TRANSALTA CORPORATION F91

Notes to Consolidated Financial Statements
32. Joint Arrangements
Joint arrangements at Dec. 31, 2020, included the following:
Joint operations Segment
Ownership
 (per cent)
Description
Sheerness Alberta Thermal 50 Dual-fuel facility in Alberta, of which TA Cogen has a 50 per cent interest, operated by Heartland Generation Ltd., an affiliate of Energy Capital Partners
Pioneer Pipeline Alberta Thermal 50 Natural gas pipeline in Alberta operated by TMI
Goldfields Power Australian Gas 50 Gas-fired facility in Australia operated by TransAlta
Fort Saskatchewan North American Gas 60 Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta
Fortescue River
Gas Pipeline 		Australian Gas 43 Natural gas pipeline in Western Australia, operated by DBP Development Group
McBride Lake Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta
Soderglen Wind and Solar 50 Wind generation facility in Alberta operated by TransAlta
Pingston Hydro 50 Hydro facility in British Columbia operated by TransAlta
Joint ventures Segment
Ownership
 (per cent)
Description
Skookumchuck Wind and Solar 49 Wind generation facility in Washington operated by Southern Power

 
33. Cash Flow Information
A. Change in Non-Cash Operating Working Capital
Year ended Dec. 31 2020 2019 2018
(Use) source:      
Accounts receivable (79) 261  58 
Prepaid expenses 2  —  19 
Income taxes receivable (4) (6) — 
Inventory 6  (13) (21)
Accounts payable, accrued liabilities and provisions 160  (130) (97)
Income taxes payable 4  9  (3)
Change in non-cash operating working capital 89  121  (44)

B. Changes in Liabilities from Financing Activities
Balance Dec. 31, 2019
Net cash flows New leases Dividends declared Foreign exchange impact Other
Balance Dec. 31, 2020
Long-term debt and lease
obligations 		3,212  133  16  —  5  (5) 3,361 
Exchangeable securities 326  400  —  —  —  4  730 
Dividends payable (common and
preferred) 		37  (86) —  107  —  1  59 
Total liabilities from financing activities 3,575  447  16  107  5  —  4,150 





TRANSALTA CORPORATION F92
Notes to Consolidated Financial Statements
Balance
Dec. 31, 2018
Net cash flows New leases Tax shield on tax equity financing Dividends declared Foreign exchange impact Other
Balance
Dec. 31, 2019
Long-term debt and lease
liabilities 		3,267  (70) 133  (35) —  (42) (41) 3,212 
Exchangeable securities —  350  —  —  —  —  (24) 326 
Dividends payable (common and
preferred) 		58  (85) —  —  64  —  —  37 
Total liabilities from financing
activities 		3,325  195  133  (35) 64  (42) (65) 3,575 

34. Capital
TransAlta’s capital is comprised of the following:
As at Dec. 31 2020 2019 Increase/
(decrease)
Long-term debt(1)
3,361  3,212  149 
Exchangeable securities 730  326  404 
Equity      
Common shares 2,896  2,978  (82)
Preferred shares 942  942  — 
Contributed surplus 38  42  (4)
Deficit (1,826) (1,455) (371)
Accumulated other comprehensive income 302  454  (152)
Non-controlling interests 1,084  1,101  (17)
Less: available cash and cash equivalents(2)
(703) (411) (292)
Less: principal portion of restricted cash on TransAlta OCP bonds(3)
(11) (10) (1)
Less: fair value asset of hedging instruments on long-term debt(4)
(2) (7) 5 
Total capital 6,811  7,172  (361)
(1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.
(2) The Corporation includes available cash and cash equivalents as a reduction in the calculation of capital, as capital is managed internally and evaluated by management using a net debt position.  In this regard, these funds may be available and used to facilitate repayment of debt.
(3) The Corporation includes the principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt.
(4) The Corporation includes the fair value of economic and designated hedging instruments on debt in an asset, or liability, position as a reduction, or increase, in the calculation of capital, as the carrying value of the related debt has either increased, or decreased, due to changes in foreign exchange rates.

The Corporation’s overall capital management strategy and its objectives in managing capital are as follows:
A. Maintain a Strong Financial Position 
The Corporation operates in a long-cycle and capital-intensive commodity business, and it is therefore a priority to maintain a strong financial position that enables the Corporation to access capital markets at reasonable interest rates. 
Maintaining a strong balance sheet also allows its commercial team to contract the Corporation’s portfolio with a variety of counterparties on terms and prices that are favourable to the Corporation’s financial results and provides the Corporation with better access to capital markets through commodity and credit cycles. The Corporation has an investment-grade credit rating from DBRS (stable outlook). During 2020, Moody's reaffirmed its issuer rating of Ba1 with a stable outlook; DBRS reaffirmed the Corporation’s Unsecured Debt rating and Medium-Term Notes rating of BBB (low), the Preferred Shares rating of Pfd-3 (low) and Issuer Rating of BBB (low) with a stable outlook; and Standard and Poor’s reaffirmed the Corporation’s Unsecured Debt rating and Issuer Rating of BB+ with stable outlook. The Corporation remains focused on strengthening its financial position and cash flow coverage ratios. Credit ratings provide information relating to the Corporation's financing costs, liquidity and operations and affect the Corporation's ability to obtain short-term and long-term financing and/or the cost of such financing.





TRANSALTA CORPORATION F93

Notes to Consolidated Financial Statements
Key rating agencies assess TransAlta’s credit rating using a variety of methodologies, including financial ratios. The methodologies and ratios used by rating agencies to assess our credit rating are not publicly disclosed. We have developed our own definitions of ratios and targets to help evaluate the strength of our financial position. These metrics and ratios are not defined under IFRS and may not be comparable to those used by other entities or by rating agencies. These ratios are summarized in the table below:
As at Dec. 31 2020 2019 Target
Funds from operations before interest to adjusted interest coverage (times) 4.2  4.5 
4 to 5
Adjusted funds from operations to adjusted net debt (%) 18.3  19.0 
20 to 25
Adjusted net debt to adjusted comparable earnings before interest,
taxes, depreciation and amortization (times)
3.9  3.9 
3.0 to 3.5
Deconsolidated net debt to deconsolidated comparable EBITDA (times) 4.6 4.2
2.5 to 3.0

Funds from Operations (“FFO”) before Interest to Adjusted Interest Coverage is calculated as FFO less the termination payments for the Sundance B and C PPAs plus interest on debt, exchangeable securities and lease liabilities (net of capitalized interest) divided by interest on debt, exchangeable securities and lease liabilities (net of capitalized interest) plus 50 per cent of dividends paid on preferred shares. The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. FFO is calculated as cash flow from operating activities before changes in working capital and is adjusted for transactions and amounts that the Corporation believes are not representative of ongoing cash flows from operations. The Corporation’s goal is to maintain this ratio in a range of four to five times.

Adjusted FFO to Adjusted Net Debt is calculated as FFO less the termination payments for the Sundance B and C PPAs less 50 per cent of dividends paid on preferred shares divided by adjusted net debt (current and long-term debt plus exchangeable securities plus 50 per cent of outstanding preferred shares less available cash and cash equivalents less principal portion of TransAlta OCP restricted cash and including fair value assets of hedging instruments on debt). The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. The Corporation’s goal is to maintain this ratio in a range of 20 to 25 per cent.

Adjusted Net Debt to Adjusted Comparable EBITDA is calculated as adjusted net debt divided by adjusted comparable EBITDA. Adjusted comparable EBITDA is calculated as earnings before interest, taxes, depreciation and amortization and is adjusted for transactions and amounts that the Corporation believes are not representative of ongoing business operations as well as the termination payments for the Sundance B and C PPAs. The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. The Corporation’s goal is to maintain this ratio in a range of 3.0 to 3.5 times.

Deconsolidated net debt to deconsolidated comparable EBITDA is calculated as deconsolidated net debt (long-term debt, lease liabilities and exchangeable debentures including current portion and fair value (asset) liability of hedging instruments on debt plus 50 per cent issued preferred shares less cash and cash equivalents less principal portion of TransAlta OCP restricted cash less TransAlta Renewables long-term debt and lease liabilities including current portion less tax equity financing) divided by deconsolidated comparable EBITDA (comparable EBITDA less TransAlta Renewables comparable EBITDA less TA Cogen comparable EBITDA plus dividends received from TransAlta Renewables plus dividends received from TA Cogen). The exchangeable preferred shares (see Note 25) are considered equity with dividend payments for credit purposes. The Corporation's goal is to maintain this ratio in a range of 2.5 to 3.0 times.

At times, the credit ratios may be outside of the specified ranges while the Corporation executes its conversion to gas and growth strategy, but we remain focused on maintaining a strong balance sheet.

Management routinely monitors forecasted net earnings, cash flows, capital expenditures and scheduled repayment of debt with a goal of meeting the above ratio targets and to meet dividend and PP&E expenditure requirements.

B. Ensure Sufficient Cash and Credit is Available to Fund Operations, Pay Dividends, Distribute Payments to Subsidiaries’ Non-Controlling Interests, Invest in PP&E and Make Acquisitions
For the years ended Dec. 31, 2020 and 2019, cash inflows and outflows are summarized below. The Corporation manages variations in working capital using existing liquidity under credit facilities.




TRANSALTA CORPORATION F94
Notes to Consolidated Financial Statements
Year ended Dec. 31 2020 2019 Increase
(decrease)
Cash flow from operating activities 702  849  (147)
Change in non-cash working capital (89) (121) 32 
Cash flow from operations before changes in working capital 613  728  (115)
Dividends paid on common shares (47) (45) (2)
Dividends paid on preferred shares (39) (40) 1 
Distributions paid to subsidiaries’ non-controlling interests (97) (106) 9 
Property, plant and equipment expenditures (486) (417) (69)
Inflow (outflow) (56) 120  (176)

TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2020, $1.5 billion (2019 — $1.3 billion) of the Corporation’s credit facilities were fully available.

From time to time, TransAlta accesses capital markets, as required, to help fund some of these periodic net cash outflows, to maintain its available liquidity, and to maintain its capital structure and credit metrics within targeted ranges.

35. Related-Party Transactions
Details of the Corporation’s principal operating subsidiaries at Dec. 31, 2020, are as follows:

Subsidiary Country Ownership
(per cent) 		Principal activity
TransAlta Generation Partnership Canada 100 Generation and sale of electricity
TransAlta Cogeneration, L.P. Canada 50.01 Generation and sale of electricity
TransAlta Centralia Generation, LLC US 100 Generation and sale of electricity
TransAlta Energy Marketing Corp. Canada 100 Energy marketing
TransAlta Energy Marketing (U.S.), Inc. US 100 Energy marketing
TransAlta Energy (Australia), Pty Ltd. Australia 100 Generation and sale of electricity
TransAlta Renewables Inc. Canada 60.1 Generation and sale of electricity
Associate or joint venture Country Ownership
(per cent) 		Principal activity
SP Skookumchuck Investment, LLC US 49 Generation and sale of electricity
EMG International, LLC US 30 Wastewater treatment and biogas fuel to generate electricity
Transactions between the Corporation and its subsidiaries have been eliminated on consolidation and are not disclosed. Associates and joint ventures have been equity accounted for by the Corporation.
Transactions with Key Management Personnel 
TransAlta’s key management personnel include the President and CEO and members of the senior management team that report directly to the President and CEO, and the members of the Board. Key management personnel compensation is as follows:
Year ended Dec. 31 2020 2019 2018
Total compensation 27  30  17 
Comprised of:      
  Short-term employee benefits 12  13  11 
  Post-employment benefits 2  2  2 
  Termination benefits —  2  — 
  Share-based payments 13  13  4 






TRANSALTA CORPORATION F95

Notes to Consolidated Financial Statements
36. Commitments and Contingencies
In addition to commitments disclosed elsewhere in the financial statements, the Corporation has incurred the following additional contractual commitments, either directly or through its interests in joint operations. Approximate future payments under these agreements are as follows:
  2021 2022 2023 2024 2025 2026 and thereafter Total
Natural gas, transportation and
other contracts 		141  149  137  134  134  1,353  2,048 
Transmission 8  8  8  5  5  1  35 
Coal supply and mining
agreements 		81  105  101  67  56  —  410 
Long-term service agreements 31  37  22  18  10  55  173 
Operating leases 4  2  2  1  1  26  36 
Growth 509  411  93  —  —  —  1,013 
TransAlta Energy Transition Bill 6  6  6  —  —  —  18 
Total 780  718  369  225  206  1,435  3,733 

A. Natural Gas, Transportation and Other Contracts 
The Corporation has fixed price or volume natural gas purchase and transportation contracts. In addition to the commitments shown above, upon closing the sale of the Pioneer Pipeline, a 15-year transportation agreement will provide an additional 275 TJ per day of natural gas on a firm basis by 2023, bringing the total firm natural gas transportation contracts to 400 TJ per day by 2023. This agreement would replace the Corporation's existing 15-year commitment to purchase 139 TJ per day of natural gas on the Pioneer Pipeline, which remains in place until the closing of the Transaction. Other contracts relate to commitments for goods and services.
B. Transmission 
The Corporation has several agreements to purchase transmission network capacity in the Pacific Northwest. Provided certain conditions for delivering the service are met, the Corporation is committed to the transmission at the supplier’s tariff rate whether it is awarded immediately or delivered in the future after additional facilities are constructed.
C. Coal Supply and Mining Agreements 
Various coal supply and associated rail transport contracts are in place to provide coal for use in production at the Centralia thermal facility. The coal supply agreements allow TransAlta to take delivery of coal at fixed volumes with dates extending to 2025. In 2020, a new rail transportation service contract was entered into and pricing is reflective of current market conditions. As a result, there is an increase in expected rail transportation costs over the service period.
Commitments related to mining agreements include the Corporation’s share of commitments for mining agreements related to its Sheerness joint operation and certain other mining royalty agreements. Some of these commitments have been reduced due to the accelerated plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021.
D. Long-Term Service Agreements 
TransAlta has various service agreements in place, primarily for inspections and repairs and maintenance that may be required on natural gas facilities, coal facilities and turbines at various wind facilities.
E. Operating Leases
Includes lease commitments not recognized under IFRS 16 and lease commitments that have not yet commenced, mainly related to buildings, vehicles and land.

Prior to the adoption of IFRS 16, operating lease expenses were recognized as incurred in the statement of earnings. During the year ended Dec. 31, 2018, $8 million was recognized as an expense in respect of operating leases. Sublease payments received during 2020 were $2 million (2019 and 2018 — were less than $1 million). No contingent rental payments were made in respect of operating leases.





TRANSALTA CORPORATION F96
Notes to Consolidated Financial Statements
F. Growth 
Commitments for growth relate to the following projects: conversion to gas and repowering Sundance Unit 5, Kaybob cogeneration project, Windrise project and any final costs associated with the Big Level and Antrim wind projects. Refer to Note 4 for further details on these projects.

G. TransAlta Energy Transition Bill Commitments 
As part of the TransAlta Energy Transition Bill signed into law in the State of Washington and the subsequent MOA, we have committed to fund US$55 million in total over the remaining life of the Centralia coal plant to support economic and community development, promote energy efficiency and develop energy technologies related to the improvement of the environment. The MoA contains certain provisions for termination and in the event of the termination and certain circumstances, this funding or part thereof would no longer be required. As of Dec. 31, 2020, the Corporation has funded approximately US$41 million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position.
H. Other 
A significant portion of the Corporation’s electricity and thermal production are subject to PPAs and long-term contracts. The majority of these contracts include terms and conditions customary to the industry in which the Corporation operates. The nature of commitments related to these contracts includes: electricity and thermal capacity, availability and production targets; reliability and other plant-specific performance measures; specified payments for deliveries during peak and off-peak time periods; specified prices per MWh; risk sharing of fuel costs; and retention of heat rate risk.
I. Contingencies 
TransAlta is occasionally named as a party in various claims and legal and regulatory proceedings that arise during the normal course of its business. TransAlta reviews each of these claims, including the nature of the claim, the amount in dispute or claimed, and the availability of insurance coverage. There can be no assurance that any particular claim will be resolved in the Corporation’s favour or that such claims may not have a material adverse effect on TransAlta. Inquiries from regulatory bodies may also arise in the normal course of business, to which the Corporation responds as required.
I. Line Loss Rule Proceeding 
The Corporation has been participating in a line loss rule proceeding before the AUC. The AUC determined that it has the ability to retroactively adjust line loss charges going back to 2006 and directed the AESO to recalculate loss factors for 2006 to 2016 and issue a single invoice charging or crediting market participants for the difference in losses charges. The AESO submitted a review and variance application of this decision to implement a “pay-as-you-go” invoicing scheme rather than issue a single invoice. The AUC ruled on the AESO’s request and approved a three-period invoice process (2006-2009, 2010-2013 and 2014-2016). The total liability for the loss charges was $25 million; however, due to payments made (and received) for the first two invoices, only $8 million of the total liability remains outstanding. The AESO issued the first invoice on Oct. 22, 2020 for $6 million, which was paid by Dec. 30, 2020. The second invoice was issued on Dec. 21, 2020, for $11 million. The third invoice is expected in March 2021.

In November 2020, the AESO sought direction from the AUC with respect to interest payments on the loss charges and the AUC ruled in January 2021 that simple interest rather than compound interest would apply to the loss charges.

II. FMG Disputes
The Corporation is currently engaged in a dispute with Fortescue Metals Group Ltd. ("FMG") as a result of FMG's purported termination of the South Hedland PPA. TransAlta sued FMG, seeking payments of amounts invoiced and not paid under the South Hedland PPA, as well as a declaration that the PPA is valid and in force. FMG, on the other hand, seeks a declaration that the PPA was lawfully terminated. This matter has been rescheduled to proceed to trial beginning May 3, 2021, instead of June 15, 2020.

The Corporation had a second dispute involving FMG's claims against TransAlta related to the transfer of the Solomon facility to FMG. FMG claimed certain amounts related to the condition of the facility while TransAlta claimed certain outstanding costs that should be reimbursed. The dispute was settled and discontinued in the Supreme Court of Western Australia on Sept. 9, 2020.





TRANSALTA CORPORATION F97

Notes to Consolidated Financial Statements
III. Mangrove Claim
On April 23, 2019, Mangrove commenced an action in the Ontario Superior Court of Justice, naming the Corporation, the incumbent members of the Board of Directors of the Corporation on such date and Brookfield BRP Holdings (Canada), as defendants. Mangrove is seeking to set aside the Brookfield Investment. TransAlta believes the claim is wholly lacking in merit and is taking all steps to defend against the allegations. This matter has been rescheduled and the three-week trial will begin on April 19, 2021.

IV. Keephills 1 Stator Force Majeure
The Balancing Pool and ENMAX Energy Corporation ("ENMAX") are seeking to set aside an arbitration award on the basis that they did not receive a fair hearing. The Alberta Court of Queen’s Bench ("ABQB") dismissed the Balancing Pool and ENMAX’s allegations of unfairness on June 26, 2019. The Balancing Pool and ENMAX, however, sought leave to appeal the ABQB’s decision at the Court of Appeal, which was granted on Feb. 13, 2020. The appeal is scheduled to be heard on April 8, 2021. TransAlta believes that the Court of Appeal will affirm the ABQB decision that the arbitration proceeding was fair.

V. Keephills 1 Superheater Force Majeure
Keephills Unit 1 was taken offline from March 17, 2015 to May 17, 2015, as a result of a large leak in the secondary superheater. TransAlta Generation Partnership claimed force majeure under the Keephills PPA. ENMAX, the PPA buyer under the PPA at the time, did not dispute the force majeure, but the Balancing Pool did, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The Balancing Pool argued and won in the Courts that it has a right under the PPA to commence an arbitration, independent of the PPA buyer, ENMAX. An arbitration for this dispute has commenced and is set to be heard for seven days starting Dec. 6, 2021.

VI. Sundance A Decommissioning
TransAlta filed an application with the AUC seeking payment from the Balancing Pool for TransAlta’s decommissioning costs for Sundance A, including its proportionate share of the Highvale mine. The Balancing Pool and Utilities Consumer Advocate are participating as interveners because they take issue with the decommissioning costs claimed by TransAlta. Due to various factors including the COVID-19 pandemic and significant information requests from the Balancing Pool, the application has been delayed. While a hearing date has not been set, the application will likely be heard in late 2021 or early 2022. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain.

VII. Hydro Power Purchase Arrangement ("Hydro PPA") Emission Performance Credits
The Balancing Pool claims to be entitled to emissions performance credits ("EPCs"), valued at approximately $17 million per year, earned by the Hydro facilities under the Carbon Competitiveness Incentive Regulation from 2018-2020. Refer to Note 2(A) and 2(F)(IV) for the accounting policies on these credits. The dispute is based on the ownership of the EPCs as a result of a change in law provision under the Hydro PPA and that TransAlta is benefiting from the purported change in law. TransAlta has not received any benefit from the EPCs and has not recognized any benefit from the EPCs within its financial statements. TransAlta believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and will be likely set down for a hearing sometime in early 2022.

VIII. Direct Assigned Capital Deferral Account ("DACDA") Application
AltaLink Management Ltd. ("AltaLink") filed an application before the AUC to recover its 2016-2018 DACDA costs (the "Proceeding") incurred for the 240 kV line upgrades project in the Edmonton region (the “Upgrades Project”). TransAlta is a secondary applicant in the Proceeding because it owns a portion of the 1043L Line located on Enoch Cree Nation (“ECN”) Reserve that was a part of the Upgrades Project. AltaLink and TransAlta sought to have their costs ($91 million for AltaLink and $22 million for TransAlta) approved by the AUC as reasonable and prudent. The ECN and the Consumers' Coalition of Alberta are registered participants in the Proceeding. The AUC rendered its decision in the Proceeding on Dec. 10, 2020, and disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta believes that the AUC made errors by disallowing 15 per cent of its costs and therefore filed a permission to appeal application with the Court of Appeal (the “PTA”) and a review and variance application with the AUC (the “R&V”). The PTA will be adjourned until the R&V process is completed.





TRANSALTA CORPORATION F98
Notes to Consolidated Financial Statements
37. Segment Disclosures
A. Description of Reportable Segments 
The Corporation has eight reportable segments as described in Note 1.
The following tables provides each segment's results in the format that management organizes its segments to make operating decisions and assess performance. For internal reporting purpose, the earnings information from the Corporation's investment in Skookumchuck has been presented in the Wind and Solar segment on a proportionate basis. Information on a proportionate basis reflects the Corporation's share of Skookumchuck's statement of earnings on a line-by-line basis. Proportionate financial information is not, and is not intended to be, presented in accordance with IFRS. Under IFRS, the investment in Skookumchuck has been accounted for as a joint venture using the equity method. The table below also shows the reconciliation of the total segmented results to the statement of earnings reported under IFRS.
B. Reported Segment Earnings (Loss) and Segment Assets
I. Earnings Information
Year ended Dec. 31, 2020 Hydro
Wind
and
Solar(1)
North
American
Gas(2)
Australian
Gas
Alberta
Thermal(3)
Centralia(3)
Energy
Marketing 		Corporate Total
Equity accounted investments(1)
IFRS Financials
Revenues 152  332  217  158  619  497  122  7  2,104  (3) 2,101 
Fuel, carbon
compliance and
purchased power 		8  25  66  10  573  279  —  7  968  —  968 
Gross margin 144  307  151  148  46  218  122  —  1,136  (3) 1,133 
Operations,
maintenance and
administration 		37  53  49  32  131  60  30  80  472  —  472 
Depreciation and
amortization 		28  136  46  43  270  105  2  25  655  (1) 654 
Asset impairment 2  —  —  —  75  7  —  —  84  —  84 
Taxes, other than
income taxes 		2  8  2  —  15  5  —  1  33  —  33 
Net other operating
expense (income) 		—  —  —  —  (11) —  —  —  (11) —  (11)
Operating income
(loss) 		75  110  54  73  (434) 41  90  (106) (97) (2) (99)
Equity income from associate(1)
—  —  —  —  —  —  —  —  —  1  1 
Finance lease income —  —  5  2  —  —  —  —  7  —  7 
Net interest expense (239) 1  (238)
Foreign exchange
loss 		17  —  17 
Gain on sale of assets
and other 		9  —  9 
Earnings before
income taxes 		(303) —  (303)
(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.
(2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details.
(3) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.





TRANSALTA CORPORATION F99

Notes to Consolidated Financial Statements
Year ended Dec. 31, 2019 Hydro Wind
and
Solar
North
American
Gas(1)
Australian
Gas
Alberta
Thermal(2)
Centralia(2)
Energy
Marketing 		Corporate Total
Revenues 156  312  209  160  816  571  129  (6) 2,347 
Fuel, carbon compliance and
purchased power 		7  16  74  9  570  416  —  (6) 1,086 
Gross margin 149  296  135  151  246  155  129  —  1,261 
Operations, maintenance and
administration 		36  50  44  37  138  67  30  73  475 
Depreciation and amortization 32  124  41  48  233  83  2  27  590 
Asset impairment (reversal) 2  —  —  —  15  (10) —  18  25 
Gain on termination of
   Keephills 3 coal rights
   contract (Note 4(R))
—  —  —  —  (88) —  —  —  (88)
Taxes, other than income taxes 3  8  1  —  13  3  —  1  29 
Termination of Sundance B and
   C PPAs (Note 9)
—  —  —  —  (56) —  —  —  (56)
Net other operating expense
(income) 		—  (10) (1) —  (40) —  —  2  (49)
Operating income (loss) 76  124  50  66  31  12  97  (121) 335 
Finance lease income —  —  6  —  —  —  —  —  6 
Net interest expense                 (179)
Foreign exchange loss                 (15)
Gain on sale of assets and
other 		46 
Earnings before income taxes                 193 
(1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details.
(2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
Year ended Dec. 31, 2018 Hydro Wind
and
Solar
North
American
Gas(1)
Australian
Gas
Alberta
Thermal(2)
Centralia(2)
Energy
Marketing 		Corporate Total
Revenues 156  282  232  165  912  442  67  (7) 2,249 
Fuel, carbon compliance and
purchased power 		6  17  96  8  666  314  —  (7) 1,100 
Gross margin 150  265  136  157  246  128  67  —  1,149 
Operations, maintenance and
administration 		38  50  48  37  171  61  24  86  515 
Depreciation and amortization 30  110  43  49  241  74  2  25  574 
Asset impairment —  12  —  —  38  —  —  23  73 
Taxes, other than income taxes 3  8  1  —  13  5  —  1  31 
Termination of Sundance B and
   C PPAs (Note 9)
—  —  —  —  (157) —  —  —  (157)
Net other operating income —  (6) —  —  (41) —  —  —  (47)
Operating income (loss) 79  91  44  71  (19) (12) 41  (135) 160 
Finance lease income —  —  8  —  —  —  —  —  8 
Net interest expense                 (250)
Foreign exchange loss (15)
Gain on sale of assets 1 
Earnings before income taxes                 (96)
(1) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details.
(2) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.





TRANSALTA CORPORATION F100
Notes to Consolidated Financial Statements
II. Selected Consolidated Statements of Financial Position Information
As at Dec. 31, 2020 Hydro Wind
and
Solar
North
American
Gas(2)
Australian
Gas
Alberta
Thermal(1)
Centralia(1)
Energy
Marketing 		Corporate Total
PP&E 467  2,005  382  421  2,271  260  —  16  5,822 
Right-of-use assets 6  55  1  4  53  —  —  22  141 
Intangible assets 4  159  32  34  31  5  7  41  313 
Goodwill 258  175  —  —  —  —  30  —  463 
As at Dec. 31, 2019 Hydro Wind
and
Solar
North
American
Gas(2)
Australian
Gas
Alberta
Thermal(1)
Centralia(1)
Energy
Marketing 		Corporate Total
PP&E 469  1,947  392  489  2,540  352  1  17  6,207 
Right-of-use assets 6  56  —  4  68  —  —  12  146 
Intangible assets 5  173  2  37  41  6  9  45  318 
Goodwill 258  176  —  —  —  —  30  —  464 
(1) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
(2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details.

III. Selected Consolidated Statements of Cash Flows Information
Additions to non-current assets are as follows:

Year ended Dec. 31, 2020 Hydro Wind
and
Solar
North
American
Gas(2)
Australian
Gas
Alberta
Thermal(1)
Centralia(1)
Energy
Marketing 		Corporate Total
Additions to non-current assets:                  
 PP&E 22  174  39  10  200  28  —  13  486 
 Intangible assets —  —  —  —  1  —  —  13  14 
Year ended Dec. 31, 2019 Hydro Wind
and
Solar
North
American
Gas(2)
Australian
Gas
Alberta
Thermal(1)
Centralia(1)
Energy
Marketing 		Corporate Total
Additions to non-current assets:                  
 PP&E 23  229  36  6  114  8  —  1  417 
 Intangible assets —  —  —  —  2  —  —  12  14 
Year ended Dec. 31, 2018 Hydro Wind
and
Solar
North
American
Gas(2)
Australian
Gas
Alberta
Thermal(1)
Centralia(1)
Energy
Marketing 		Corporate Total
Additions to non-current assets:                  
 PP&E 16  117  21  6  101  14  —  2  277 
 Intangible assets —  —  —  —  3  —  —  17  20 
(1) The Canadian Coal segment was renamed Alberta Thermal and the US Coal segment was renamed Centralia in the third quarter of 2020.
(2) This segment was previously known as the Canadian Gas segment but renamed with the acquisition of the US cogeneration facility in the second quarter of 2020. Refer to Note 4(K) for further details.





TRANSALTA CORPORATION F101

Notes to Consolidated Financial Statements
IV. Depreciation and Amortization on the Consolidated Statements of Cash Flows 
The reconciliation between depreciation and amortization reported on the Consolidated Statements of Earnings (Loss) and the Consolidated Statements of Cash Flows is presented below:

Year ended Dec. 31 2020 2019 2018
Depreciation and amortization expense on the Consolidated Statements of
Earnings (Loss) 		654  590  574 
Depreciation included in fuel, carbon compliance and purchased power (Note 6) 144  119  136 
Depreciation and amortization on the Consolidated Statements of Cash Flows 798  709  710 

C. Geographic Information
I. Revenues
Year ended Dec. 31 2020 2019 2018
Canada 1,227  1,460  1,573 
US 716  727  511 
Australia 158  160  165 
Total revenue 2,101  2,347  2,249 

II. Non-Current Assets
Property, plant and
equipment 		Right-of-use assets Intangible assets Other assets Goodwill
As at Dec. 31 2020 2019 2020 2019 2020 2019 2020 2019 2020 2019
Canada 4,661  4,854  107  109  185  213  74  75  418  418 
US 737  863  30  33  94  68  61  47  45  46 
Australia 424  490  4  4  34  37  71  76  —  — 
Total 5,822  6,207  141  146  313  318  206  198  463  464 

D. Significant Customer 
During the year ended Dec. 31, 2020, no sales to any one customer was greater than 10 per cent of the Corporation’s total revenue (2019 — one customer within the Alberta Thermal and Hydro segments represented 11 per cent of total revenue).





TRANSALTA CORPORATION F102

Exhibit 1

Exhibit 1 
(Unaudited)
The information set out below is referred to as “unaudited” as a means of clarifying that it is not covered by the audit opinion of the independent registered public accounting firm that has audited and reported on the Consolidated Financial Statements.
To the Financial Statements of TransAlta Corporation

EARNINGS COVERAGE RATIO
The following selected financial ratio is calculated for the year ended Dec. 31, 2020:
Earnings coverage on long-term debt supporting the Corporation’s Shelf Prospectus
(0.46) times
Earnings coverage on long-term debt on a net earnings basis is equal to net earnings before interest expense and income taxes, divided by interest expense including capitalized interest.





TRANSALTA CORPORATION F103

Exhibit 23.1
  
EYLOGOA011.JPG  

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 

We consent to the reference of our Firm under the caption “Experts”, and to the incorporation by reference in the following Registration Statements:

a.Form S-8 Nos. 333-236894, 333-72454 and 333-101470 pertaining to TransAlta Corporation’s Share Option Plan

b.Form F-10 No. 333-229991 pertaining to the registration of Debt and Equity Securities

of TransAlta Corporation and the use herein of our reports dated March 2, 2021, with respect to the consolidated statements of financial position as at December 31, 2020 and 2019 and the consolidated statements of earnings (loss), comprehensive income (loss), changes in equity and cash flows for each of the years in the three year period ended December 31, 2020, and the effectiveness of internal control over financial reporting of TransAlta Corporation as of December 31, 2020, included in this Annual Report on Form 40-F.



 
 
  /s/Ernst & Young LLP
Calgary, Alberta
March 2, 2021
Chartered Professional Accountants
 


 
 
A member firm of Ernst & Young Global Limited



Exhibit 31.1
 
Certifications
I, Dawn L. Farrell, certify that:
1.I have reviewed this annual report on Form 40-F of TransAlta Corporation;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.
 
March 2, 2021  
  /s/ Dawn L. Farrell
  Dawn L. Farrell
  President and Chief Executive Officer



Exhibit 31.2
 
Certifications
 
I, Todd Stack, certify that:
1.I have reviewed this annual report on Form 40-F of TransAlta Corporation;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
4.The issuer’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
5.The issuer’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.
March 2, 2021  
  /s/ Todd Stack
  Todd Stack
  Executive Vice-President, Finance and Chief Financial Officer



Exhibit 32.1
 
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Annual Report of TransAlta Corporation (the “Company”) on Form 40-F for the year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Dawn L. Farrell, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
1.The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and
2.The information contained in the Report fairly presents, in all materials respects, the financial condition and result of operations of the Company.

/s/ Dawn L. Farrell
Dawn L. Farrell
President and Chief Executive Officer
 
Dated: March 2, 2021
 
 
 
The foregoing certification is being furnished solely to accompany the Report pursuant to 18 U.S.C § 1350, and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.



Exhibit 32.2
 
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Annual Report of TransAlta Corporation (the “Company”) on Form 40-F for the year ended December 31, 2020 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Todd Stack, Executive Vice-President, Finance and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
 
1.The Report fully complies with the requirements of Section 13(a) or 15(d), as applicable of the Securities Exchange Act of 1934, as amended; and
2.The information contained in the Report fairly presents, in all materials respects, the financial condition and result of operations of the Company.
 
 
 
/s/ Todd Stack  
Todd Stack  
Executive Vice-President, Finance and Chief Financial Officer  
 
Dated: March 2, 2021
 
 
 
The foregoing certification is being furnished solely to accompany the Report pursuant to 18 U.S.C § 1350, and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.