UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 40-F
 
[Check one]
 
☐           REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
 
OR
 
☒   ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year endedDecember 31, 2021Commission file number001-15214
 
 
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 classTrading SymbolsName of each exchange
  on which registered
   
  
Common Shares, no par valueTACNew York Stock Exchange
  
Common Share Purchase RightsTACNew 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:
 
☒        Annual information form
☒        Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report:
 
At December 31, 2021, 271,034,933 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. ¨

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† 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.

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x
 
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.
 
FormRegistration No.
S-8333-72454
S-8333-101470
S-8333-236894
S-8333-260935
F-10333-257098
 
 
CONSOLIDATED AUDITED ANNUAL FINANCIAL STATEMENTS
AND MANAGEMENT’S DISCUSSION & ANALYSIS
 
A.                                             Consolidated Audited Annual Financial Statements
 
For consolidated audited annual financial statements for the year ended December 31, 2021, 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.
 
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Based on the foregoing evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2021, 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.

Management evaluated the effectiveness of our internal control over financial reporting as of December 31, 2021 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, 2021.  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, 2021.  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, 2021, filed as Exhibit 13.3 and incorporated by reference herein, under the heading “Report of Independent Registered Public Accounting Firm - Public Company Accounting Oversight Board (United States) (“PCAOB”) (PCAOB 1263)".
 
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
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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.
 
In accordance with the provisions of NI 52-109 and consistent with U.S. Securities and Exchange Commission (the "SEC") guidance, the scope of the evaluation did not include internal controls over financial reporting of the acquisition of a 122 MW portfolio of operating solar sites located in North Carolina, which TransAlta Corporation (“TransAlta” or the “Company”) acquired on Nov. 5, 2021. North Carolina Solar was excluded from management's evaluation of the effectiveness of the Company's internal control over financial reporting as at Dec. 31, 2021 due to the proximity of the acquisition to year-end. Further details related to the acquisition are disclosed in Note 4 to the Company's Consolidated Financial Statements for the year ended Dec. 31, 2021. Included in the 2021 consolidated financial statements of TransAlta for North Carolina Solar is 2 per cent and 5 per cent of the Company`s total and net assets, respectively, as at Dec. 31, 2021.

TransAlta proportionately consolidates the accounts of the Sheerness Generating Station joint operations and equity accounts for investment in SP Skookumchuck Investment, LLC, (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 at the transactional level of any of the Excluded Entities.

The 2021 consolidated financial statements of TransAlta, in accordance with EITF 00-1, included for joint operations and equity accounted investments are 4 per cent and 10 per cent of the Company's total and net assets, respectively, as of Dec. 31, 2021, and 8 percent of the Company's revenues for the year then ended. Once the financial information is obtained from these Excluded Entities it falls within the scope of TransAlta’s internal control framework.

AUDIT COMMITTEE FINANCIAL EXPERT
 
TransAlta’s board of directors has determined that each member of the Audit, Finance and Risk Committee (the “AFRC”) is an audit committee financial expert. Ms. Beverlee F. Park, Mr. Alan Fohrer, Mr. Thomas O'Flynn 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, Mr. O'Flynn, Mr. Fohrer and Mr. Pinney, see the section titled “Audit, Finance and Risk Committee” in our Annual Information Form for the year ended December 31, 2021 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
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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 2021 fiscal year.
 
PRINCIPAL ACCOUNTANT FEES AND SERVICES
 
For the years ended December 31, 2021 and December 31, 2020, Ernst & Young LLP and its affiliates billed or expect to bill , including out-of-pocket costs, $4,432,833 and $4,703,316, respectively, as detailed below:
 
Ernst & Young LLP
 
Year Ended Dec. 3120212020
Audit Fees(1)
$2,936,910 $2,574,625 
Audit-related fees(1)(2)
1,429,365 1,294,822 
Tax fees66,558 833,869 
All other fees— — 
Total$4,432,833 $4,703,316 
 (1) Comparative figures have been reclassified to confirm to the current periods classification of fees.
(2) Included in the audit-related fees are $968,935 (2020 - $861,338) of fees billed to TransAlta Renewables.

All amounts are in Canadian dollars unless otherwise stated.
 
No other audit firms provided audit services in 2021 or 2020.
 
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 2021 and 2020, 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.
 
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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, 2021, 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.

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)
Alan J. Fohrer
Bryan D. Pinney
Thomas O'Flynn
 
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 – Energy Transition 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
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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: our Clean Electricity Growth Plan and ability to achieve the target of 2 gigawatts ("GW") of incremental renewables capacity with an investment of $3 billion by 2025; the Company's future growth pipeline, including the timing of commercial operations and the costs of the advanced and early-stage projects; expansion of the Company's development pipeline to 5 GW; the White Rock East and White Rock West Wind Power Projects, including the total construction costs, ability to secure tax equity financing, the timing of commercial operation and expected average earnings before interest, taxes, depreciation and amortization ("EBITDA"); the proportion of EBITDA to be generated from renewable sources by the end of 2025; the suspension of the Sundance 5 repowering project; expected average annual EBITDA of the North Carolina Solar (as defined above) portfolio; the incident at the Kent Hills 1 and 2 wind facilities and the extent of any remediation, the timing and cost of such remediation, the ability to secure waivers in respect of the Kent Hills bonds for any potential event of default, and the impact such incident could have on the Company's revenues and contracts; the Northern Goldfields Solar Project, including the total construction capital and expected average annual EBITDA; the Garden Plain wind project, including construction capital and expected average annual EBITDA; expected increases to our cost per tonne of coal at Centralia; the expected impact and quantum of carbon compliance costs; the ability to realize future growth opportunities with BHP (as defined in the Management Discussion & Analysis); regulatory developments and their expected impact on the Company, including the Canadian federal climate plan and the implementation of the major aspects thereof (including increased carbon pricing and increased funding for clean technology); the ability of the Company to realize benefits from Canadian, US and Australian regulatory developments, including receiving funding for clean electricity projects; the potential increase in value of emission reduction credits; the 2022 financial outlook, including adjusted EBITDA, free cash flow ("FCF") and annualized dividend in 2022; increased gross margin contribution from Energy Marketing; hedged production and price for the full year 2022; hedged gas volume and gas price for 2022; sustaining and productivity capital in 2022, including routine capital, planned major maintenance and mine capital; significant planned major outages for 2022 and lost production due to planned major maintenance for 2022; expected power prices in Alberta, Ontario and the Pacific Northwest; the cyclicality of the business, including as it relates to maintenance costs, production and loads; expectations regarding refinancing the debt maturing in 2022; the liquidated damages potentially payable in respect of the Sarnia outages in the second quarter of 2021; and the Company continuing to maintain a strong financial position and significant liquidity.
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 Company; no significant changes to applicable laws and regulations beyond those that have already been announced; no significant changes to the fuel and purchased power costs; no material adverse impacts to the long-term investment and credit markets; Alberta spot prices of $80 /MWh to $90/MWh in 2022; Mid-Columbia spot prices of US$45/MWh to US$55/MWh in 2022; sustaining capital of $150 million to $170 million; the Company's proportionate ownership of TransAlta Renewables Inc. ("TransAlta Renewables") not changing materially; no decline in the dividends to be received from TransAlta Renewables; and the growth of TransAlta Renewables.
Forward-looking statements are subject to a number of significant risks and uncertainties 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 risks relating to: the impact of COVID-19, including more restrictive directives of government and public health authorities; increased force majeure claims; reduced labour availability and ability to
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continue to staff our operations and facilities; disruptions to our supply chains, including our ability to secure necessary equipment; our ability to obtain regulatory approvals on the expected timelines or at all in respect of our growth projects; restricted access to capital and increased borrowing costs; changes in short-term and/or long-term electricity supply and demand; fluctuations in market prices, including lower merchant pricing in Alberta, Ontario and Mid-Columbia; reductions in production; increased costs; a higher rate of losses on our accounts receivables due to credit defaults; impairments and/or write-downs of assets; adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats; commodity risk management and energy trading risks, including the effectiveness of the Company’s risk management tools associated with hedging and trading procedures to protect against significant losses; 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; operational risks involving our facilities, including unplanned outages; disruptions in the transmission and distribution of electricity; the effects of weather, including man made or natural disasters and other climate-change related risks; unexpected increases in cost structure; reductions to our generating units’ relative efficiency or capacity factors; disruptions in the source of fuels, including natural gas and coal, as well as the extent of water, solar or wind resources required to operate our facilities; general economic risks, including deterioration of equity markets, increasing interest rates or rising inflation; failure to meet financial expectations; general domestic and international economic and political developments, including armed hostilities, the threat of terrorism, including cyberattacks, diplomatic developments or other similar events that could adversely affect our business; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner or at all, including if the remediation at the Kent Hills 1 and 2 wind facilities is more costly or takes longer than expected; industry risk and competition; fluctuations in the value of foreign currencies; structural subordination of securities; counterparty credit risk; changes to our relationship with, or ownership of, TransAlta Renewables; changes in the payment or receipt of future dividends, including from 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; inadequacy or unavailability of insurance coverage; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Company; 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, 2021 which form part of this Form 40-F.
Readers are urged to consider these factors carefully in evaluating the forward-looking statements, which reflect the Company's expectations only as of the date hereof, and are cautioned not to place undue reliance on them. 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
13.1TransAlta Corporation Annual Information Form for the year ended Dec. 31, 2021
13.2Management’s Discussion and Analysis for the year ended Dec. 31, 2021
13.3Consolidated Audited Annual Financial Statements for the year ended Dec. 31, 2021
13.4Management’s Annual Report on Internal Control over Financial Reporting, (included on page F2 of Exhibit 13.3 filed herewith).
23.1Consent of Independent Registered Public Accounting Firm
31.1Certification of President and Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1Certification of President and Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101Interactive Data File (formatted as Inline XBRL)
104Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

 
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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: February 23, 2022 

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transaltalogo_cmykxpowerina.jpg


TRANSALTA CORPORATION
ANNUAL INFORMATION FORM
FOR THE YEAR ENDED DECEMBER 31, 2021


February 23, 2022





Table of Contents




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, 2021. All dollar amounts are in Canadian dollars unless otherwise noted. Unless the context otherwise requires, all references to the "Company" 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 those 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; Clean Electricity Growth Plan and ability to achieve the target of 2 GW of incremental renewables capacity with an investment of $3 billion by 2025; the Company's future growth pipeline, including the timing of commercial operations and the costs of the advanced and early-stage projects; the source of funding for the Clean Electricity Growth Plan; our transformation, growth, capital allocation and debt reduction strategies; growth opportunities from 2022 to 2030 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 White Rock East and White Rock West Wind Power Projects ("White Rock Wind Projects"), including the total construction costs, ability to secure tax equity financing, and the timing of commercial operation; the Garden Plain wind project, including construction capital; the Northern Goldfields Solar Project, including the total construction capital; the proportion of EBITDA to be generated from renewable sources by the end of 2025; the suspension of the Sundance 5 repowering project; expected average annual EBITDA of the North Carolina Solar (as defined below) portfolio; the incident at Kent Hills 1 and 2 wind facilities and the extent of any remediation, the timing and cost of such remediation, the ability to secure waivers in respect of the Kent Hills bonds for any potential event of default, and the impact such incident could have on the Company's revenues and contracts; expected increases to our cost per tonne of coal at Centralia; the expected impact and quantum of carbon compliance costs; the ability to realize future growth opportunities with BHP (as defined below); regulatory developments and their expected impact on the Company, including the Canadian federal climate plan and the implementation of the major aspects thereof (including increased carbon pricing and increased funding for clean technology); the ability of the Company to realize benefits from Canadian, US and Australian regulatory developments, including receiving funding for clean electricity projects; the potential increase in value of emission reduction credits; the cyclicality of the business, including as it relates to maintenance costs, production and loads; expectations regarding refinancing the debt maturing in 2022; and the Company continuing to maintain a strong financial position and significant liquidity.
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 Company, which includes the Company 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 ability to realize the full economic benefit from the capacity, energy and ancillary services from our Alberta hydro assets.
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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: the impact of COVID-19, including more restrictive directives of government and public health authorities; increased force majeure claims; 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 in respect of our growth projects; restricted access to capital and increased borrowing costs; changes in short-term and/or long-term electricity supply and demand; fluctuations in market prices, including lower merchant pricing in Alberta, Ontario and Mid-Columbia; reductions in production; increased costs; a higher rate of losses on our accounts receivables due to credit defaults; impairments and/or write-downs of assets; adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats; commodity risk management and energy trading risks, including the effectiveness of the Company’s risk management tools associated with hedging and trading procedures to protect against significant losses; changes in demand for electricity and capacity and our ability to contract our electricity 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; operational risks involving our facilities, including unplanned outages; disruptions in the transmission and distribution of electricity; the effects of weather, including man made or natural disasters and other climate-change related risks; unexpected increases in cost structure; reductions to our generating units’ relative efficiency or capacity factors; disruptions in the source of fuels, including natural gas and coal, as well as the extent of water, solar or wind resources required to operate our facilities; general economic risks, including deterioration of equity markets, increasing interest rates or rising inflation; failure to meet financial expectations; general domestic and international economic and political developments, including armed hostilities, the threat of terrorism, cyberattacks, diplomatic developments or other similar events; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner or at all, including if the remediation at the Kent Hills wind facilities is more costly than expected; the holders of the KH Bonds (as defined below) declaring the principal and interest on the KH Bonds and all other amounts, together with any make-whole amount due thereunder, to be immediately due and payable; industry risk and competition; fluctuations in the value of foreign currencies; structural subordination of securities; counterparty credit risk; changes to our relationship with, or ownership of, TransAlta Renewables; changes in the payment or receipt of future dividends, including from TransAlta Renewables; risks associated with development projects and acquisitions, including capital costs, permitting, engineering risks, and delays in the construction or commissioning of projects; inadequacy or unavailability of insurance coverage; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Company; reliance on key personnel; and labour relations matters. 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, 2021.
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 Company'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, 2021, 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 a 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 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 the "Capital and Loan Structure - Exchangeable Securities" section of this AIF.
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, 2021, TransAlta Corporation owned, directly or indirectly, 60.1 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 60.1 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 39.9 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 110 years of operating experience. We own, operate and manage a highly contracted and geographically diversified portfolio of assets utilizing a broad range of fuels that include water, wind, solar, natural gas, energy storage and coal. We are undertaking a multi-year transition to convert or retire all of our coal units completely by the end of 2025. This transition is complete in Alberta where we discontinued all generation with coal and all coal mining operations on Dec. 31, 2021. Our Centralia coal-fired facility in Washington State is committed to be retired under the TransAlta Energy Transition Bill pursuant to which, 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 goal is to be a leader in customer-centred clean electricity, committed to a sustainable future, focused on increasing shareholder value by growing our portfolio of high quality generation facilities with stable and predictable cash flows. Our mission is to provide safe, low-cost and reliable clean electricity. With our 110-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 we can employ our competitive advantages.
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 7,387 megawatts ("MW") of gross installed capacity. We are focused on generating and marketing electricity in Canada, the United States ("US") and Western Australia through our diversified portfolio of facilities including hydro, wind, solar, energy storage, natural gas and 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 clean energy solutions that meet the needs of our customers and communities. We invest in a disciplined manner in projects that help our customers and our communities meet their Environment, Social and Governance ("ESG") objectives and that deliver returns to our shareholders. To support this strategy we maintain a growing pipeline of project opportunities focused on hydro, wind, solar and energy storage and low emissions gas generation.
On Sept. 28, 2021, TransAlta announced its strategic growth targets and accelerated Clean Electricity Growth Plan. The Company's enhanced focus on renewable generation and storage solutions for customers is driven largely by the growing demand for zero-emissions electricity to reach global decarbonization goals and the increase in demand for contracted renewables to help companies achieve their ESG ambitions.

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The following provides an overview of our Clean Electricity Growth Plan and strategic priorities to 2025:
1. Accelerate growth in customer-centred renewables and storage
We are growing our renewable capacity and plan to invest $3 billion to deliver 2 GW of incremental renewable capacity by the end of 2025. We are targeting this new capacity, once fully operational, to deliver incremental annual EBITDA of $250 million. We are also expanding our Company's development pipeline to 5 GW by 2025, which will enable us to deliver a two-fold increase in the Company's renewables fleet between 2025 and 2030.
2. Realize targeted approach to diversification
We are focused on growing our asset base in our core geographies of Australia, Canada, and the US so that we can realize targeted diversification and value creation. We expanded our renewables platform in the US and Canada in 2021 and continue to identify additional opportunities with customers on electricity offerings with a higher component of power coming from renewable sources in our 3 GW development pipeline.
3. Maintain financial strength and capital allocation discipline
Our strong cash flow results provide a large pool of funds to be allocated to our funding priorities. Higher operating cash flow at the Company, combined with the structural reduction in sustaining capital, frees up additional capital capacity to allocate to growth, dividends and share buybacks.
4. Define the next generation of power solutions and technologies
We intend to define the next generation of power solutions that will meet the needs of our economy and communities in the back-half of the decade and the decade to come.
5. Lead in ESG policy development
Given the ambitious climate goals in all of our geographies, we see it as being imperative that independent power producers ("IPPs"), like TransAlta, actively participate in policy development to ensure the zero-emissions electricity we provide contributes to emissions reduction, grid reliability and achieving competitive energy prices.
6. Successfully navigate through COVID-19 pandemic
We will continue to maintain an effective response to COVID-19 and plan a safe return to office.
Our ESG Leadership
Sustainability means ensuring that our financial returns consider short- and long-term economics, environmental and societal impacts as well as community needs. As we execute our strategy, our decisions are governed with a view to also delivering on our ESG objectives. We have a long history of adopting leading sustainability practices, including over 25 years of sustainability reporting and also 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 and the Task Force on Climate-related Financial Disclosures ("TCFD").
Our key sustainability pillars build on our corporate strategy and weave through our business. 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 ("ED&I"), we believe the focus will only strengthen our corporate strategy and support value creation into the future. Our sustainability pillars include:
•Clean, Reliable and Sustainable Electricity Production
•Safe, Healthy, Diverse, and Engaged Workplace
•Positive Indigenous, Stakeholder and Customer Relationships
•Progressive Environmental Stewardship
•Technology and Innovation
In 1990, we were the first Canadian company to purchase carbon offsets and in 2000 we were an early adopter of wind power generation. Since 2015, we have reduced our Green House Gas ("GHG") emissions by 61 per cent. In 2021, we reduced approximately 3.9 million tonnes of carbon dioxide equivalent ("CO2e") or 24 per cent over our 2020 levels. After ending coal generation in Canada in 2021, TransAlta will cease generation from our single remaining US coal unit by the end of 2025 further reducing emissions. Moreover, the Company aligns its ESG targets with the UN Sustainable Development Goals.
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The key components of our Company's approved ESG 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 2026 a company-wide reduction in GHG emissions of 75 per cent below 2015 levels;
•undertaking initiatives that will enhance the environmental performance of the Company, including converting coal facilities to natural gas and developing new renewable projects that support customer ESG 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 of Directors by 2030 and at least 40 per cent representation of women among all of our employees by 2030; and
•maintaining our commitment to leading ESG disclosures.

On Dec. 7, 2021, the Company received a B score from the CDP under updated criteria, exceeding the average C score in North America and the highest score achieved by thermal generating companies.
ESG factors are overseen by TransAlta's Governance, Safety and Sustainability Committee ("GSSC") of the Board of Directors. The GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environment, health and safety, and social well-being, including human rights, working conditions and responsible sourcing.
In 2021, we revised several corporate policies to help govern sustainability at TransAlta. Our Corporate Code of Conduct sets out expected behaviours of all our employees and our commitment to creating a work environment where all workers feel safe and are valued for the diversity they bring to our business. We also have adopted a Supplier Code of Conduct that defines the principles and standards expected of suppliers, their employees and contractors to meet while in the provision of goods and/or services to TransAlta.
Our Human Rights and Discrimination Policy communicates our commitment to human rights in our operations and supply chain to ensure that our personnel policies and practices in our global operations will respect fundamental rights. In Australia, our Modern Slavery Act statements demonstrate the actions we have taken to assess and address modern slavery risks within our operations and supply chain. Our Indigenous Relations Policy focuses on four key areas: community engagement and consultation; business development; community investment; and employment. We ensure that TransAlta’s principles for engagement are upheld and that the Company fulfills its commitments to Indigenous communities.
Our Whistleblower Policy provides a mechanism for our employees, officers, directors and contractors to report, amongst other things, any actual or suspected ethical or legal violations. We would seek to remedy the impact promptly in order to establish a corrective action plan in collaboration with the relevant individuals and stakeholders.
Our Total Safety Management Policy formalizes our commitment to protecting the public and our assets, as well as the physical, psychological and social well being of our people, and defines the personal responsibility of each employee and contractor working on TransAlta's behalf. Our commitment to equity, diversity and inclusion in our workplace and amongst our co-workers at all levels of the Company is set out in our Board and Workforce Diversity Policy and Diversity and Inclusion Pledge. We believe a strong focus on equity, diversity and inclusion will drive performance in innovation, improve service to our customers and positively impact the communities that we all live in.
Our Capital Allocation and Financing Strategy
Our goal is to remain disciplined with our capital investment program and ensure that we maintain a strong financial position and sufficient capital is available to execute on our strategy.
 Maintaining a strong financial position allows the Company's commercial team to contract the Company’s portfolio with a variety of counterparties on terms and prices that are favourable to the Company’s financial results and provides the Company with better access to capital markets through commodity and credit cycles. The Company has an investment-grade BBB (low) credit rating from DBRS, a corporate family rating of Ba1 from Moody's with a stable outlook, Standard and Poor ("S&P") Global Ratings that reaffirmed the Company’s Unsecured Debt rating and Issuer Rating of BB+ with a stable outlook. The Company has the ability to execute its Clean Electricity Growth Plan at these rating levels.
Our capital allocation strategy includes cash available to the Company's shareholders and considers maintenance capital, debt repayment, growth and dividend payments. The Company targets returning between 10 per cent and 15 per cent of TransAlta deconsolidated funds from operations to common shareholders.
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Our capital allocation and financing strategy 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
During the fourth quarter of 2021, the Company changed its segmented reporting disclosures to align with the Company’s Clean Electricity Growth Plan. The segment reporting changes reflect a corresponding change in how management and the Chief Executive Officer assess the performance of the Company.
The primary changes are the elimination of the Alberta Thermal and the Centralia segments; and the reorganization of the North American Gas and Australia Gas segments into a new "Gas" segment. The Alberta Thermal facilities that were converted to gas have been included in the redefined Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit are included in a new "Energy Transition" segment. The Skookumchuck dam was also moved from the Hydro segment to the Energy Transition segment due to its close proximity and use in the Centralia facility, see "Business of TransAlta – Energy Transition Business Segment." No changes were made to the Wind and Solar, Corporate or Energy Marketing segments. Prior years' metrics were restated to reflect the realignment of the operating segments.
The Hydro segment has a net ownership interest of approximately 925 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 1,879 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, North Carolina, Pennsylvania, Washington and Wyoming.
The Gas segment has a net ownership interest of approximately 2,775 MW of owned electrical-generating capacity and includes facilities located in Alberta, Ontario, Michigan and Western Australia. This includes a pipeline located in Western Australia.
The Energy Transition segment has a net ownership interest in approximately 1,472 MW of owned electrical-generating capacity. The segment includes the previously disclosed Centralia reportable segment, the Skookumchuck Hydro facility, Sundance Unit 4, retired thermal units and the mining operations previously recorded in the Alberta Thermal segment. This change aligns with the Company's long-term strategy and reflects the Clean Electricity Growth Plan.
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 several markets.
The Corporate segment supports each of the above segments and includes the Company's central finance, legal, administrative, business development and investor relations functions.
We regularly review our operations in order to optimize our generating assets and evaluate appropriate growth opportunities to maximize value to the Company. 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 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 AIF. 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.
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. The Company's majority ownership of TransAlta Renewables has supported the Company in implementing its overall strategy of developing, constructing or acquiring additional renewable assets. The Company's strategy has shifted to reduce merchant and gas exposure as announced at our September 2021 Investor Day. As such, TransAlta's and TransAlta Renewables' strategies for growth are becoming more aligned and may result in a overlap of growth objectives.
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TransAlta Renewables, or one or more of its wholly owned subsidiaries, directly owns certain of our wind, hydro, natural gas and energy storage facilities. TransAlta Renewables also owns economic interests in a number of our other facilities. The Company 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 the "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" section in this AIF.
TransAlta's Map of Operations
The following map outlines the Company's operations(1)(2) as of Dec. 31, 2021.
tacmapa.jpg
Notes:
(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.
(2) Facilities include Keephills Unit No. 1, which was retired from service effective Dec. 31, 2021, and Sundance Unit No.4, which is set to retire on April 1, 2022.
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General Development of the Business
Significant regulatory changes continue to have extensive impacts on the Company's business and strategy. Starting in 2015, the Government of Alberta and the Government of Canada announced a shared goal to reduce carbon emissions and phase out pollution from coal-generated electricity by 2030. TransAlta responded quickly to these announcements and set down the path to fully transform itself into a leading clean electricity company. Part of this strategy was to convert our remaining coal fleet in Canada to natural gas. This eliminated coal as a fuel source in our Canadian operating units at the end of 2021. In addition, we continue to expand our renewable generation fleet with our Clean Electricity Growth Plan. 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 in this AIF in the "Business of TransAlta" Section.
Three-Year History
Generation and Business Development
2021
TransAlta Achieves Full Phase-Out of Coal in Canada
On Dec. 29, 2021, the Company announced that it had completed the full conversion of Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 from thermal coal to natural gas. Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 will maintain the same generator nameplate capacity of 395 MW, 463 MW and 401 MW, respectively. These conversion to gas projects will reduce our CO2 emissions by more than half and complete our plan to generate 100 per cent clean electricity in Alberta by the end of 2021. As of Dec. 31, 2021, the Company is no longer generating with coal and has fully transitioned to natural gas in Canada.
White Rock Wind Projects and Corporate PPA
On Dec. 22, 2021, the Company executed two long-term power purchase agreements ("PPAs") with a new customer with an AA credit rating from S&P Global Ratings for 100 per cent in respect of its 300 MW White Rock East and White Rock West wind projects located in Caddo County, Oklahoma. The White Rock wind projects will consist of a total of 51 Vestas turbines. Construction is expected to begin in late 2022 with a target commercial operation date in the second half of 2023. TransAlta will construct, operate and own the facilities. Total construction capital is estimated at approximately US$460 million to US$470 million and is expected to be financed with a combination of existing liquidity and tax equity financing. Over 90 per cent of the project costs are captured under executed fixed price turbine supply agreements and fixed price engineering, procurement, and construction agreements.
TransAlta Renewables Delivers Commercial Operation of Windrise
On Dec. 2, 2021, TransAlta Renewables announced that the 206 MW Windrise wind facility ("Windrise") achieved commercial operation on Nov. 10, 2021. The Windrise facility is located approximately 20 km southwest of Fort Macleod on approximately 11,000 acres of privately owned land. The Windrise wind facility is TransAlta Renewables’ largest wind farm to-date and has a 20-year offtake agreement with the Alberta Electric System Operator ("AESO").
North Carolina Solar Acquisition
On Nov. 5, 2021, the Company closed the acquisition of a 122 MW portfolio of 20 solar photovoltaic sites located in North Carolina (collectively, "North Carolina Solar"). The assets were acquired from a fund managed by Copenhagen Infrastructure Partners for approximately US$99 million (including working capital adjustments) and the assumption of existing tax equity obligations. The acquisition was funded using existing liquidity.
At the closing of the acquisition, TransAlta Renewables acquired a 100 per cent economic interest in North Carolina Solar from a wholly owned subsidiary of TransAlta through a tracking share structure for aggregate consideration of approximately US$102 million.
The facilities are all operational and were commissioned between November 2019 and May 2021. The facilities are secured by long-term PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity, and environmental attributes from each site.
Retirement of Sundance Unit 4 and Keephills Unit 1 and Suspension of Sundance Unit 5
On Sept. 28, 2021, the Company announced its decision to suspend the Sundance Unit 5 repowering project and retire Keephills Unit 1 on Dec. 31, 2021 and Sundance Unit 4 on April 1, 2022.

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Kent Hills Wind Facilities Outage
On Sept. 27, 2021, the Company's subsidiary, Kent Hills Wind LP, experienced a single tower failure at its 167 MW Kent Hills wind facilities in Kent Hills, New Brunswick. The failure involved a collapsed tower located within the Kent Hills 2 site. There were no injuries as a result of the collapse. No one was in the area when the incident occurred and there are no homes in the immediate vicinity. The Company's emergency response team secured the area to ensure safety.
The facilities consist of 50 turbines at Kent Hills 1 and 2 wind facilities and five turbines at Kent Hills 3. Following extensive independent engineering assessments and root cause failure analysis, the Company announced on Jan. 11, 2022, that all 50 turbine foundations at the Kent Hills 1 and 2 wind facilities will require a full foundation replacement. The root cause failure analysis indicates that deficiencies in the original design of the foundations have caused crack propagation within the foundations and that the foundations must be replaced. The Company is in the process of planning the rehabilitation of the wind sites and currently expects the wind facility foundations to be fully replaced by the end of 2023. Based on the recommendations of independent engineers, and in order to maintain the safety of the affected sites and turbines, the wind turbines will cease to operate until their associated foundations are replaced.
Foundation replacements will require expenditures of approximately $75 million to $100 million, in aggregate. The remediation plan is expected to begin to be implemented in 2022. The outage is expected to result in foregone revenue of approximately $3.4 million per month on an annualized basis so long as all 50 turbines are offline, based on average historical wind production, with revenue expected to be earned as the wind turbines are returned to service.
TransAlta and New Brunswick Power Corporation continue discussions to enable the safe return to service of the facilities.
The foundation issues at the Kent Hills 1 and 2 wind facilities are unique to the design of those sites and there is no indication of any foundation issue at the Kent Hills 3 wind facility or any other wind facility in the fleet. The Company is maintaining communication with all key stakeholders and keeping them fully apprised of the situation. The Company is actively evaluating any options that may be available to recover these costs from third parties and insurance providers.
As a result of the determination that all 50 foundations require replacement, as well as certain resulting amendments to applicable insurance policies, the Company's operating subsidiary, Kent Hills Wind LP, has provided notice to BNY Trust Company of Canada, as trustee (the “KH Trustee”) for the approximately $221 million outstanding non-recourse project bonds (the “KH Bonds”) secured by, among other things, the Kent Hills wind facilities, that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Upon the occurrence of any event of default, holders of more than 50 per cent of the outstanding principal amount of the KH Bonds have the right to direct the KH Trustee to declare the principal and interest on the KH Bonds and all other amounts due thereunder, together with any make-whole amount, to be immediately due and payable and to direct the KH Trustee to exercise rights against certain collateral. The Company is in discussions with the KH Trustee and holders of the KH Bonds to negotiate required waivers and amendments while the Company works to remedy the matters described in the notice. Although the Company expects that it will reach agreement with the KH Trustee and holders of the KH Bonds with respect to terms of an acceptable waiver and amendment, there can be no assurance that the Company will receive such waivers and amendments.
Northern Goldfields Solar Project
On July 29, 2021, TransAlta Renewables announced that Southern Cross Energy ("SCE"), a subsidiary of the Company and an entity in which TransAlta Renewables owns an indirect economic interest, had reached an agreement to provide BHP Billiton Nickel West Pty Ltd. ("BHP") with renewable electricity to its Goldfields-based operations through the construction of the Northern Goldfields Solar Project. The project includes the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm, 10 MW/5MWh Leinster battery energy storage system and interconnecting transmission infrastructure, all of which will be integrated into our existing 169 MW SCE North remote network in Western Australia. Construction activities started in the first quarter of 2022 with completion of the projects expected in the second half of 2022. The total construction capital of the project is estimated at approximately AU$69 million to AU$73 million.
Keephills Unit 2 Conversion to Gas
On July 19, 2021, the Company announced the completion of the conversion of Keephills Unit 2 from coal to natural gas. Keephills Unit 2 maintains the same generator nameplate capacity of 395 MW while reducing the CO2 emissions by more than half, from approximately 1.04 tonnes of CO2e per MWh to approximately 0.51 tonnes of CO2e per MWh.
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Sale of the Pioneer Pipeline
On June 30, 2021, the Company closed the previously announced sale of the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. ("ATCO") for the aggregate sale price of $255 million. The net cash proceeds to TransAlta from the sale of its 50 per cent interest was approximately $128 million. Pioneer Pipeline has been integrated into NOVA Gas Transmission Ltd. ("NGTL") and ATCO's Alberta natural gas transmission systems to provide reliable natural gas supply to the Company's power generation stations at Sundance and Keephills. As part of the transaction, TransAlta entered into additional long-term gas transportation agreements with NGTL for new and existing transportation service of 400 TJ per day by the end of 2023.
TransAlta Completes Sarnia Cogeneration Facility Contract Extension
On May 12, 2021, the Company executed an Amended and Restated Energy Supply Agreement with one of its large industrial customers at the Sarnia cogeneration facility, which provides for the supply of electricity and steam. This agreement will extend the term of the original agreement from Dec. 31, 2022, to Dec. 31, 2032. The agreement provides that if the Company is unable to enter into a new contract with the Ontario Independent Electricity System Operator ("IESO") or enter into agreements with its other industrial customers at the Sarnia cogeneration facility that extend past Dec. 31, 2025, then the Company has the option to provide notice of termination in 2022 that would terminate the Amended and Restated Energy Supply Agreement four years following such notice. The Company is in active discussions with the three other existing industrial customers regarding extensions to their supply of electricity and steam from the Sarnia cogeneration facility on comparable terms. The current contract with the IESO in respect of the Sarnia cogeneration facility expires on Dec. 31, 2025. On July 19, 2021, the IESO released its Annual Acquisition Report which included draft details for mid- and long-term procurement mechanisms for capacity for 2026 and beyond for existing and new generation. The medium term procurement process is scheduled to commence in 2022. The Company plans to bid into the process, seeking to secure a contract extension for the Sarnia cogeneration facility following the end of the current contract.
Garden Plain Wind Project
On May 3, 2021, the Company announced that it entered into a long-term PPA with Pembina Pipeline Corporation ("Pembina") pursuant to which Pembina has contracted for the renewable electricity and environmental attributes for 100 MW of the 130 MW Garden Plain wind project. Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project (49 per cent of the 100 MW under the PPA). The option must be exercised no later than 30 days after the commercial operational date. TransAlta would remain the operator of the facility and earn a management fee if Pembina exercises this option. The Garden Plain wind project will be located approximately 30 km north of Hanna, Alberta. Construction activities started in the fall of 2021 with completion of the project expected in the second half of 2022. Total construction capital of the project is estimated at approximately $195 million.
TransAlta Renewables Acquisitions
On Feb. 26, 2021, the Company completed the sale of its 100 per cent direct interest in the 206 MW Windrise wind facility to TransAlta Renewables for $213 million. The remaining construction costs for Windrise were paid by TransAlta Renewables. The Windrise wind facility achieved commercial operation on Nov. 10, 2021.
On April 1, 2021, the Company completed the sale of its 100 per cent economic interest in the 29 MW Ada cogeneration facility ("Ada") and its 49 per cent economic interest in the 137 MW Skookumchuck wind facility ("Skookumchuck") to TransAlta Renewables for $43 million and $103 million, respectively. Both facilities are fully operational. Pursuant to the transaction, a TransAlta subsidiary owns Ada and Skookumchuck directly and has issued to TransAlta Renewables tracking preferred shares reflecting its economic interest in the facilities. The Ada cogeneration facility is under a PPA until 2026. The Skookumchuck wind facility is contracted under a PPA until 2040 with an investment grade counterparty.
TransAlta Completes First Off-Coal Conversion and Achieves Major Milestone in Phase-Out of Coal
On Feb. 1, 2021, the Company 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 coal to natural gas allows the unit to reduce its CO2 emissions by half from approximately 1.05 tonnes of CO2e per MWh to approximately 0.52 tonnes of CO2e per MWh.
2020
TransAlta's Alberta Power Purchase Arrangements Expire
On Dec. 31, 2020, the Alberta Power Purchase Arrangements ("Alberta PPAs") 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.
Centralia Unit 1 and 2 Retirement
Effective Dec. 31, 2020 Centralia Unit 1 was retired from service. The Centralia Unit 2 is set to shut down at the end of 2025.
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TransAlta Sells 303 MW Portfolio Including 274 MW of Wind to TransAlta Renewables
On Dec. 23, 2020, the Company and TransAlta Renewables entered into definitive agreements for the acquisition of three assets consisting of: (a) a 100 per cent direct interest in the 206 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 included the remaining construction costs for the Windrise wind project. TransAlta Renewables funded the cash consideration and remaining construction costs with the proceeds from the South Hedland financing.
TransAlta Acquired 30 per cent Equity Interest in EMG International LLC ("EMG")
On Nov. 30, 2020, the Company acquired a 30 per cent equity investment in EMG. The Company 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 Company's existing customer service offerings.
Skookumchuck Wind Project Equity Investment
On Nov. 25, 2020, the Company closed its 49 per cent equity investment in the Skookumchuck wind project with the Southern Power 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 PPA with Puget Sound Energy. The economic interest in this facility was sold to TransAlta Renewables on April 1, 2021.
BHP 15-Year Contract Extension
On Oct. 22, 2020, SCE, a subsidiary of the Company, replaced and extended its current PPA with 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 SCE 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 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 BHP are underway, including wind generation and lower emission firming generation to support BHP's future power requirements.
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 that uses Tesla Megapack technology. TransAlta partnered with Emissions Reduction Alberta in order to receive co-funding of approximately 50 per cent of the $14 million construction cost. The 10 MW / 20 MWh battery storage facility was acquired by TransAlta Renewables from the Company on Aug. 1, 2020. The Company also executed a 20-year battery storage usage contract with TransAlta Renewables in which the Company 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 spot market and ancillary services market of the AESO.
Retirement of Sundance 3 Coal-Fired Thermal Facility
On July 22, 2020, the Company 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.
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 in Michigan which is contracted under a long-term PPA and steam sale agreement for approximately six years with Consumers Energy and Amway. The economic interest in this facility was sold to TransAlta Renewables in the first half of 2021.
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2019
TransAlta Renewables 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 S&P 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 used to fund the construction.
2019 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 was 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") connected to their Three Creeks project. These turbines were intended to be redeployed to our Sundance 5 site as part of the repowering of Sundance Unit 5. However, the Sundance Unit 5 repowering project was suspended on Sept. 28, 2021. 
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.
ET Canada purported to terminate the agreements related to the development and construction of the K3 cogeneration project. As a result, during the first quarter of 2021, the Company recorded an impairment of $27 million in the Corporate segment as this facility was not yet operational. The recoverable amount was based on estimated fair value less costs of disposal of reselling the equipment purchased to date. TransAlta has commenced an arbitration seeking compensation for ET Canada's wrongful termination of the agreements. ET Canada seeks a declaration that the agreements were lawfully terminated.
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.
Strategic Investment by Brookfield
On March 25, 2019, the Company entered into an agreement dated March 22, 2019, with Brookfield (the "Investment Agreement"). Under the Investment Agreement, Brookfield agreed to invest $750 million in the Company through the purchase of exchangeable securities, which are exchangeable by Brookfield into an equity ownership interest in certain of TransAlta’s Alberta hydro assets ("Hydro Assets") in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted 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 and second tranche were used to accelerate our conversion to gas program. In addition, the proceeds from the second tranche of the financing were used to fund other growth initiatives and for general corporate purposes.
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Under the terms of an Investment Agreement, Brookfield 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. At Dec. 31, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,425,696 common shares, representing approximately 13.1 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.
In accordance with the terms of the Investment Agreement, TransAlta 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 Company has committed to pay Brookfield an annual fee of $1.5 million for six years beginning May 1, 2019.
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 Company's assessment of market prices and market conditions. Subsequently, on July 31, 2020, we retired Sundance Unit 3 and on Sept. 28, 2021, we suspended the repowering of Sundance Unit 5.
Corporate
2021
TransAlta Renewables Closes $173 Million Green Bond
On Dec. 6, 2021, On Dec. 6, 2021, TransAlta Renewables' indirect wholly owned subsidiary, Windrise Wind LP, secured a green bond financing by way of private placement for $173 million. The bonds are amortizing, bear interest from their date of issue at a rate of 3.41 per cent per annum and mature on Sept. 30, 2041. The bonds are aligned with the four components of the 2021 International Capital Market Association Green Bond Principles.
Windrise Wind LP used proceeds of the bonds, among other things, to repay all amounts owing pursuant to an intercompany construction loan agreement entered into in connection with the Windrise facility, make advances to TransAlta Renewables on a subordinated basis pursuant to an intercompany loan agreement, finance or refinance eligible green projects, including renewable energy facilities and to fund a construction reserve account.
Announced Common Share Dividend Increase
On Sept. 28, 2021, the Company announced that the Board approved an 11 per cent increase to its common share dividend and declared a dividend of $0.05 per common share paid on Jan. 1, 2022, to shareholders of record at the close of business on Dec. 1, 2021. The quarterly dividend of $0.05 per common share represents an annualized dividend of $0.20 per common share.
2021 Clean Electricity Growth Plan
On Sept. 28, 2021, the Company held our 2021 Investor Day and announced our Clean Electricity Growth Plan. The Company has established targets to deliver 2 GW of incremental renewables capacity with a targeted investment of $3 billion by 2025. TransAlta will accelerate its growth with a focus on customer-centred renewables and storage through the execution of its 3 GW development pipeline.
TransAlta Renewables is named on the Best 50 Corporate Citizens List
On July 6, 2021, the Company announced that TransAlta Renewables was recognized by Corporate Knights as one of the Best 50 Corporate Citizens for 2021. The Best 50 Corporate Citizens list evaluates and ranks Canadian corporations against a set of 24 key performance indicators covering ESG indicators relative to their industry peers and using publicly available information. The Company is committed to continuous improvement on key ESG issues and ensuring its economic value creation is balanced with a value proposition for the environment and its communities.
Equity, Diversity and Inclusion Program
On May 3, 2021, TransAlta announced that it had received certification from a third party that specializes in measuring and tracking ED&I metrics for the Company's continued commitment to and meaningful performance on ED&I in the workplace. The Company developed a five year ED&I strategy that was approved by the Board in August 2021, and executed the first year of that ED&I strategy.
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Normal Course Issuer Bid
On May 25, 2021, the TSX accepted the notice filed by the Company to implement a normal course issuer bid ("NCIB") for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. 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 TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021, and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares were repurchased under the current or previous NCIB in 2021.
Favourable Resolution of Disputes
The Company had been engaged in a dispute with Fortescue Metals Group ("FMG") as a result of FMG's purported termination of the South Hedland PPA. On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.
On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice naming the Company, the members of the Board of Directors on such date, and Brookfield as defendants. Mangrove was seeking to set aside the 2019 Brookfield investment. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021.
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 claimed force majeure under the PPA. ENMAX Energy Corporation, the purchaser under the PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.
Sustainability-Linked Loan
In March 2021, TransAlta extended its $1.25 billion syndicated credit facility to June 30, 2025, and converted the facility into a Sustainability-Linked Loan (“SLL”). The facility's financing terms align the cost of borrowing to TransAlta's GHG emission reductions and gender diversity targets, which are part of the Company's overall ESG strategy. The SLL will have a cumulative pricing adjustment to the borrowing costs on the facilities and a corresponding adjustment to the standby fee (the "Sustainability Adjustment"). Depending on performance against interim targets that have been set for each year of the credit facility term, the Sustainability Adjustment is structured as a two-way mechanism and could move either up, down or remain unchanged for each sustainability performance target based on performance. The SLL further underscores TransAlta's dedication to sustainability, including ED&I and emissions reduction.
Management and Board of Directors Changes
On March 31, 2021, Dawn Farrell retired from the Board and as President and Chief Executive Officer of the Company. John Kousinioris succeeded Mrs. Farrell as President and Chief Executive Officer and joined the Board on April 1, 2021. Prior to his appointment as Chief Executive Officer of TransAlta, Mr. Kousinioris held the roles of Chief Operating Officer, Chief Growth Officer and Chief Legal and Compliance Officer and Corporate Secretary with the Company. On April 30, 2021, Brett Gellner, our Chief Development Officer, retired after almost 13 years with TransAlta. Mr. Gellner continues to serve on the Board of Directors of TransAlta Renewables as a non-independent director.
On May 4, 2021, the Company announced the election of four new directors: Ms. Laura W. Folse, Ms. Sarah Slusser, Mr. Thomas O'Flynn and Mr. Jim Reid, who each bring diverse expertise and new perspectives to the Board. Mrs. Georgia Nelson, Mr. Richard Legault and Mr. Yakout Mansour did not stand for re-election and retired from the Board immediately following the annual shareholder meeting on May 4, 2021.
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2020
Declaration of a 6% Common Share Dividend Increase
On Dec. 23, 2020, the Company announced a six 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.
Redemption of Medium-Term Notes
On Nov. 25, 2020, the Company 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 Company announced that the Board adopted a Diversity and Inclusion Pledge that commits the Company to advancing diversity and inclusion in the workplace. By committing to this pledge, the Company 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 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 Company’s programs and initiatives.
TEC Hedland Pty Ltd. ("TEC") Secures AU$800 Million Financing
On Oct. 22, 2020, TEC, a subsidiary of the Company, closed an AU$800-million senior secured note offering ("TEC Notes"), by way of a private placement, which is secured by, among other things, a first-ranking charge over all assets of TEC. The TEC Notes bear 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 Notes have a rating of BBB by Kroll Bond Rating Agency.
TransAlta Renewables has received $480 million (AU$515 million) of the proceeds from the offering of the TEC Notes through the redemption of certain intercompany structures. An additional AU$200 million was 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 offering of the TEC Notes 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 Company continues to operate under its business continuity plan, which is focused on ensuring that: (i) employees who can work remotely do so; and (ii) employees who operate and maintain our facilities, and who are not able to work remotely, are able to work safely and in a manner that ensures their health and safety. TransAlta has adopted local public health authority and government guidelines in all jurisdictions in which we operate to promote the health and safety of all employees and contractors with our health and safety protocols. All of TransAlta's offices and sites follow health screening and social distancing protocols, including personal protective equipment. Employees can be exempted from rapid testing if they are able to provide proof of vaccination. Further, TransAlta maintains travel limitations that are aligned to local jurisdictional guidance, enhanced cleaning procedures, revised work schedules, contingent work teams and the reorganization of processes and procedures to minimize any workplace transmission of the virus.
Notwithstanding the challenges associated with the pandemic, all of our facilities continue to remain fully operational and are capable of meeting our customers' needs, with the exceptions of the Kent Hills 1 and 2 wind facilities, which as described above, is not related to the pandemic. The Company 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 as a result of COVID-19. 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.
The Company continues to maintain a strong financial position due in part to its long-term contracts and hedged positions and its financial liquidity.
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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 would 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 that we had been seeking to recover, $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 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 Company and was responsible for providing leadership and direction over TransAlta’s financial activities, corporate accounting and reporting, tax, and corporate planning.
Strategic Investment by Brookfield
On March 22, 2019, the Company entered into an Investment Agreement whereby Brookfield agreed to invest $750 million in the Company 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. See "General Development of the Business – Three-Year History – Generation and Business Development – 2019 – Strategic Investment by Brookfield Renewable Partners" section of this AIF.

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Business of TransAlta
Our Hydro, Wind and Solar, Gas and Energy Transition business segments are responsible for operating and maintaining our electrical generation facilities in Canada, Australia, and the US. Our Energy Marketing segment is responsible for marketing and scheduling our merchant asset fleet outside of Alberta along with procurement of gas, transport and storage to our gas fleet, providing intellectual knowledge to support our growth team, and generating a stand-alone gross margin separate from our asset business through a leading North American energy marketing platform. All the segments are supported by a Corporate segment.
As the Company continues its transformation into a leading clean electricity company, it is expected that the proportion of revenue attributable to the Energy Transition business unit will decline relative to the other business units. In addition, the Company 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, 2021:
2021 Revenues(1)
2020 Revenues(1)
Hydro
14%7%
Wind and Solar
11%16%
Gas
41%37%
Energy Transition
26%34%
Energy Marketing
8%6%
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 see the audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see the "Documents Incorporated by Reference" section of 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 925 net MW. The facilities are located in British Columbia, Alberta and Ontario.
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, 2021:
Facility NameProvince/ State
Nameplate Capacity (MW)(1)
Consolidated Interest
Gross Installed Capacity(1)
 Ownership
Net Capacity Ownership Interest (MW)(1)
Commercial Operation DateRevenue Source
Contract Expiry Date(2)
Alberta - Bow River System
Barrier(3)
AB13100%13100%131947Merchant‑
Bearspaw(3)
AB17100%17100%171954Merchant‑
Cascade(3)
AB36100%36100%361942, 1957Merchant‑
Ghost(3)
AB54100%54100%541929, 1954Merchant‑
Horseshoe(3)
AB14100%14100%141911Merchant‑
Interlakes(3)
AB5100%5100%51955Merchant‑
Kananaskis(3)
AB19100%19100%191913, 1951Merchant‑
PocaterraAB15100%15100%151955Merchant‑
Rundle(3)
AB50100%50100%501951, 1960Merchant‑
Spray(3)
AB112100%112100%1121951, 1960Merchant‑
Three Sisters(3)
AB3100%3100%31951Merchant‑
Alberta - Oldman River System
Belly River (4) (5)
AB3100%3100%31991Merchant‑
St. Mary (4) (5)
AB2100%2100%21992Merchant‑
Taylor (4) (5)
AB13100%13100%132000Merchant‑
Waterton (4) (5)
AB3100%3100%31992Merchant‑
Alberta - North Saskatchewan River System
Bighorn(3)
AB120100%120100%1201972Merchant‑
Brazeau(3)
AB355100%355100%3551965, 1967Merchant‑
BC Hydro Facilities
Akolkolex (4) (5)
BC10100%10100%101995BC Hydro2046
Pingston (4) (5)
BC4650%23100%232003, 2004BC Hydro2023
Bone Creek (4) (5)
BC19100%19100%192011BC Hydro2031
Upper Mamquam(4) (5)
BC25100%25100%252005BC Hydro2025
Ontario Hydro Facilities
Appleton (4)
ON1100%1100%11994IESO2030
Galetta (4) (6)
ON2100%2100%21998IESO2030
Misema (4)
ON3100%3100%32003IESO2027
Moose Rapids (4)
ON1100%1100%11997IESO2030
Ragged Chute (4)
ON7100%7100%71991IESO2029
Total Hydroelectric Capacity 948925925
Notes:
(1) MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated after consolidation of underlying assets. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables . As at Dec. 31, 2021, 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 the "General Development of the Business - Three-Year History - 2019 - Strategic Investment by Brookfield Renewable Partners" section of this AIF. The Alberta PPAs 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) Galetta was originally built in 1907, but was retrofitted in 1998.
Bow River System
Barrier
Barrier is a hydroelectric facility with installed capacity of 13 MW located on the Kananaskis River near Seebe, Alberta. It has been operating since 1947. 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 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.
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Cascade
Cascade is a hydroelectric facility with installed capacity of 36 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 near 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 near 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.
Three Sisters
Three Sisters is a hydroelectric facility with installed capacity of 3 MW located at the base of the Three Sisters Dam near 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.
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 ("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.
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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 near 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 near 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. The output from the facility is sold to British Columbia Hydro and Power Authority ("BC Hydro") under a PPA that terminates in 2046.
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 sold to BC Hydro under a PPA that terminates in 2031.
Pingston
Pingston is a run-of-river hydroelectric facility with installed capacity of 46 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 a subsidiary of Brookfield. The output from the facility is sold to BC Hydro under a 20-year PPA that terminates 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 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.
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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.
Wind and Solar Business Segment
As at Dec 31, 2021, the Wind and Solar segment held interests in approximately 1,879 MW of net wind generating capacity. This capacity consists of 12 wind facilities in Western Canada, four in Ontario, two in Québec, three in New Brunswick and five in the US, more specifically in the states of Washington, Wyoming, Minnesota, Pennsylvania, and New Hampshire. The Company also holds a 10 MW utility-scale battery storage in Alberta and 143 MW of solar facilities in the states of Massachusetts and North Carolina.
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 dispatchable 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 comprises the 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, and ambient and environmental conditions 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. 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, 2021:
Facility NameProvince/ State
Nameplate Capacity (MW)(1)
Consolidated Interest
Gross Installed Capacity(1)
Ownership
Net Capacity Ownership Interest (MW)(1)
Commercial Operation DateRevenue Source
Contract Expiry Date(2)
Alberta Wind Facilities
Ardenville (4) (5)
AB69100%69100%692010Merchant‑
Blue Trail and
Macleod Flats (4) (5)
AB69100%69100%692009 and 2004Merchant‑
Castle River (4) (5) (6)
AB44100%44100%441997‑2001Merchant-
Cowley North (4) (5)
AB20100%20100%202001Merchant‑
McBride Lake (4) (5)
AB7550%38100%382004ENMAX2024
Oldman(4)(5)
AB4100%4100%42007Merchant-
Sinnott (4) (5)
AB7100%7100%72001Merchant‑
Soderglen (4) (5)
AB7150%36100%362006Merchant‑
Summerview 1 (4) (5)
AB68100%68100%682004Merchant‑
Summerview 2 (4) (5)
AB66100%66100%662010Merchant‑
Windrise(4)
AB206100%206100%2062021AESO2041
Alberta Battery Energy Storage
WindCharger (4)
AB10100%10100%102020Merchant‑
Eastern Canada Wind Facilities
Kent Breeze (4)
ON20100%20100%202011IESO2031
Kent Hills 1(4)
NB96100%9683%802008NB Power2035
Kent Hills 2 (4)
NB54100%5483%452010NB Power2035
Kent Hills 3 (4)
NB17100%1783%142018NB Power2035
Le Nordais (4) (5) (7)
QC98100%98100%981999Hydro-Québec2033
Melancthon I (4)
ON68100%68100%682006IESO2026
Melancthon II (4)
ON132100%132100%1322008IESO2028
New Richmond (4) (5)
QC68100%68100%682013Hydro-Québec2033
Wolfe Island (4)
ON198100%198100%1982009IESO2029
US Wind and Solar Facilities
Antrim (3)
NH29100%29100%292019Partners HealthCare and New Hampshire Electric2039
Big Level (3)
PA90100%90100%902019Microsoft2034
Lakeswind (3)
MN50100%50100%502014LTC2034
Mass Solar (3)(7)
MA21100%21100%212012-2015LTC2032-2045
North Carolina Solar(3)(7)
NC122100%122100%1222019-2021Duke Energy2033
Skookumchuck Wind (3)
WA13749%67100%672020Puget Sound Energy2040
Wyoming Wind (3)
WY140100%140100%1402003LTC2028
Total Wind and Solar Capacity (8)
2,0491,9071,879
Notes:
(1) MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated after consolidation of underlying assets. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables. As at Dec. 31, 2021, 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) 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 multiple facilities.
(8) Excludes White Rock East and White Rock West Wind Projects, Garden Plain Wind and Northern Goldfields Solar, which are wind and solar projects, respectively, and are currently under construction.
All of the electricity generated and sold by our wind generating facilities within Alberta and Quebec, excluding Windrise, 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 14 kilometres south of Fort Macleod, Alberta. 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 TIER until October 2023. 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 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 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 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 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.
Oldman
The Oldman facility is owned by TransAlta Renewables. The 3.6 MW Oldman facility is located east of the Oldman River Dam, near Pincher Creek in southern Alberta. The Oldman facility has been in operation since March 2007. Interconnection of the facility is through the Fortis Alberta distribution grid. In 2021, TransAlta Renewables acquired 100 per cent of the project from a subsidiary of Boralex. This facility sells energy into the Alberta merchant market and 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 facility 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 50 per cent of the the generation from the facility pursuant to a Renewables PPA, and subsequently sell such generation in the Alberta spot market (which excludes that portion of generation that is owned by CNOOC Petroleum North America ULC).
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.
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Summerview 2
The Summerview 2 facility is owned by TransAlta Renewables. Summerview 2 is a 66 MW wind facility 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 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 Company executed a 20-year battery storage usage contract with TransAlta Renewables, whereby the Company pays a fixed-monthly capacity charge for the exclusive right to operate and dispatch the battery in the Alberta spot market.
Windrise
Windrise is a 206 MW wind facility situated on 11,000 acres of land located in the county of Willow Creek. The Windrise facility is the Company's largest wind farm to-date, and has a 20-year offtake agreement with the AESO. Commercial operation of the Windrise wind facility was achieved on Nov. 10, 2021. TransAlta Renewables acquired the Windrise facility on Feb. 26, 2021.
Garden Plain
The Garden Plain wind project is currently under construction and is located approximately 30 kilometres north of Hanna, Alberta. The facility will consist of 26 Siemens-Gamesa SGRE SG-145 turbines with a nameplate capacity of 130 MW and has a target commercial operation date ("COD") in the second half of 2022. Pembina and TransAlta have entered into an 18-year PPA for 100 MW, commencing on the COD of Garden Plain. Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project. TransAlta is currently marketing the remaining 30 MW of the facility to commercial and industrial electricity customers that are looking to reduce the carbon intensity of their operations. To the extent contracts for the remaining 30 MW are not secured, the excess energy will be offered into the Alberta spot market. See the "General Development of the Business — Three-Year History" section of this AIF.
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. On May 31, 2018, this facility was acquired by TransAlta Renewables.
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, consists of 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.
On Sept. 27, 2021, a single tower failure occurred at Kent Hills 2 resulting in extensive engineering and assessment of the Kent Hills 1 and 2 sites to determine the cause of the failure. Following the extensive independent engineering assessments and root cause failure analysis, it was determined that all 32 turbine foundations at the Kent Hills 1 site require a full foundation replacement. The root cause failure analysis indicated that deficiencies in the original design of the foundations have caused subsurface crack propagation within the foundations and that the foundations must be replaced. The Company is in the process of planning the rehabilitation of the wind sites and currently expects the foundations to be fully replaced by the end of 2023. Based on the recommendations of independent engineers, and in order to maintain the safety of the affected sites and turbines, the wind turbines will cease to operate until their associated foundations are replaced. See the "General Development of the Business – Three-Year History" section of this AIF.
Kent Hills 2
The Kent Hills 2 facility is owned by TransAlta Renewables. The 54 MW Kent Hills 2 wind facility expansion, in which TransAlta Renewables has an 83 per cent interest, consists of 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.
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It was determined, following the extensive independent engineering assessments and root cause failure analysis of the Kent Hills 1 and 2 facilities that all 18 turbine foundations at the Kent Hills 2 site require a full foundation replacement. Based on the recommendations of independent engineers, and in order to maintain the safety of the affected sites and turbines, the Kent Hills 2 wind turbines will cease to operate until their associated foundations are replaced. See the "General Development of the Business — Three-Year History" section of this AIF.
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. The foundation issues at the Kent Hills 1 and Kent Hills 2 sites are unique to the design of those sites and there is no indication of any foundation issue at Kent Hills 3.
Le Nordais
The Le Nordais facility is owned by TransAlta Renewables. The 98 MW Le Nordais wind facility is located at two locations: 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 it generates RECs for sale.
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 facility is a 29 MW wind facility located in Antrim, New Hampshire. The wind facility was constructed by the Company 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 Company that provides TransAlta Renewables with an economic interest in the wind facility. See the "General Developments of the Business – Three-Year History - Generation and Business Development" and "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" sections of this AIF.
Big Level
The Big Level facility is a 90 MW wind facility located in Potter County, Pennsylvania. The wind facility was constructed by the Company 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 from the Company that provides TransAlta Renewables with an economic interest in the wind facility. See the "General Developments of the Business – Three-Year History - Generation and Business Development" and "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" sections of this AIF.
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Lakeswind
The Lakeswind facility is a 50 MW wind facility 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 Company that provides TransAlta Renewables with an economic interest in the wind facility. . See the "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" section of this AIF.
Mass Solar
The Mass Solar facility is a 21 MW solar project consisting of multiple sites 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 generates solar RECs that expire in 2024. On May 31, 2018, TransAlta Renewables acquired tracking preferred shares from the Company that provide TransAlta Renewables with an economic interest in the solar facility. See the "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" section of this AIF.
North Carolina Solar
The North Carolina Solar facility is a 122 MW solar project consisting of 20 sites located in North Carolina. The solar facility was acquired in November 2021 from a fund managed by Copenhagen Infrastructure Partners. The facilities are all operational and were commissioned between November 2019 and May 2021. The facilities are secured by long-term PPAs with two subsidiaries of Duke Energy, which have an average remaining term of 12 years that are automatically extended unless terminated by either party. At the closing of the acquisition in November 2021, TransAlta Renewables acquired tracking preferred shares from the Company that provide TransAlta Renewables with an economic interest in the solar facility. See the "General Development of the Business – Three-Year History - Generation and Business Development" and "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" sections of this AIF.
Skookumchuck Wind
The Skookumchuck facility is a 137 MW wind facility 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 Company acquired a 49 per cent equity interest in the wind facility from its partner Southern Power Company, a subsidiary of Southern Company. TransAlta Renewables acquired the economic interest in Skookumchuck wind facility, which closed on April 1, 2021. See the "General Development of the Business – Three-Year History - Generation and Business Development" and "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" sections of this AIF.
Wyoming
The Wyoming facility is a 140 MW wind facility 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 Company that provides TransAlta Renewables with an economic interest in the wind facility.
White Rock East and White Rock West
On Dec. 22, 2021, TransAlta executed two long-term Power PPAs for the offtake of 100 per cent of the generation from its 300 MW White Rock East and White Rock West Wind power projects to be located in Caddo County, Oklahoma. The White Rock Wind Projects will consist of a total of 51 Vestas turbines with construction expected to begin in late 2022 and a target commercial operation date in the second half of 2023. TransAlta will construct, operate and own the facility. See the "General Development of the Business – Three-Year History - Generation and Business Development" and "Business of TransAlta – Non-Controlling Interests – TransAlta Renewables" sections of this AIF.
Australian Solar Facilities
Northern Goldfields Solar
The Company reached agreement to provide BHP with renewable electricity to its Goldfields-based operations through the construction of the Northern Goldfields Solar Project. The project consists of the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm, 10 MW/5MWh Leinster battery energy storage system and interconnecting transmission infrastructure, all of which will be integrated into our existing 169 MW SCE North remote network in Western Australia.
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Gas Business Segment
The following table summarizes our natural gas-fired generation facilities as at Dec. 31, 2021:
Facility NameProvince/ State
Nameplate Capacity (MW)(1)
Consolidated Interest
Gross Installed Capacity(1)
Ownership
Net Capacity Ownership Interest (MW)(1)
Commercial Operation DateRevenue Source
Contract Expiry Date(2)
Alberta Gas Facilities
Fort Saskatchewan(3)
AB11860%7150%351999Dow Chemical/Merchant2029
Keephills Unit No. 2(4)
AB395100%395100%3951984Merchant-
Keephills Unit No. 3(4)
AB463100%463100%4632011Merchant-
Poplar Creek(5)
AB230100%230100%2302001Suncor2030
Sheerness Unit No.1 (3)(4)
AB40050%20050%1001986Merchant-
Sheerness Unit No. 2 (3)(4)
AB40050%20050%1001990Merchant-
Sundance Unit No. 6(4)
AB401100%401100%4011980Merchant-
Total Alberta Gas Capacity2,4071,9601,724
Eastern Canada and US Gas Facilities
Ada(6)
MI29100%29100%291991Consumers Energy/ Amway2026
Ottawa(3)
ON74100%7450%371992LTC/Merchant2022-2033
Sarnia(7)
ON499100%499100%4992003LTCs2025-2032
Windsor(3)
ON72100%7250%361996IESO/Merchant2031
Total Eastern Canada and US Gas Capacity674674601
Australian Gas Facilities
Parkeston(6)(8)
WA(11)
11050%55100%551996Northern Star/Merchant2026
South Hedland(6)(9)
WA(11)
150100%150100%150
2017(9)
LTCs(9)
2042
SCE(6)(7)(10)
WA(11)
245100%245100%2451996BHP2038
Fortescue River Gas Pipeline(6)
WA(11)
N/A100%N/A43%N/A2015FMG2035
Total Australian Gas Capacity505450450
Total Gas Capacity3,5863,0842,775
Notes:
(1) MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated after consolidation of underlying assets. Net capacity ownership interest includes 100 per cent of the generating capacity owned by TransAlta Renewables . As at Dec. 31, 2021, 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) Our interests in these facilities are through our ownership interest in TransAlta Cogeneration LP ("TA Cogen").
(4) The Alberta PPA in respect of these assets expired on Dec. 31, 2020, and are now operated as merchant.
(5) The Poplar Creek facility is operated by Suncor Energy Inc. and ownership of the facility will transfer to Suncor in 2030.
(6) TransAlta Renewables owns an economic interest in the facility.
(7) Facility is owned by TransAlta Renewables.
(8) Plant contracted to October 2026 with early termination options beginning in 2021.
(9) The South Hedland facility is contracted with FMG and Horizon Power.
(10) Comprised of four facilities.
(11) These assets are based in Western Australia.

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Alberta Gas Facilities
Fort Saskatchewan
We have a net ownership interest of 30 per cent in the Fort Saskatchewan facility. See the "Business of TransAlta – Non-Controlling Interests" section of this AIF. 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 extended the long-term contract for the Fort Saskatchewan facility providing for the delivery of energy and steam to the customer, Dow Chemical. The contract extension 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.
Keephills 2
The Keephills 2 facility is located approximately 70 kilometres west of Edmonton, Alberta, and is wholly-owned by TransAlta. Keephills 2 facility is a gas-fired unit that completed its conversion to natural gas in the spring of 2021 and commercial operation was announced on July 19, 2021. Converting to natural gas from coal maintains the unit's current generation capacity and reduces its CO2 emissions by more than half from approximately 1.04 tonnes of CO2e per MWh to approximately 0.51 tonnes of CO2e per MWh in 2021, thereby adding an additional eight years of life under the federal gas-fired regulations. The end of regulatory life for this unit is set for 2037.
Keephills 3
The Keephills 3 facility is located approximately 70 kilometres west of Edmonton, Alberta, and is wholly owned by TransAlta. Keephills 3 facility is a gas-fired unit that completed its conversion to natural gas in the second half of 2021 and commercial operations was announced on Dec. 29, 2021. Converting to natural gas from coal maintains the current generation capacity of the unit and reduces its CO2 emissions by almost 50 per cent from approximately 0.86 tonnes of CO2e per MWh to approximately 0.43 tonnes of CO2e per MWh, thereby adding an additional 10 years of life under the federal gas-fired regulation. The end of regulatory life for this unit is set for 2039.
Poplar Creek
Our Poplar Creek cogeneration facility is located in Fort McMurray, Alberta. On Aug. 31, 2015, the Company 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 Company 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 Company's gas generators until Dec. 31, 2030. The ownership of the entire Poplar Creek cogeneration facility will transfer to Suncor in 2030.
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. On April 4, 2020, Sheerness Unit 2 was converted to natural gas. Also during 2020, Sheerness Unit 2's capacity was increased from 390 MW to 400 MW following a generator rewind and final testing. On March 31, 2021, Sheerness Unit 1 was converted to natural gas. The Sheerness facility received its last coal shipment in the first quarter of 2021, with the coal stock being fully depleted in July of 2021. On Nov. 9, 2021, Heartland announced that it had completed the transition off-coal at Sheerness. The end of regulatory life for these units is set for 2037.
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 spot market. See the "Business of TransAlta – Non-Controlling Interests" section of this AIF.
Sundance 6
The Sundance 6 facility is located approximately 70 kilometres west of Edmonton, Alberta, and is wholly owned by TransAlta. Sundance 6 was a coal-fired unit that completed its conversion to gas in the first half of 2021 and announced its commercial operation on Jan. 31, 2021. Converting to natural gas from coal reduces the unit's CO2 emissions by half from approximately 1.05 tonnes of CO2e per MWh to approximately 0.52 tonnes of CO2e per MWh, thereby adding an additional eight years of life under the federal gas-fired regulations. The end of regulatory life for this unit is set for 2037.
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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 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 Company 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.
Eastern Canada and US Gas Facilities
Ottawa
The Ottawa facility is owned by TA Cogen. See the "Business of TransAlta – Non-Controlling Interests" section of this AIF. It is a combined-cycle cogeneration facility designed to produce 74 MW of electrical energy. On Aug. 30, 2013, the Company announced the recontracting of the facility with the IESO for a 20-year term, effective January 2014. The Ottawa facility also provides thermal energy 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 has a term to Dec. 31, 2033, with an automatic renewal of five years unless terminated by either party.
Sarnia
The Sarnia cogeneration 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. The facility also provides electricity to the IESO under a contract that terminates Dec. 31, 2025.
On May 12, 2021, the Company executed an Amended and Restated Energy Supply Agreement with one of its large industrial customers at the Sarnia cogeneration facility that provides for the supply of electricity and steam. This Amended and Restated Energy Supply Agreement extends the term of the original agreement from Dec. 31, 2022 to Dec. 31, 2032. However, if TransAlta is unable to enter into a new contract with the IESO or enter into agreements with its other industrial customers at the Sarnia cogeneration facility that extend past Dec. 31, 2025, then the Company has the option to provide notice of termination in 2022 that would terminate the Amended and Restated Energy Supply Agreement four years following such notice. The Company is in active discussions with the three other existing industrial customers regarding extensions to their supply of electricity and steam from the Sarnia cogeneration facility on comparable terms. The current contract with the IESO expires on Dec. 31, 2025. On July 19, 2021, the IESO released its Annual Acquisition Report which included draft details for mid- and long-term procurement mechanisms for capacity for 2026 and beyond for existing and new generation. The Company is participating in the consultation process, seeking to secure a contract extension for the Sarnia cogeneration facility following the end of the current contract.
The Sarnia cogeneration 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 the "Business of TransAlta – Non-Controlling Interests" section of this AIF. It is a combined-cycle cogeneration facility designed to produce 72 MW of electrical energy. 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 November 2022, with six successive renewal terms of one year each. 
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 acquired the economic interest in the facility, which closed on April 1, 2021.
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Australian Gas 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 the economic interest based on the cash flows broadly equal to the underlying net distributable cash flow of TEA.
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 Northern Star Resources Limited, which interest was transferred from Newmont Australia Pty Ltd. to Northern Star Resources Limited on Dec. 1, 2021. The Parkeston facility primarily supplies energy to Kalgoorlie Consolidated Gold Mines pursuant to a supply contract that extends 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.
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 is contracted with two customers. Capacity of 110 MW is contracted to Horizon Power to 2042. Horizon Power is the state-owned electricity supplier in the region. The second customer is the port operations of FMG for 35 MW of capacity. The Company was engaged in a dispute with FMG as a result of FMG's purported termination of the PPA. On May 2, 2021, the Company entered into a settlement with FMG that resulted in FMG continuing as a customer of the South Hedland facility. See the "General Development of the Business – Three-Year History – Corporate" section of this AIF.
Southern Cross Energy
SCE consists of four natural gas and diesel-fired generation facilities with a combined capacity of 245 MW. On Oct. 22, 2020, SCE replaced and extended its PPA with BHP, which became effective Dec. 1, 2020, and replaced the previous contract that was scheduled to expire Dec. 31, 2023. The amendment to the PPA extended 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 PPA supports BHP's future power requirements and emission reduction targets. The amendments also provide BHP participation rights in integrating renewable electricity generation, including solar, wind, and energy storage technologies into BHP's mining operations located in the Goldfields region, subject to the satisfaction of certain conditions. New-build projects are already in progress under this contract and include the Northern Goldfields Solar and Battery Project in Mount Keith and Leinster. See the "General Development of the Business – Three Year History – Generation and Business Development " section of this AIF.
Evaluation of additional renewable energy supply and carbon emissions reduction initiatives under the extended PPA with BHP are underway.
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.

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Energy Transition Business Segment
The following table summarizes our energy transition facilities as at Dec. 31, 2021:
Facility NameProvince/ State
Nameplate Capacity (MW)(1)
Consolidated Interest
Gross Installed Capacity(1)
Ownership
Net Capacity Ownership Interest (MW)(1)
Commercial Operation DateRevenue SourceContract Expiry Date
US Facilities
Centralia Thermal No. 2 WA670100%670100%6701971LTC/Merchant2025
Skookumchuck (2)
WA1100%1100%11970PSE2025
Alberta Facilities
Sundance Unit No. 4 (3)
AB406100%406100%4061977Merchant-
Keephills Unit No. 1(4)
AB395100%395100%3951983Merchant-
Total Energy Transition Capacity 1,4721,4721,472
Notes:
(1) MW are rounded to the nearest whole number. The gross installed capacity reflects the basis of consolidation of underlying assets owned, whereas net capacity ownership interest deducts capacity attributable to non-controlling interest in these assets and is calculated after consolidation of underlying assets.
(2) This facility is used to provide a reliable water supply to Centralia Thermal.
(3) The Company discontinued firing with coal and will only operate on gas effective Jan. 1, 2022 and, as a result, the maximum capability of this unit has been reduced to 113 MW.
(4) Keephills Unit No. 1 was retired from service effective Dec. 31, 2021.

Centralia
The 1,340 MW coal-fired facility in Centralia, Washington, consists of two units, the Centralia Thermal Unit No. 1 retired on Dec. 31, 2020, reducing the net capacity from 1,340 MW to 670 MW. This retirement was undertaken 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. Pursuant to the Bill, 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 purchases 380 MW of base-load power to December 2024 and 300 MW in 2025.
On July 30, 2015, we announced that we will 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. Approved funding totals approximately US$45.8 million as at Dec. 31, 2021.
We sell electricity from the Centralia thermal facility into the Western Electricity Coordinating Council and, in particular, on the spot market in the US Pacific Northwest energy market. Our strategy is to balance contracted and non-contracted sales of electricity to manage production and price risk.
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.
Sundance 4
Effective Jan. 1, 2022, Sundance Unit 4 discontinued firing with coal and the unit will only operate on gas until it retires on April 1, 2022, resulting in the maximum capacity of the unit being reduced to 113 MW.
Reclamation Activities
Centralia Mine
The Company continues to own a coal mine adjacent to the Centralia facility. The Company stopped mining operations at our Centralia coal mine on Nov. 27, 2006. The mine is currently in the reclamation phase and we continue to perform reclamation and associated work. The coal used to fuel the Centralia facility is sourced from the Powder River Basin in Montana and Wyoming. The Centralia facility has coal contracts in place that expire at the end of 2025.
Under the US "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 2021. The total dollar value of all Mine Safety and Health Administration ("MSHA") assessments are not material.
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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
28 (1)
0000
4,896 (2)
0NoNo0
Notes:
(1) Section 104 Violations: TransAlta Centralia Mining (21) and Coalview Centralia LLC (7).
(2) Citations in Contest: Coalview Centralia LLC (104a - $125) (104g, l - $336).
Highvale Mine
We own the Highvale mine that supplied coal to the now gas-powered Sundance and Keephills facilities, and we continue to perform reclamation and associated work at the Highvale mine. Furthering the Clean Electricity Growth Plan, the Company discontinued all mining operations at Highvale mine at the end of 2021. The mine is currently in reclamation phase as of Jan. 1, 2022.
Whitewood Mine
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.
Coal Retirements
In aggregate, TransAlta in Alberta has retired 3,794 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to cleaner-burning natural gas. The below five units have been retired and are no longer in operation.
Keephills 1
On Jan. 1, 2022, we retired Keephills Unit 1. The retirement is consistent with our strategy to transition to clean electricity.
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 retirements remain consistent with our strategy to transition to clean electricity.
On July 31, 2020, the Company retired 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.
Sundance 5
On July 29, 2021, in accordance with applicable regulatory requirements, the Company gave notice to the AESO of its intention to retire the mothballed coal-fired Sundance Unit 5 effective Nov. 1, 2021, and to terminate the associated transmission service agreement. In addition, the Company suspended the Sundance Unit 5 repowering project due to escalating costs, changing supply and demand dynamics and forecasted power prices in the Alberta market, as well as risks associated with carbon pricing and the evolving regulatory environment. With the suspension of the project, the Company will redeploy the capital previously allocated to the Sundance Unit 5 repowering project to renewable growth projects.
Energy Marketing Segment
Our Energy Marketing segment provides a number of strategic functions, including the following:
a.gathering and analyzing market trends to enable more effective strategic planning and decision making;
b.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;
c.actively engaging in the trading of power, natural gas and environmental products across a variety of markets; and
d.negotiating and managing fuel supply arrangements with third parties for our generation assets, including scheduling, billing and settlement of physical deliveries of natural gas and other fuels.
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 Company.
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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 Company's central finance, legal, administrative, business development and investor relations functions.
Non-Controlling Interests
Our subsidiaries and operations in which we have non-controlling interests are as follows:
TransAlta Renewables
As at Dec. 31, 2021, the Company held, directly and indirectly, approximately 60.1 per cent of the issued and outstanding common shares in TransAlta Renewables. We remain committed to maintaining our position as the majority shareholder of TransAlta Renewables.
The Company 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 the Company and TransAlta Renewables. In connection with the services provided under the Management, Administrative and Operational Services Agreement, TransAlta Renewables pays us a 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, Administrative and Operational Services Agreement was amended so that the G&A Reimbursement Fee will be calculated quarterly in an amount equal to five per cent of adjusted 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 Company on any of the tracking preferred shares. This amendment did not 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 adjusted EBITDA calculated before taking into account the G&A Reimbursement Fee. During 2021, the G&A Reimbursement Fee was approximately $16 million.
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 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 its independent directors at any time if TransAlta's direct and indirect ownership in TransAlta Renewables falls below 20 per cent.
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: (a) the 74 MW Ottawa plant; and (b) the 72 MW Windsor plant. See the "Gas Business Segment" section of this AIF.
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PPAs
Renewables PPAs 
In August 2013, we entered into long-term Renewables PPAs with certain subsidiaries of TransAlta Renewables (each a "Merchant Subsidiary") providing for the purchase by the Company, for a fixed price, of all of the power produced at the Merchant Subsidiaries. The initial price payable in 2013 by the Company 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 2021 were $33.77 per MWh for wind facilities and $50.66 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
The Alberta PPAs expired on Dec. 31, 2020, and the facilities previously under the Alberta PPAs are now merchant in the Alberta power market. 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 was 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.
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. We also anticipate the generation mix to undergo a major shift in our key markets. 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, which include, without limitation:
a.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.
b.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 wind and solar generation and battery storage. As a result, these technologies now account for the majority of the new generating capacity added to many of the world's electricity grids.
c.Electrification is seen as a one of the most effective levers to reduce GHG emissions in many sectors such as transportation. We expect that renewable power generation will continue to be one of the fastest-growing sources of power generation in Canada, Australia and the US.
Alberta
Approximately 57 per cent of our gross installed capacity is located in Alberta. As of Jan. 1, 2022, our portfolio of merchant assets in Alberta is a combination of hydro facilities, wind facilities, a battery storage facility 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 physical and financial contracts to reduce our exposure to variable power and natural gas prices on our merchant generation.
Alberta's annual demand expanded by approximately 3.0 per cent from 2020 to 2021 as the economy reopened from COVID-19 and stronger market conditions for energy commodities supported power demand in the province. The average pool price in Alberta increased from $47/MWh in 2020 to $102/MWh in 2021. Pool prices were higher in each quarter compared to 2020, generally as a result of higher demand in the province and higher natural gas and carbon prices. In addition, the province experienced very strong weather-driven demand in June and July as well as in December.
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 $170 per tonne by 2030. Our portfolio of assets, we believe provides us with brownfield development opportunities in wind, solar, hydro and gas that give us an advantage over competitors when constructing generation facilities that use these fuel types.
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US Pacific Northwest
Our capacity in the US Pacific Northwest is represented by our Centralia coal facility, which declined to 670 MW of operating capacity as of Jan. 1, 2021. The Centralia coal facility is committed to be phased out over the next four years, with the remaining plant capacity scheduled to retire at the end of 2025. In the fourth quarter of 2020, we added a 49 per cent interest in the Skookumchuck wind facility.
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.
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 (dropping to 300 MW in 2025). The contract and our hedges allow us to satisfy power requirements from the market during low-priced periods.
Contracted Gas and Renewables
The markets in which we operate for developing or acquiring gas and renewable generation facilities is highly competitive in all markets in which we operate. Our track record as an experienced operator and developer supports our competitive position. We expect, where possible, to reduce our cost of capital and improve our competitive profile through efficient financing structures. In the US, our substantial tax attributes further increase our competitiveness.
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. These facilities generally have a substantial cost advantage over new builds and we have been able to add value by recontracting these facilities without incurring the significant capital expenditures required for a new facility. We have extended the contracted life of our Ottawa (2033 expiry), Windsor (2031 expiry), Parkeston (2026 expiry), Fort Saskatchewan (2030 expiry), and SCE (2038) facilities.
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 appears to be 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, which is expected to continue. The federal Department of Industry, Science, Energy and Resources 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. 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 the 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 SCE facilities in the Goldfields region have a number of projects in development under our newly extended contractual arrangement to support BHP achieve its decarbonization objectives. We expect this trend to continue and to create further opportunities for our business in Western Australia.
Seasonality and Cyclicality
Our business is cyclical, particularly in respect of the renewables generation held by TransAlta Renewables, due to: (a) the nature of business 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 Company’s exposure to the variations of any one natural resource in any one region. 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 the "Risk Factors" section of this AIF.
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Regulatory Framework
Below is a description of the regulatory framework in the markets that are material to the Company.
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. On Dec. 12, 2018, Environment and Climate Change Canada published two final regulations in the Canada Gazette, Part II to phase out coal-fired generation by 2030, as well as 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
Alberta remains an energy-only market where generators make power supply offers that clear against power demand. The demand and supply dynamics determine market clearing prices.
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 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 is currently undertaking a market renewal consultation that includes proposed fundamental changes to the electricity market. These include modifying the energy market, adding resource adequacy procurements, including medium- and long-term requests for proposals (RFP) and improving market operations and reliability. The implementation of the energy market changes are planned for end of 2023.
The IESO has also actively engaged market participants on the design of its medium-term RFP and medium-term capacity contract. The first medium-term RFP is restricted to existing resource that will be uncontracted in mid-2027. The medium-term RFP is scheduled to take place in 2022 and will award contracts with terms of three to five years and a commencement date of May 1, 2026. Furthermore, the IESO intends to provide mechanisms to bridge resources between contracts (i.e., extending an existing contract to the start date of a medium-term contract or starting a medium-term contract early). The Sarnia and Melancthon 1 facilities will participate in the medium-term RFP.
Due to the fact that our units are almost entirely contracted, we expect market rule changes to have minimal, near-term impact on the Company.
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").
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 its new Integrated Resource Plan ("IRP"). In 2020, BC Hydro started its Clean Power 2040 consultation process to feed into the development of the IRP. The purpose of 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. BC Hydro filed its 2021 IRP to the BCUC on Dec. 21, 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 that BC Hydro continues to have a need to renew energy purchase agreements with existing IPPs, which could include TransAlta's Pingston Hydro project.
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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, with contracts in place, are generally unaffected and are able to recontract.
New Brunswick
The Electricity Act (New Brunswick) is the legislation that sets out the framework and rules of law for how the electricity sector is managed in New Brunswick. The current Electricity Act (New Brunswick) was enacted in 2013. The Electricity Act (New Brunswick) also includes government policy directives that guide utility planning, including ensuring the safe, secure and equitable access to electricity at least cost of service. The Electricity Act (New Brunswick) gives New Brunswick Power Corporation ("NB Power") the authority to sell electricity within the province and to manage and operate NB Power’s resources and facilities for the supply, transmission and distribution of electricity within New Brunswick. The Electricity Act (New Brunswick) also makes NB Power responsible for promoting, developing and delivering energy efficiency, energy conservation, and demand side management programs in New Brunswick.
In 2014, the Government of New Brunswick committed to develop more renewable energy in New Brunswick. The Electricity from Renewable Resources Regulation - Electricity Act guides the development of renewable electricity resources in New Brunswick. The regulation requires NB Power to supply 40 per cent of its in-province electricity sales with renewable energy by 2020, which was achieved in both 2019 and 2020.
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. FERC oversees the market structure for all integrated market rules and wholesale sales from generators. 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)
The Lakeswind facility in Minnesota is connected to the Midwest Independent System Operator ("MISO") and falls under FERC jurisdiction. FERC-approved MISO tariffs dictate market and operational requirements 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. As a result, market changes are not expected have a material 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. As a result, market changes are not expected to have a material impact on net metering revenues.
New Hampshire (NE-ISO)
The Antrim facility 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 capacity market. The Antrim facility's electricity is offered into the market and transferred to the buyers. The Antrim facility has a long-term capacity supply obligation so it is not impacted by near term changes to the capacity market auction process. The Antrim facility and most other intermittent wind projects must take part in the NE-ISO's Do Not Exceed Dispatch. As a result, market changes are not expected to have a material impact on revenues.
North Carolina
The North Carolina Solar facility is a portfolio of 20 solar generation sites that are connected to Duke Energy's distribution system and are not directly connected to the PJM system. The assets are qualified facilities under the Public Utilities Regulatory Policy Act that are fully contracted to Duke Energy as the buyer. Duke Energy is regulated by the North Carolina Utilities Commission, which sets regulated rates for utilities, oversees resource planning and monitors resource contracting. Given that the North Carolina Solar facility is fully contracted to Duke Energy under a long-term PPA. As a result, market changes are not expected to have any material impact on revenues during the contract term.
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Oklahoma (SPP)
The White Rock Wind Projects are currently in development and are expected to be energized in the second half of 2023. They will be connected to the Southwest Power Pool ("SPP") which falls under FERC jurisdiction. FERC-approved SPP tariffs dictate market and operational requirements for facilities. SPP operates a wholesale energy market and an energy imbalance market. The White Rock Wind Projects's attributes, including energy, capacity, and environmental credits, will be transferred to the buyer under a long-term contract. As a result, market changes are not expected to have a material impact on revenues during the contract term.
Pennsylvania (PJM)
The Big Level facility 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. The Big Level facility'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). The Centralia facility 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 Company 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 Wyoming Public Service 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). The Wyoming wind facility is not regulated by the Wyoming Public Service 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 Company does not expect any material impact on revenue streams from any Wyoming Public Service 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. It is anticipated that the reforms will be implemented on or around 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 those noted below.
Operational Excellence
We have strong operational excellence built up over our 110-year history with extensive experience in wind, hydro, solar, storage and gas that is founded on one of Canada’s largest wind fleet and Alberta’s largest hydro fleet.

We continually benchmark ourselves against our previous year performance in order to drive operating efficiencies 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. We believe the continued maturity of this program will continue to drive further value in the operations of our facilities.
Strong Financial Position
Our strong cash flow results provide a pool of funds to be allocated to our funding priorities. Higher operating cash flow at the Company, combined with the structural reduction in sustaining capital, frees up additional capital capacity to allocate to growth, dividends and share buybacks.
Through the use of long-term contracts, approximately 50 per cent of our capacity is contracted in 2022 and 2023. The net revenue received under these contractual arrangements helps to minimize short-term revenue fluctuations due to the variable price of electricity. The Company also regularly hedges portions of its uncontracted merchant positions to further stabilize cash flows from market volatility.
Highly Credible Developer
We have internal development expertise with teams that are able to manage every aspect and every stage of new project development from resource assessment to site control, permitting, contracting, engineering, construction and project management.
Customers are increasingly looking not just to pricing for the procurement of clean electricity but also to a developer's credibility.
Portfolio Diversity
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 in a single Centralia facility unit until it is retired at the end of 2025. We will continue to optimize this facility until we fully complete the transition off coal by the end of 2025.
We believe that we can reduce the potential impact of external events that affect one fuel source or one geographic region on our performance given the location of our operations across Canada, the US 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 110 years, and many of our employees have been with us for more than 20 years.
Optimization and Trading Expertise
We believe that our Energy Marketing segment has enhanced returns of 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 fulfil electricity delivery obligations in the event of an outage.
Environmental, Social and Governance Strategy
We have a long history of adopting leading sustainability practices, including over 25 years of sustainability reporting and voluntarily integrating our sustainability results into our annual financial performance. 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) and the TCFD. TransAlta has been operating hydroelectric facilities for more than 110 years and was an early adopter of wind power generation, acquiring its first wind assets in 2002. Today, we are the one of the leading producers of wind power in Canada. Through our ongoing energy transition efforts, we are on track to reduce our total GHG emissions by approximately 75 per cent from 2015 levels by 2026.
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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. 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 as well as the communities in which we operate to promote sustainable development.
Ongoing and Recently Passed Environmental Legislation
Changes in current environmental legislation do have an impact on our operations and business. See the "Risk Factors" section of this AIF.
Climate-Related Financial Disclosure
TransAlta has prepared an assessment of climate-related risks and opportunities to conform with the recommendations of TCFD describing our climate change strategy, governance, risk management approach, GHG metrics and targets. In 2021, we conducted our first climate-related scenario analysis to strengthen decision-making and climate-related reporting. Qualitative findings are included in our annual management's discussion and analysis for the year-ended Dec. 31, 2021.
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 rose by $10 per year until reaching $50 per tonne in 2022 The federal government has announced the price will rise by $15 per tonne of CO2e emissions per year starting in 2023 until it reaches $170 in 2030.
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. Ontario was the only jurisdiction where TransAlta operates assets covered by the OBPS; however, as of Jan. 1, 2022, Ontario transitioned from the federal OBPS to the Ontario Emissions Performance Standards program. Alberta and Ontario are subject to the federal consumer carbon tax.
Other jurisdictions that were compliant with the GGPPA did not have the backstop mechanism imposed in 2020. To this point, these jurisdictions have filed and had their carbon pricing programs approved annually by the federal government. The federal government has announced its intent to approve provincial programs in 2023 for the full 2023 to 2030 period. 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.
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. 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 regulations and other initiatives.

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 of CO2e per year from 2023 until reaching $170 per tonne of CO2e by 2030;
•carbon obligations will rise as the benchmark under large emitter regulations tighten;
•develop a Clean Electricity Standard to achieve a net zero grid in Canada;
•over $10 billion of funding will be available for everything from electric vehicles and clean energy development, to battery storage and improved grid technology;
•the CFR will apply to liquid fuels but not to gaseous and solid fuels; and
•develop a GHG offset credit system for the CFR and the OBPS.
In April 2021, the Government of Canada announced a revised GHG emissions target of 40 per cent to 45 per cent below 2005 levels by 2030. During the 2021 election campaign, the government committed to achieving a net zero grid by 2035 and subsequently indicated that its proposed Clean Electricity Standard would be designed to achieve this goal.
In December 2021, the government extended the timeline to release an Emissions Reduction Plan, as required by the new Canadian Net-Zero Emissions Accountability Act, to March 2022. This plan is expected to provide more detail regarding how the government intends to reach Canada's 2030 emissions targets.
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TransAlta has made a submission regarding the federal Emissions Reduction Plan and will continue to engage with governments to mitigate risks and identify opportunities within the new federal plan.
Gas Performance Standards 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 a prescribed number of additional years past the end of its useful life. These standards apply to TransAlta's coal to gas facilities.
Alberta
Large Emitter Greenhouse Gas Regulations
On Jan. 1, 2020, the Government of Alberta replaced the previous Carbon Competitiveness Incentive Regulation ("CCIR") with TIER. 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 2022 has been set at $50 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 expected in 2022.
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 (d) remitting emission offset credits.
As required by the GGPPA, the Alberta government submits annual reports with TIER program details to the federal government. The federal government reviewed TIER and found it compliant with the GGPPA for 2022.
The Company will continue to receive offsets and EPC for its renewable facilities under TIER ensuring expected revenues are realized.
Bill 86, the Electricity Statutes Amendment Act ("ESAA")
The ESAA was introduced on Nov 17, 2021, and passed its second reading on Nov. 24, 2021. Bill 86 plans to address the changing ways that electricity producers and consumers interact with and use Alberta’s power grid to encourage adoption and investment in emerging energy systems and technologies. Bill 86 passed first and second readings on Nov. 17. and 24, 2021, respectively, but did not get proposed for final reading or proclamation. The Government is expected to re-introduce Bill 86 with a different name in the spring session for a final reading when the accompanying regulations are drafted. It is expected to be consistent with the originally proposed ESAA, although could include changes based on industry feedback.
If passed, the ESAA will: (a) allow the integration of energy storage into Alberta’s interconnected electricity system in both the competitive electricity market and the transmission and distribution system; (b) allow unlimited self-supply with export while ensuring that transmission system costs are balanced among all system participants; modernize Alberta’s electric distribution system to ensure cost-effectiveness; and (c) include a requirement for distribution owners to provide long-term planning process.
TransAlta will continue to participate in the regulatory development engagements to ensure that our strategic interest and positions, especially with regards to storage, are well represented.
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. 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 regulations for the provincial Emissions Performance Standard ("EPS") carbon pricing system. On Sept. 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. As of Jan. 1, 2022, the EPS system applies in Ontario and the federal OBPS no longer applies to covered emitters.
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The EPS-proposed stand-alone facility electricity performance standard differs from the OBPS performance standard for cogeneration facilities. This may place cogeneration electricity at a carbon pricing disadvantage relative to stand-alone electricity facilities as the efficiency benefits of cogeneration are not fully realized. However, as carbon costs are passed-through under current contracts, risks related to changes under the Ontario EPS are reduced. Notwithstanding, TransAlta is working to understand the interpretation of the policy in terms of the applicable quantification methodologies and any potential implications to our thermal asset contracts in Ontario.
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 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, published on July 9, 2021, sets the alternative compliance payment rate for the Massachusetts RPS Class I Minimum Standard at $60 per MWh in compliance year 2021, $50 per MWh in compliance year 2022 and $40 per MWh in compliance year 2023. The RECs are currently trading at $38/MWh below the 2022 ceiling price. Despite these changes to the Massachusetts ceiling price, the Le Nordais contract is hedged out through 2023 so we are insulated from any changes to the decreasing ceiling price. The Company will continue to market these RECs at the best available market price in the New England region.
Minnesota
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.
North Carolina
The North Carolina market has a state Renewable Energy and Energy Efficiency Portfolio Standard ("REPS") that requires utilities in North Carolina to meet up to 12.5% of their energy needs through renewable energy resources or energy efficiency. Under our PPAs with Duke Energy, Duke Energy receives the renewable electricity, capacity and environmental attributes from each facility. To date, the North Carolina REPS have had no material impact on our facility revenues.
New Hampshire
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
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-powered 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.
On May 17, 2021, Governor Inslee signed Washington State's cap and trade law. This law will cover entities that emit over 25,000 tCO2e per year. It creates a “cap-and-invest” program, which sets a statewide cap on greenhouse gas emissions and then auctions or allocates emissions allowances. The cap-and-invest trading program has three mechanisms for participation: (a) Covered entities – GHG reporters that meet the covered emission thresholds; (b) Opt-in entities – GHG emitters that don’t meet the covered emission thresholds, but choose to participate; and (c) General market participants – anyone else that wants to hold allowances. TransAlta’s Centralia facility will be exempt from the cap-and-invest program until it closes in 2025, as per agreement with the State of Washington. TransAlta is seeking to understand how the new law will impact energy trading in the market.
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 Company expects state environmental and market regulations, and policy will not have a material impact on revenues.
Australia
In October 2021, the Australian government announced a target to reach net zero emissions by 2050. The announcement was made at the UN Climate Change Conference in Glasgow ("COP26") and is in addition to the longer-standing target to cut emissions by 26 per cent to 28 per cent below 2005 levels by 2030. With the announcement, the Commonwealth Government is now fully aligned with all Australian states and territories, each a target of net zero emissions by or before 2050, although apart from the Australian Capital Territory and the State of Victoria, none of the targets are legislated.

The Australian government’s plan to achieve the necessary reductions is focused on technology development and cost reduction, enabling deployment at scale through incentives and infrastructure development. The plan also focuses on opportunities in new markets such as clean hydrogen exports as well as expanding markets for minerals and metals required for low emissions economies such as copper, nickel and lithium. The Australian government provides various targeted funding in this area, including via the Australian Renewable Energy Agency, which administers a funding application process for projects seeking to develop or commercialize technologies related to emissions reductions. For businesses, the main legislated compliance mechanisms include the Renewable Energy Target ("RET") and the safeguard mechanism.
The RET has been in place since 2001 to achieve legislated targets of renewable energy in Australia. The current target of 33,000GWh/year of renewable energy production has applied from 2020 and will continue until 2030 when the scheme is due to expire. Under the scheme, renewable energy providers create tradable certificates (one for every MWh) with an obligation on electricity retailers to purchase certificates in proportion to their customers’ load requirements.
On Dec. 13, 2014, the Australian government enacted legislation to implement the Emissions Reduction Fund ("ERF"). The ERF's safeguard mechanism commenced on July 1, 2016, and 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.
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 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 is not expected to exceed the sectoral emission target as no new coal generation is being built and older coal facilities are being retired. It is expected that the Company's gas facilities will not be subject to carbon costs under current regulations, unless regulatory changes are enacted.
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TransAlta Activities
Reducing the environmental impact of our activities benefits not only our operations and financial results, but also 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 environment and safety 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
At TransAlta, we operate our facilities in line with best practices related to environmental management standards. Our environmental management system ("EMS") processes are verified annually to ensure we continuously improve our environmental performance. Our knowledge of EMS has matured since when we aligned our processes in accordance with the internationally recognized ISO 14001 standard. Currently, the most material natural or environmental capital impacts to our business are GHG emissions, air emissions (i.e., pollutants, metals) and energy use. Other material impacts that we manage and track performance on using our EMS practices include land use, water use and waste management.
Renewable Power
We continue to invest in and build renewable power resources. The Company completed the construction of its 206 MW Windrise wind project in the third quarter of 2021 and commercial operation was achieved on Nov. 10, 2021. The Company also acquired the 122 MW North Carolina Solar facility in November 2021. On Dec. 22, 2021, we entered into two long-term PPAs for the offtake of 100 per cent of the generation from our 300 MW White Rock East and White Rock West wind projects located in Oklahoma.
We believe that a larger renewable portfolio provides increased flexibility in generation and creates incremental environmental value through environmental attributes (i.e., RECs and 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.
The most significant strides in reducing the Company's environmental footprint are related to our coal transition. We successfully completed the transition of our coal units in Alberta to natural gas at the end of 2021. The Keephills Unit 3 conversion to natural gas began during the third quarter of 2021 and was completed in December 2021. Earlier in 2021, Keephills Unit 2, Sundance Unit 6 and our non-operated Sheerness Unit 1 completed their conversions to natural gas, resulting in all these units now running solely on natural gas. We also retired Sundance 5 and suspended the repowering project. On Dec. 31, 2021, Keephills Unit 1 was retired and on April 1, 2022, Sundance Unit 4 will be retired. Effective Jan. 1, 2022, we discontinued the firing of coal in Canada.
The combination of all these actions will significantly reduce environmental impacts from air emissions, GHG emissions, water usage and land disturbance, and reduce energy usage at the respective facilities.
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 anticipate 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. See the "Risk Factors" section of this AIF and see "Governance and Risk Management" section of our annual management's discussion and analysis for the year-ended Dec. 31, 2021. 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, see"Governance and Risk Management" section of our annual management's discussion and analysis for the year-ended Dec. 31, 2021, which is incorporated by reference herein.
A reference herein to a material adverse effect on the Company means such an effect on the Company or its business, financial condition, results of operations or cash flows, as the context requires.
The operation and maintenance of our facilities involve 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 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 any other unforeseen problems may disrupt the operation and maintenance of our facilities and may materially adversely affect our business.
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. Due to COVID-19, it is possible that the potential cross-border travel and transportation restrictions could impact the timely availability of services, parts and equipment.
While we maintain an inventory of, or otherwise make arrangements to obtain, spare parts to replace critical equipment and maintain insurance for property damage and business interruption 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 such circumstances, the costs to produce the power 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 Company's facilities may adversely affect its results of operations.
Unexpected increases in the Company's cost structure that are beyond the control of the Company 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.
Changes in the price of 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, and in particular in the Alberta spot market. 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 and 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 precisely predict future electricity prices and electricity price volatility (particularly lower Alberta electricity prices) could have a material and adverse effect on us.
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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.
In particular, the replacement of all 50 turbine foundations at the Kent Hills 1 and 2 facilities could present material risks to the Company if the Company's subsidiary, Kent Hills Wind LP, is found to be in default of its PPAs with New Brunswick Power Corporation or an event of default is deemed to have arisen under the trust indenture governing the KH Bonds, which could allow the holders of such bonds to direct the KH Trustee to declare the principal and interest on the KH Bonds, together with any make-whole amount due thereunder, to be immediately due and payable and to direct the KH Trustee to exercise rights against certain collateral.
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 Company's construction projects and the operation and maintenance of our assets.
The impact of COVID-19 and the associated general economic downturn on the Company 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 impacting our ability to continue to staff the Company’s operations and facilities; impacts on the Company’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 Company’s efforts to mitigate the impact of COVID-19; deterioration of worldwide credit and financial markets that could limit the Company’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 Company’s supply chain; impairments and/or writedowns of assets; and adverse impacts on the Company’s information technology systems and the Company’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 at times 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 2022.
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 (i.e., 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 makes 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 Company's development or construction projects, and delays in the completion of services, any of which may result in the Company incurring penalties under contracts, additional costs or the cancellation of contracts.
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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, supply chain constraints, 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 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 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 or steam 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 or steam for the required availability in a given contract year, penalty payments may be payable to the relevant purchaser by us and could give rise to termination rights. The payment of any such penalties or the termination of such PPAs 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.
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We depend on certain joint venture, strategic and other partners that may have interests or objectives that 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 on the Company'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 processes 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 facilities. 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 Company to continue to generate electricity for such periods, and such circumstances could pose threats to the Company'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.
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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 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.
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 Company subject to environmental regulation and the implementation of provincial, state and national environmental regulations 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. 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.
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 Company, our operations and assets into compliance, which could have a material adverse effect on our business.
The estimated reclamation costs applicable to the Company's operations may be inaccurate and could require greater financial resources than currently anticipated. As a mine owner, we maintain 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, 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 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.
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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 Gas facilities are reliant on having adequate natural gas and our Centralia facility requires coal available to run the facility 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 facility is sourced from the Powder River Basin in Montana and Wyoming through contracts to purchase and transport such coal to our Centralia 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 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.
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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 Company, its customers, partners or others with whom the Company 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 purchased 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 any service disruptions.
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.
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 US and Australia. These areas of operation are affected by competition ranging from large utilities to small IPPs, 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. Furthermore, older facilities may over time be unable to compete with newer more efficient facilities utilizing improvements to existing power technologies and cost-efficient new technologies. Climate change will drive innovation and transformation of the power generation sector, including energy production and consumption.
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Changes in the price and availability of fuel supplies required to generate electricity may materially and adversely affect our business.
We buy natural gas 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. Furthermore, a period of prolonged inflation may negatively impact our revenue, operating costs, maintenance costs and capital expenditures.
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" section of this AIF.
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 and development of projects and to support 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, 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's debt securities will be structurally subordinated to any debt of our subsidiaries that is 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 in respect 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 or tax withholding amounts.
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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.
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. See Note 16(F) of our audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see "Documents Incorporated by Reference" section of this AIF.
Changes to our reputation 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 and that 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 on common shares 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 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.
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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 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.
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, 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.
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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 and Australian 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, cyberattacks 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.
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 loss or damage to any of our generation facilities may not be sufficient to permit us to continue to make payments on our debt.
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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 Company 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 2021, we successfully renegotiated one collective bargaining agreement. We expect to renegotiate seven collective bargaining agreements in 2022 and expect to renegotiate one collective bargaining agreement in 2023.  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 Company is required to develop and retain a skilled workforce for its operations. Many of the employees of the Company possess specialized skills and training and the Company must compete in the marketplace for these workers. As at Dec. 31, 2021, we had 1,282 active employees, which includes full-time, part-time and temporary employees. Approximately 33 per cent of our employees are represented by labour unions. We are currently a party to 11 different collective bargaining agreements.
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 Feb. 23, 2022, there were 271,219,820 common shares outstanding and 9,629,913 Series A Shares, 2,370,087 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 Company does not have any escrowed securities.
Common Shares
Each common share of the Company entitles the holder thereof to one vote for each common share held at all meetings of shareholders of the Company, 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.
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Normal Course Issuer Bid
On May 25, 2021, the TSX accepted the Company's 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 31, 2021, and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election.
Under TSX rules, not more than 169,737 common shares (being 25 per cent of the average daily trading volume on the TSX of 678,948 common shares for the six months ended April 30, 2021) 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, 2021, the Company did not purchase and cancel common shares under the NCIB. See Note 27 of our audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see "Documents Incorporated by Reference" section of 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 the Company 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 Company, 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 the Company 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 Company, or a reduction of stated capital, no sum shall be paid or assets distributed to holders of other shares of the Company 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.
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 Company.
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 on a one-for-one basis. On March 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis and 871,871 Series B Shares were converted into Series A Shares on a one-for-one basis. Certain provisions of the Series A Shares are discussed below.
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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 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, 2021, 1,417,338 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 Company 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 Company.
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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
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 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis and 871,871 Series B Shares were converted into Series A Shares on a one-for-one basis. 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 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.
On March 31, 2021, 871,871 of the Series B Shares were converted into Series A Shares on a one-for-one basis.
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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 Company 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 Company.
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 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.
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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 Company 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 Company.
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 (the "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 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 the Company 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 the Company, at its option, in whole or in part, on Sept. 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 Sept. 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.
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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 (the "Series F Shares"), subject to certain conditions, on Sept. 30, 2017, and will again have the right to convert on Sept. 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 Sept. 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 Sept. 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 Company 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 Company.
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.
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 the Company 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.
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Redemption of Series G Shares
The Series G Shares were redeemable by the Company, at its option, in whole or in part, on Sept. 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 Sept. 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 Sept. 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 Sept. 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 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 Company 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 Company.
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 Company will pay the Redemption Price in cash (the “Cash Redemption Amount”).
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Except in the case of an Optional Redemption by the Company or a Cash Acceleration Event, as described below, the Series I Shares will be exchangeable into interests (“Hydro Equity Interest”) in the equity (the “Hydro Equity”) of TA Alberta Hydro LP (“Hydro Assets Owner”), a special purpose vehicle formed by the Company. 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 Company 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 Company, 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 (“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 Company 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 Company 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 Company (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 Company or by the Company to Brookfield to account for the difference between $1.95 billion and the tax-affected 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 that enjoins the completion of the Exchange Right (“Cash Acceleration Event”), then Brookfield will be entitled to the Cash Redemption Amount.
Related-Party Articles Provisions
The articles of the Company contain provisions restricting the ability of the Company 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 Company, 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 Company. 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 Company with a Major Shareholder; the furnishing of financial assistance by the Company to a Major Shareholder; certain sales of assets or provision of services by the Company to a Major Shareholder or vice versa; certain issuances of securities by the Company that increase the proportionate voting interest of a Major Shareholder; a reorganization or recapitalization of the Company that increases the proportionate voting interest of a Major Shareholder; and the creation of a class or series of non-voting shares of the Company that has a residual right to participate in earnings of the Company and assets of the Company upon dissolution or winding up.
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Shareholder Rights Plan
The Company implemented a shareholder rights plan ("Rights Plan") pursuant to a Shareholder Rights Plan Agreement ("Rights Plan Agreement") dated as of Oct. 13, 1992, as amended and restated as of April 26, 2019, between the Company 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 2021, we renewed our syndicated credit agreement giving us access to a $1.25 billion committed credit facility and converted the facility into a Sustainability Linked Loan. The agreement is fully committed, expiring in 2025. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. The amendments to the syndicated credit facility in 2021 aligned the cost of borrowing to TransAlta's GHG emission reductions and gender diversity targets, which are part of the Company's overall ESG strategy, and will result in a cumulative pricing adjustment to the borrowing costs on the syndicated credit facilities as well as a corresponding adjustment to the standby fee. 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 first quarter of 2019 was amended from $500 million to $700 million. In 2021, the credit agreement was renewed and extended to 2025. The credit facility is subject to a number of customary covenants and restrictions in order to maintain access to the funding commitments. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see "Documents Incorporated by Reference" section of this AIF.
Long-Term Debt
The long-term debt of the Company 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. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see "Documents Incorporated by Reference" section of this AIF.
Exchangeable Securities
On March 22, 2019, the Company entered into a definitive Investment Agreement, whereby Brookfield agreed to invest $750 million in the Company 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 ("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.
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.
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In connection with the Investment Agreement, Brookfield has committed to purchase common shares of the Company 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 nine 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 Company’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 (“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 Brookfield (“Standstill”), with customary exceptions, which will be in effect for three years starting from May 1, 2019 (“Standstill Period”). Among other things, the Standstill prohibits Brookfield from acquiring an ownership interest in the Company 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 Company 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 Company on May 1, 2019 (“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 (“Demand Registration”) to the Company 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 Company of a Demand Registration, the Company 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 Company 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 Company proposes to file a prospectus supplement with respect to the distribution of any TransAlta common shares to the public, then the Company 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 Company will use commercially reasonable efforts to include in such Prospectus Supplement such Registrable Securities (a “Piggy Back Offering”), unless the Company’s managing underwriter or underwriters determines, in good faith, that including such Registrable Securities in the distribution would, in their opinion, adversely affect the Company’s distribution or sales price of the securities being offered by the Company.
The Demand Offerings and Piggy Back Offerings are subject to various conditions and limitations. The Company 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 Company 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.
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In the case of a prospectus supplement filed in connection with a Demand Offering or Piggy Back Offering, the Company will pay all applicable fees and expenses incident to the Company’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 Company receives the offering request, the Company 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 Company in such offering. The Company 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 Company will pay all selling expenses with respect to any Securities sold for the account of the Company. The Company 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 Company, 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 Company has non-recourse debt outstanding in an amount equal to approximately $1,908 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. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see "Documents Incorporated by Reference" section of this AIF.
Tax Equity
In November 2021, the Company assumed US$16 million in tax equity financing as part of the acquisition of the North Carolina Solar portfolio.
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 Company 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. See Note 24 of our audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see"Documents Incorporated by Reference" section of 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 Company'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. The incident at Kent Hills has resulted in Kent Hills Wind LP currently being unable to make distributions.
As a result of the determination that all 50 foundations at Kent Hills 1 and Kent Hills 2 require replacement, as well as certain resulting amendments to applicable insurance policies, Kent Hills Wind LP has provided notice to the KH Trustee for the approximately $221 million outstanding non-recourse KH Bonds that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Upon the occurrence of any events of default, holders of more than 50 per cent of the outstanding principal amount of the KH Bonds have the right to direct the KH Trustee to declare the principal and interest on the KH Bonds and all other amounts due thereunder, together with any make-whole amount due thereunder, to be immediately due and payable and to direct the KH Trustee to exercise rights against certain collateral. Kent Hills Wind LP is in discussions with the KH Trustee and holders of the KH Bonds to negotiate required waivers and amendments while the Company works to remedy the matters described in the notice. Although Kent Hills Wind LP expects that it will reach agreement with the KH Trustee and holders of the KH Bonds with respect to terms of an acceptable waiver and amendment, there can be no assurance that the Company will receive such waivers and amendments. See "General Development of the Business —Three-Year History — Generation and Business Development" section of this AIF.
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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 Company’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 maintaining a strong balance sheet and financial position with strong cash flow coverage ratios in order to access sufficient financial capital. Our credit ratings as of Dec. 31, 2021, are as follows:

DBRSMoody'sS&P
Issuer RatingBBB (low)Not applicableBB+
Corporate Family RatingNot applicableBa1Not applicable
Preferred Shares
Pfd-3 (low)(1)
Not applicable
P-4(High)
Unsecured Debt/MTNsBBB (low)Ba1/LGD4BB+
Rating OutlookStableStableStable
Note:
(1) The outstanding Preferred Shares all have the same rating.

In 2021, Moody’s reaffirmed its Corporate Family Rating of Ba1 and maintained its rating outlook at stable. During 2021, DBRS Limited confirmed the Company’s Issuer Rating and Unsecured Debt/Medium-Term Notes rating of BBB (low), and the Company's Preferred Shares rating of Pfd-3 (low), all with stable trends. During 2021, S&P Global Ratings reaffirmed the Company’s Issuer Credit Rating and Senior Unsecured Debt rating of BB+ with a stable outlook.
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, 2021, 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 that 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 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.
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, 2021, 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.
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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, 2021, 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, 2021, 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.
S&P Global Ratings
The S&P Global Ratings 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, 2021, 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.
The S&P Global Ratings 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 S&P Global Ratings 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 S&P Global Ratings 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. The S&P Global Ratings 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 S&P Global Ratings.  Each of our outstanding Preferred Shares Series has 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. 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.
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 the S&P Global Ratings 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 the S&P Global Ratings in the future if, in its judgement, circumstances so warrant.
We have paid fees for rating services to DBRS, Moody's, and the S&P Global Ratings during the last two years. We have also paid fees to the S&P, DBRS and Kroll Bond Rating Agency for certain other services provided to the Company during the last two years.
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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:
PeriodDividend per Common Share
2019First Quarter$0.04
Second Quarter$0.04
Third Quarter$0.04
Fourth Quarter$0.04
2020First Quarter$0.04
Second Quarter$0.0425
Third Quarter$0.0425
Fourth Quarter$0.0425
2021First Quarter$0.0450
Second Quarter$0.0450
Third Quarter$0.0450
Fourth Quarter$0.05
2022
First Quarter(1)
$0.05
Note:
(1) Dividends have been declared but not yet paid.
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
PeriodDividend per Series A Share
2019First Quarter$0.16931
Second Quarter$0.16931
Third Quarter$0.16931
Fourth Quarter$0.16931
2020First Quarter$0.16931
Second Quarter$0.16931
Third Quarter$0.16931
Fourth Quarter$0.16931
2021First Quarter$0.16931
Second Quarter$0.17981
Third Quarter$0.17981
Fourth Quarter$0.17981
2022
First Quarter(1)
$0.17981
Note:
(1) Dividends have been declared but not yet paid.
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Series B Shares
PeriodDividend per Series B Share
2019First Quarter$0.17889
Second Quarter$0.19951
Third Quarter$0.20984
Fourth Quarter$0.22301
2020First Quarter$0.22949
Second Quarter$0.22800
Third Quarter$0.14359
Fourth Quarter$0.13693
2021First Quarter$0.13186
Second Quarter$0.13108
Third Quarter$0.13479
Fourth Quarter$0.1397
2022
First Quarter(1)
$0.13309
Note:
(1) Dividends have been declared but not yet paid.
Series C Shares
PeriodDividend per Series C Share
2019First Quarter$0.25169
Second Quarter$0.25169
Third Quarter$0.25169
Fourth Quarter$0.25169
2020First Quarter$0.25169
Second Quarter$0.25169
Third Quarter$0.25169
Fourth Quarter$0.25169
2021First Quarter$0.25169
Second Quarter$0.25169
Third Quarter$0.25169
Fourth Quarter$0.25169
2022
First Quarter(1)
$0.25169
Note:
(1) Dividends have been declared but not yet paid.
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Series E Shares
PeriodDividend per Series E Share
2019First Quarter$0.32463
Second Quarter$0.32463
Third Quarter$0.32463
Fourth Quarter$0.32463
2020First Quarter$0.32463
Second Quarter$0.32463
Third Quarter$0.32463
Fourth Quarter$0.32463
2021First Quarter$0.32463
Second Quarter$0.32463
Third Quarter$0.32463
Fourth Quarter$0.32463
2022
First Quarter(1)
$0.32463
Note:
(1) Dividends have been declared but not yet paid.
Series G Shares
PeriodDividend per Series G Share
2019First Quarter$0.33125
Second Quarter$0.33125
Third Quarter$0.33125
Fourth Quarter$0.31175
2020First Quarter$0.31175
Second Quarter$0.31175
Third Quarter$0.31175
Fourth Quarter$0.31175
2021First Quarter$0.31175
Second Quarter$0.31175
Third Quarter$0.31175
Fourth Quarter$0.31175
2022
First Quarter(1)
$0.31175
Note:
(1) Dividends have been declared but not yet paid.
Series I Shares
TransAlta also declared an aggregate cash dividend of approximately $7 million in respect of the issued and outstanding Series I Shares for the period starting from and including Sept. 30, 2021, up to but excluding Dec. 31, 2021, which will be paid on Feb. 28, 2022.
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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 ("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 ($)
MonthHighLowVolume
2021
January11.579.5719,096,016
February 12.3410.9715,152,046
March11.9510.1019,816,302
April12.5111.926,861,255
May12.2110.8212,430,428
June12.6111.0712,641,889
July13.0511.9610,659,547
August13.5012.2211,298,887
September13.3912.2411,917,443
October14.5413.2410,928,970
November14.6112.709,157,007
December14.4413.058,163,601
2022
January14.7512.6315,550,257
February 1-2314.0612.998,752,336

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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 SecurityDescription of Transaction
Dec. 10, 2010(1)
12,000,000 Series A Shares$25.00Public Offering
March 31, 2021(2)
871,871 Series A SharesN/AConversion of Series B Shares
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 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis, and 871,871 Series B Shares were converted to Series A Shares on a one-for-one basis.

Price ($)
MonthHighLowVolume
2021
January12.4010.47316,112
February13.3912.00327,177
March 13.5012.96534,183
April13.6512.99123,610
May14.5013.60196,059
June14.7513.68354,964
July14.7513.90179,870
August14.7014.27179,083
September14.6813.85216,564
October15.8014.47544,268
November16.6915.74101,549
December16.2915.30114,197
2022
January17.4415.99190,737
February 1-2317.1515.9034,309

Series B Shares
Our Series B Shares are listed on the TSX under the symbol "TA.PR.E".
Date of IssuanceNumber of SecuritiesIssue Price per SecurityDescription of Transaction
March 31, 2016(1)
1,824,620 Series B SharesN/AConversion of Series A Shares
March 31, 2021(2)
1,417,338 Series B SharesN/AConversion of Series A Shares
Notes:
(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.
(2) On March 31, 2021, 1,417,338 of the Series A Shares were converted into Series B Shares on a one-for-one basis. Also on March 1, 2021, 871,871 of the Series B Shares were converted into Series A Shares on a one-for-one basis.

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Price ($)
MonthHighLowVolume
2021
January12.3510.2782,249
February13.3011.8274,012
March 13.5412.1242,472
April13.1012.3538,338
May13.7812.6117,350
June15.0013.4144,450
July14.8213.009,100
August14.3612.025,600
September13.8813.5138,200
October15.5013.6136,355
November16.6015.1524,018
December15.7514.7042,200
2022
January17.0015.3524,050
February 1-2316.8916.009,382
Series C Shares
Our Series C Shares are listed on the TSX under the symbol "TA.PR.F".
Date of IssuanceNumber of SecuritiesIssue Price per SecurityDescription of Transaction
Nov. 30, 2011(1)
11,000,000 Series C Shares$25.00Public Offering
Note:
(1) Series C Shares were issued pursuant to a public offering by way of a prospectus supplement dated Nov. 23, 2011, to a short form base shelf prospectus dated Nov. 15, 2011.
Price ($)
MonthHighLowVolume
2021
January16.0114.89272,060
February17.1015.66174,101
March 17.3116.59278,845
April17.7317.0487,821
May18.7017.40106,175
June19.1618.25154,586
July19.1018.1553,097
August19.0818.46285,674
September18.9218.50867,520
October20.8018.64993,455
November21.0520.22227,252
December20.2719.8893,313
2022
January21.4520.12109,454
February 1-2321.5421.0284,516


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Series E Shares
Our Series E Shares are listed on the TSX under the symbol "TA.PR.H".
Date of IssuanceNumber of SecuritiesIssue Price per SecurityDescription of Transaction
Aug. 10, 2012(1)
9,000,000 Series E Shares$25.00Public Offering
Note:
(1) Series E Shares were issued pursuant to a public offering by way of a prospectus supplement dated Aug. 3, 2012, to a short form base shelf prospectus dated
Nov. 15, 2011.
Price ($)
MonthHighLowVolume
2021
January18.9317.88339,587
February20.4018.34285,496
March 20.3419.27218,350
April20.1419.80127,084
May21.3820.05261,196
June22.1821.27254,987
July22.1821.27254,987
August22.8421.78836,903
September22.5321.76235,276
October23.6422.40338,264
November24.0023.2597,870
December23.3022.24124,844
2022
January24.1322.56147,605
February 1-2324.0523.61100,201
Series G Shares
Our Series G Shares are listed on the TSX under the symbol "TA.PR.J".
Date of IssuanceNumber of SecuritiesIssue Price per SecurityDescription of Transaction
Aug. 15, 2014(1)
6,600,000 Series G Shares$25.00Public Offering
Note:
(1) Series G Shares were issued pursuant to a public offering by way of a prospectus supplement dated Aug. 8, 2014, to a short form base shelf prospectus dated
Dec. 9, 2013.
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Price ($)
MonthHighLowVolume
2021
January20.0018.85101,974
February21.2019.36164,127
March 21.0020.22127,368
April21.1120.37137,229
May22.5020.65124,017
June24.1021.77182,192
July23.9023.02211,632
August23.9523.1082,511
September23.9923.25170,936
October24.0023.54167,275
November24.4123.70102,111
December24.2423.5552,076
2022
January24.6723.63103,304
February 1-2324.3923.9638,348
Series I Shares
On Oct. 30, 2020, the Company 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 million. 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 February 23, 2022, 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 ResidenceYear First Became DirectorPrincipal Occupation
Rona H. Ambrose
Alberta, Canada
2017The Honourable Rona Ambrose is Chair of the Governance, Safety and Sustainability Committee. Ms. Ambrose is the Deputy Chairwoman of TD Securities. She was the 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, she 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. She 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 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. She is a Global Fellow at the Wilson Centre Canada Institute in Washington, DC, serves on the advisory board of the Canadian Global Affairs Institute and is a director of Coril Holdings Ltd. and Andlauer Healthcare Group. She has a Bachelor of Arts from the University of Victoria and a Master of Arts 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.
John P. Dielwart
Alberta, Canada
2014Mr. 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 of ARC Financial but remains as a partner and member of ARC Financial's Investment Committee, and currently represents ARC Financial on the board of Aspenleaf Energy Limited. Mr. Dielwart has a Bachelor of Science with distinction (civil engineering) 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 Producers. 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. Mr. Dielwart provides the Company with a wealth of experience in leadership, finance and entrepreneurship along with a strong understanding of the commodity markets in which we operate, specifically the oil and gas markets.
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Name, Province (State) and Country of ResidenceYear First Became DirectorPrincipal Occupation
Alan J. Fohrer
California, US
2013
Mr. Fohrer is the former Chairman and Chief Executive Officer of Southern California Edison Company ("SCEC"), a subsidiary of Edison International 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 international projects, which enhanced the value of the assets sold in subsequent years. Mr. Fohrer also served as Executive Vice-President and Chief Financial Officer of both Edison and SCEC from 1995 to 1999. After 37 years with Edison, Mr. Fohrer retired in Dec. 2010. Mr. Fohrer 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. 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 has served on boards of directors of the Institute of Nuclear Power Operations, the California Chamber of Commerce, Duratek, Inc., Osmose Utilities Services, Inc., MWH, Inc. and Synagro, a private waste management company. 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. Mr. Fohrer brings to the Company experience in accounting, finance and the power industry from both a regulated and deregulated market perspective.
Laura Folse
Texas, US
2021Ms. Folse is the former CEO of BP Wind Energy, North America, where she led a business with over 500 employees and contractors and that consisted of of 14 wind farms across 8 states with an operating capacity of over 2.5 gigawatts. Prior to her role as CEO of BP Wind Energy, North America, she served at BP p.l.c. as Executive VP, Science, Technology, Environment and Regulatory Affairs, in which she led the operational, scientific and technological programs within the multi-billion dollar cleanup and restoration effort in response to the 2010 BP Macondo well explosion off the coast of Louisiana. At its peak, the clean-up project team that she led consisted of over 45,000 people working across five US Gulf and Mexico states. She successfully negotiated with federal, state, and local government officials to implement and conclude the offshore and onshore clean-up efforts. Prior thereto, she held numerous leadership roles with increasing responsibility and complexity within BP p.l.c. Ms. Folse has a Master of Management, Business from Stanford University, a Master of Science, Geology from the University of Alabama and a Bachelor of Science, Geology from Auburn University. Ms. Folse is a Board member for the Auburn University College of Arts & Sciences and was a Board member for the American Wind Energy Association from 2016 to 2019. Ms. Folse brings to the Company experience in corporate risk management, large-scale crisis management, leveraging data analysis, leading large and complex organizations, and driving cultural change while realizing improvements in safety, operational and financial performance.
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Name, Province (State) and Country of ResidenceYear First Became DirectorPrincipal Occupation
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.
John Kousinioris
Alberta, Canada
2021
Mr. Kousinioris is the President and Chief Executive Officer of the Company, responsible for the overall stewardship of the Company, including strategic leadership. Previously, he was Chief Operating Officer of the Company, responsible for overseeing operations, shared services, commercial, trading, customer solutions, hedging and optimization. Prior thereto, Mr. Kousinioris was the Company’s Chief Growth Officer and Chief Legal and Compliance Officer. Mr. Kousinioris’ prior leadership roles have provided him with responsibility for almost every aspect of the Company’s business. He was also the President of TransAlta Renewables Inc. until February 5, 2021. Prior to joining TransAlta, Mr. Kousinioris was a partner and co-head of the corporate commercial department at Bennett Jones LLP. He has 30 years of experience in securities law, mergers and acquisitions and corporate governance matters. Mr. Kousinioris has a Bachelor of Arts degree in Honors Business Administration from the University of Western Ontario, a Master of Business Administration degree from York University and a Bachelor of Laws degree from Osgoode Hall Law School at York University. He has attended the Advanced Management Program at Harvard University. He is also Vice Chair of the Board of Governors of Bow Valley College and a member of the Board of Directors of the Calgary Stampede Foundation.
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Name, Province (State) and Country of ResidenceYear First Became DirectorPrincipal Occupation
Thomas O'Flynn
New Jersey, US
2021
Mr. O'Flynn is the Chief Financial Officer of Powin Energy, a battery energy storage company. Mr. O'Flynn is also a Venture Partner in Energy Impact Partners, a private energy technology fund investing in high-growth companies in the energy, utility and transportation industries, and also an investor in Powin. Mr. O'Flynn was the Chief Executive Officer and Chief Investment Officer, AES Infrastructure Advisors at the AES Corporation. Prior thereto he was Executive Vice President and Chief Financial Officer at AES Corporation and responsible for all aspects of global finance and M&A teams across six global regions. During his tenure, Mr. O’Flynn helped lead AES through a significant transformation, including strategic exits of non-core markets, that resulted in improved financial stability and allowed for the redeployment of cash to primary growth markets. AES's total shareholder return increased 54% during his tenure and its credit rating improved significantly. Mr. O’Flynn was also a key driver in initiating a major transition to renewables and green energy to significantly improve AES’s growth profile and reduce its carbon footprint. Prior to joining AES Corporation, Mr. O’Flynn was with the Blackstone Group Inc. where he was Senior Advisor, Power and Utility Sector, and Chief Operating Officer and Chief Financial Officer of Transmission Developers Inc., a Blackstone-controlled entity that develops innovative power transmission projects in an environmentally responsible manner. Prior thereto he was Executive Vice President and Chief Financial Officer at Public Service Enterprise Group Incorporated and was Head of North American Power at Morgan Stanley. Mr. O’Flynn has a Bachelor of Arts, in economics from Northwestern University and a Master of Business Administration, Finance from the University of Chicago. He is also currently on the Board of Directors of the New Jersey Performing Arts Center. He is also an adjunct professor at Northwestern University, for a Master’s Program in Energy Infrastructure Development and Finance. Mr. O’Flynn has demonstrated an ability to realize shareholder value through his significant senior executive experience at large electricity companies. He has led successful organizational transformations, including by focusing on acquisitions and greenfield development.
Beverlee F. Park
British Columbia, Canada
2015Ms. Park is the Chair of the Audit, Finance and Risk Committee of the Board. Ms. Park was previously a board member of SSR Mining Inc., 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 the Simon Fraser University Executive Program and is a Fellow of the Chartered Professional Accountants of British Columbia (FCPA, FCA). Ms. Park brings to the Company 35 years of experience in a range of industries.
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Name, Province (State) and Country of ResidenceYear First Became DirectorPrincipal Occupation
Bryan D. Pinney
Alberta, Canada
2018Mr. 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. He is also a director of one private company. Mr. Pinney was also the past chair of the Board of Governors of Mount Royal University and has previously served on a number of non-profit boards. Mr. Pinney has over 30 years of experience serving many of Canada's largest corporations, primarily in energy and resources and construction. 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. He was a partner at Andersen LLP and served as Calgary Managing Partner from 1991 through May 2002. 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's extensive leadership accomplishments, financial expertise, knowledge of regulatory and compliance matters and diverse range of industry experience make him an important contributor to the Company.
James Reid
Alberta, Canada
2021
Mr. Reid is the former Managing Partner of the Brookfield Private Equity Group based in Calgary, Alberta. In that role he was responsible for originating, evaluating and structuring investments and financings in the energy sector and overseeing operations in Brookfield's private equity energy segment. He established Brookfield’s Calgary office in 2003 after spending several years as a Chief Financial Officer for two oil and gas exploration and production companies in Western Canada. Mr. Reid obtained his Chartered Accountant designation at PricewaterhouseCoopers in Toronto and holds a Bachelor of Arts in commerce from the University of Toronto. Mr. Reid has considerable experience in leadership, finance, mergers and acquisitions and organizational change.
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Name, Province (State) and Country of ResidenceYear First Became DirectorPrincipal Occupation
Sandra R. Sharman
Ontario, Canada
2020
Ms. 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 US, 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.
Sarah A. Slusser
Washington, US
2021
Ms. Slusser is the Chief Executive Officer of Cypress Creek Renewables, LLC, (“Cypress Creek”) a solar and storage Independent Power Producer that develops, owns and operates projects in the US Cypress Creek owns a 1,600 MW operating fleet and has a 7,000 MW development pipeline. She joined Cypress Creek as CEO in 2019 to reposition the company for sustainable growth. Prior to joining Cypress Creek, she founded Point Reyes Energy Partners LLC, a solar and energy storage advisory and development company, where she provided strategic advice to a number of large companies in the renewable sector. She remains a founding partner of Point Reyes Energy Partners LLC. Prior to this, she co-founded GeoGlobal Energy LLC, a geothermal company in the US, Chile, and Germany, which was sold to its cornerstone investor in 2015. Before co-founding GeoGlobal Energy LLC, Ms. Slusser worked at the AES Corporation for 21 years, where she earned increasingly significant leadership roles. She ultimately became a Senior Vice President and Managing Director reporting directly to the CEO and led the corporate Mergers and Acquisitions group for the AES Corporation. She was President of one of eight Divisions of AES that was responsible for all development, construction and operations in the Caribbean, Mexico, and Central America. Ms. Slusser holds a Bachelor of Arts (cum laude) in geology from Harvard University and a Master of Business Administration from the Yale School of Management. She is a member of the Board of Directors of the Redwood Foundation, a family foundation promoting education and the environment and Our Food Chain, a non-profit promoting healthy eating.


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Officers
The name, province or state and country of residence of each of our executive officers as at February 23, 2022, their respective position and office and their respective principal occupation are set out below.
NamePrincipal OccupationResidence
John H. Kousinioris
President and Chief Executive OfficerAlberta, Canada
Todd J. StackExecutive Vice President, Finance & Chief Financial OfficerAlberta, Canada
Jane N. Fedoretz
Executive Vice President, People, Talent & TransformationAlberta, Canada
Kerry O'Reilly WilksExecutive Vice President, Legal, Commercial & External AffairsAlberta, Canada
Michael J. NovelliExecutive Vice President, GenerationAlberta, Canada
Blain van MelleExecutive Vice President, Alberta BusinessAlberta, Canada
Aron WillisExecutive Vice President, GrowthAlberta, Canada
Shasta R. Kadonaga
Senior Vice President, Shared ServicesAlberta, Canada
Brent V. WardSenior Vice President, M&A, Strategy & TreasurerAlberta, 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 Apr. 1, 2021, Mr. Kousinioris was appointed President and Chief Executive Officer. Prior to April 2021, Mr. Kousinioris was Chief Operating Officer of TransAlta. 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 Company.
•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 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 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.
•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 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.
•Prior to February 2021, Mr. van Melle was Senior Vice President, Trading & Commercial of TransAlta. Prior to August 2019, Mr. van Melle was Managing Director and Head Trader of TransAlta.
•Prior to February 2021, Mr. Willis was Senior Vice President, Growth of TransAlta. Prior to August 2019, Mr. Willis was Senior Vice President, Growth and Commercial of TransAlta. Prior to April 2019, Mr. Willis was Senior Vice President, Commercial, Gas & Renewables Operations of TransAlta. Prior to July 2018, Mr. Willis was Senior Vice President, Gas & Renewables of TransAlta.
•Prior to December 2020, Ms. Kadonaga was Managing Director, Operations Services of TransAlta, Manager, Operations Services of TransAlta.
•Prior to February 2021, Mr. Ward was Managing Director & Treasurer of TransAlta.
As of February 23, 2022, 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.

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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 2022 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. On May 4, 2021 Mr. Legault resigned from the Board and Mr. James Reid was elected as the Brookfield nominee. See "Directors and Officers" section of this AIF. Brookfield is also entitled to receive certain funding fees, management fees and interest and dividends on its $750 million investment. Also, 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" sections of this AIF.
Indebtedness of Directors, Executive Officers and Senior Officers
Since Jan. 1, 2021, 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
Except as noted below, no director, executive officer or controlling security holder of the Company 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.
Mr. Reid is a director of Second Wave Petroleum Inc. ("SWP"), a private oil and gas exploration and production company. On June 30, 2017, SWP made an assignment into bankruptcy pursuant to the Bankruptcy and Insolvency Act (Canada) ("BIA"). On Sept. 7, 2017, SWP made a proposal under the BIA and on Oct. 5, 2017, the proposal was approved by the Court of Queen's Bench of Alberta and the bankruptcy was annulled.
Personal Bankruptcies
No director, executive officer or controlling security holder of the Company 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 the Company 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.
Material Contracts
Other than contracts entered into in the ordinary course of business, the Company believes that the following are material contracts, the particulars of which are disclosed elsewhere in this AIF, to which the Company or its subsidiaries are a party:
•Investment Agreement - See "Capital and Loan Structure - Investment Agreement and E&O Agreement" section of this AIF.
•E&O Agreement - See "Capital and Loan Structure - Investment Agreement and E&O Agreement" section of this AIF.
•Registration Rights Agreement - See "Capital Structure - Registration Rights Agreement" section of this AIF.
•Off-Coal Agreement - See "Business of TransAlta - Alberta Thermal Business Segment - Off-Coal Agreement" section of this AIF.
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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 36 of our audited consolidated financial statements for the year ended Dec. 31, 2021, which financial statements are incorporated by reference herein. Also, see "Documents Incorporated by Reference" section of this AIF.
FMG Dispute at South Hedland Power Station
On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.
Mangrove Claim
On April 23, 2019, the Mangrove commenced an action in the Ontario Superior Court of Justice, naming the Company, the incumbent members of the Board of Directors of the Company on such date, and Brookfield, as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021.
Keephills 1 Stator Force Majeure Appeal
The Balancing Pool and 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 was heard on July 8, 2021. After the hearing, counsel for ENMAX raised concerns that one of the three justices on the appeal panel was distracted during the hearing. The justice has since recused herself from the hearing and the parties made submissions with respect to whether the remaining two justices can continue to issue the decision or whether a new hearing is required. On Nov. 8, 2021, the Alberta Court of Appeal released its decision and ordered that the appeal be re-heard by a new three-person panel of the Court of Appeal, which was heard on Jan. 27, 2022. The Company remains of the view 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 claimed force majeure under the Alberta PPA. ENMAX, the purchaser under the Alberta PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.
Hydro Power Purchase Arrangement ("Hydro PPA") Emission Performance Credits
The Balancing Pool claims to be entitled to emissions performance credits earned by the hydro facilities as a result of opting those facilities into the Carbon Competitiveness Incentive Regulation from 2018-2020 inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change in law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs or from any purported change in law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced and the hearing is scheduled for February 6-10, 2023.

Kaybob 3 Cogeneration Dispute
The Company is engaged in a dispute with Energy Transfer Canada ULC, formerly SemCAMS Midstream ULC (“ET Canada”) as a result of ET Canada’s purported termination of agreements between the parties to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing facility. The Company commenced an arbitration seeking full compensation for ET Canada's wrongful termination of the agreements. ET Canada seeks a declaration that the agreements were lawfully terminated. A hearing is scheduled for two weeks starting Jan. 9, 2023.
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Sarnia Outages
The Sarnia cogeneration facility experienced three separate outages between May 19, 2021, and June 9, 2021, that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent at the Sarnia cogeneration facility. The Company conducted an investigation to determine the root cause of each of the three events, which concluded all three events do not qualify as events of force majeure. As such, liquidated damages in an amount dictated by the applicable agreements are payable by TransAlta to the customers for the three outages.
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 2022 or early 2023. TransAlta expects to receive payment from the Balancing Pool for its decommissioning costs; however, the amount that the AUC will award is uncertain.
Transmission Line Loss Rule Proceeding
The Company 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. The AUC approved an invoice settlement process and all three planned settlements have been received. The first two invoices were settled by the first quarter of 2021 and the third invoice settled in the second quarter of 2021. The true-up invoices issued by the AESO in the fourth quarter of 2021 were settled by Dec. 31, 2021 with no further invoices expected.
Direct Assigned Capital Deferral Account ("DACDA") Application
AltaLink Management Ltd. ("AltaLink") and TransAlta (as a secondary applicant) filed an application before the AUC to recover its 2016-2018 DACDA costs incurred for the 240 kV line upgrades for the Edmonton Region Project. The AUC disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta disputed this finding and filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC. The AUC dismissed the application on April 22, 2021. The permission to appeal was subsequently discontinued on July 5, 2021, which concludes this matter.
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 US is Computershare Trust Company at its principal office in Jersey City, New Jersey.
Interests of Experts
The Company'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 the Company 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, 2021, and in the related annual management's discussion and analysis, each of which is incorporated by reference in this AIF. See "Documents Incorporated by Reference" section of this AIF.
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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 the Canadian Securities Administrators, 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, Thomas M. O'Flynn and Bryan D. Pinney.
All members of the committee are financially literate pursuant to both Canadian and US securities requirements and each member of the AFRC has also been determined by the Board to be an "audit committee financial expert," within the meaning of Section 407 of the US 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 Company'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 Company.
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 Company 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 that provide reasonable assurance that the assets of the Company 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 Company'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 Company'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 Company'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.
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Name of AFRC MemberRelevant Education and Experience
Alan J. FohrerPrior to his retirement in December 2010, Mr. Fohrer was Chairman and CEO of SCEC, 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 SCEC. Mr. Fohrer also serves on the audit committee of PNM Resources Inc., a public company. Mr. Fohrer holds a Master of Business Administration from California State University in Los Angeles.
Thomas M. O'FlynnMr. O'Flynn is the Chief Financial Officer of Powin Energy, an entity in which Energy Impact Partners LP (a private energy technology fund) is a major investor. Prior thereto Mr. O'Flynn was Chief Executive Officer and Chief Investment Officer at The AES Corporation, Executive Vice President and Chief Financial Officer at Public Service Enterprise Group Incorporated and Head of North American Power at Morgan Stanley. Mr. O'Flynn has a Bachelor of Arts in economics from Northwestern University and a Master of Business Administration, Finance from the University of Chicago.
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 was named a Fellow of the Chartered Professional Accountants of British Columbia in 2011.
Bryan D. PinneyMr. 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, 2021 are:
Governance, Safety and Sustainability CommitteeHuman Resources Committee
Chair: Rona H. Ambrose
Chair: Bryan D. Pinney
Sandra R. SharmanRona H. Ambrose
Laura W. FolseSandra R. Sharman
Alan J. FohrerBeverlee F. Park
Sarah A. Slusser
Investment Performance Committee
Chair: Laura W. Folse
Thomas M. O'Flynn
Harry Goldgut
James Reid
Sarah A. Slusser
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.

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Fees Paid to Ernst & Young LLP
For the years ended Dec. 31, 2021 and Dec. 31, 2020, Ernst & Young LLP and its affiliates billed $3,724,342 and $4,253,798, respectively, as detailed below.
Ernst & Young LLP
Year Ended December 3120212020
Audit Fees(1)
$2,453,917$2,273,888
Audit-related fees(1)(2)
1,270,4251,122,771
Tax fees— 857,139
All other fees— — 
Total$3,724,342$4,253,798
(1) Comparative figures have been reclassified to conform to the current periods classification of fees.
(2) Included in the audit-related fees are $844,167 (2020 — $722,733) of fees billed to TransAlta Renewables.

No other audit firms provided audit services in 2021 or 2020.
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 in the Audit Fees. Audit-related fees include statutory audits, pension audits and other compliance audits. In 2021 and 2020, 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 Company'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 ("Committee") of the Board of Directors ("Board") of TransAlta Corporation ("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 US 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 ("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 ("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.
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.
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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.

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.

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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.

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;

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(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.

(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;

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(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 US regulatory registration requirements; and (e) evaluating the communication and interaction with the external auditor including quality of service considerations;

(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

A- 5

(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.
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;

A- 6

(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

(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

A- 7

(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.

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 US 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.

A- 8

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.
"EBITDA" – Earnings before interest, taxes, depreciation, and amortization.
"ED&I" – Equity, Diversity and Inclusion.
"ESG" – Environment, Sustainability 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.
B- 1

"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.
"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
Forward-Looking Statements
M2
Description of the Business
M4
Alberta Electricity Portfolio
M7
Accelerated Clean Electricity Growth Plan
M9
Highlights
Significant and Subsequent Events
Segmented Financial Performance and Operating Results
Fourth Quarter Highlights
Segmented Financial Performance and Operating Results for the Fourth Quarter
Selected Quarterly Information
Financial Position
Financial Capital
Other Consolidated Analysis
Cash Flows
Financial Instruments
Additional IFRS Measures and Non-IFRS Measures
Financial Highlights on a Proportional Basis of TransAlta Renewables
Key Non-IFRS Financial Ratios
2022 Financial Outlook
Critical Accounting Policies and Estimates
Accounting Changes
Environment, Social and Governance ("ESG")
Transforming Our Business Model to Become Carbon Neutral by 2050
2022+ Sustainable Targets
Our 2021 Sustainability Performance
Decarbonizing Our Energy Mix
Engaging with Our Stakeholders to Create Positive Relationships
Building a Diverse and Inclusive Workforce
Progressive Environmental Stewardship
Reliable, Low-Cost and Sustainable Energy Production
Technology Adoption and Innovation Focus
Sustainability Governance
Governance and Risk Management
Disclosure Controls and Procedures
 

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with our 2021 audited annual consolidated financial statements (the "consolidated financial statements") and our 2021 annual information form ("AIF"), each for the fiscal year ended Dec. 31, 2021. 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, 2021. 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 February 23, 2022. Additional information respecting TransAlta Corporation (“TransAlta”, “we”, “our”, “us” or the “Company”), 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

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, statements relating to: our Clean Electricity Growth Plan and ability to achieve the target of 2 gigawatts ("GW") of incremental renewables capacity with an investment of $3 billion by 2025; the Company's future growth pipeline, including the timing of commercial operations and the costs of the advanced and early-stage projects; expansion of the Company's development pipeline to 5 GW; the White Rock East and White Rock West Wind Power Projects ("White Rock Wind Projects"), including the total construction costs, ability to secure tax equity financing, the timing of commercial operation and expected average earnings before interest, taxes, depreciation and amortization ("EBITDA"); the proportion of EBITDA to be generated from renewable sources by the end of 2025; the suspension of the Sundance 5 repowering project; expected average annual EBITDA of the North Carolina Solar (as defined below) portfolio; the incident at the Kent Hills 1 and 2 wind facilities and the extent of any remediation, the timing and cost of such remediation, the ability to secure waivers in respect of the Kent Hills bonds for any potential event of default, and the impact such incident could have on the Company's revenues and contracts; the Northern Goldfields Solar Project, including the total construction capital and expected average annual EBITDA; the Garden Plain wind project, including construction capital and expected average annual EBITDA; expected increases to our cost per tonne of coal at Centralia; the expected impact and quantum of carbon compliance costs; the ability to realize future growth opportunities with BHP (as defined below); regulatory developments and their expected impact on the Company, including the Canadian federal climate plan and the implementation of the major aspects thereof (including increased carbon pricing and increased funding for clean technology); the ability of the Company to realize benefits from Canadian, US and Australian regulatory developments, including receiving funding for clean electricity projects; the potential increase in value of emission reduction credits; the 2022 financial outlook, including adjusted EBITDA, free cash flow ("FCF") and annualized dividend in 2022; increased gross margin contribution from Energy Marketing; hedged production and price for the full year 2022; hedged gas volume and gas price for 2022; sustaining and productivity capital in 2022, including routine capital, planned major maintenance and mine capital; significant planned major outages for 2022 and lost production due to planned major maintenance for 2022; expected power prices in Alberta, Ontario and the Pacific Northwest; the cyclicality of the business, including as it relates to maintenance costs, production and loads; expectations regarding refinancing the debt maturing in 2022; the liquidated damages potentially payable in respect of the Sarnia cogeneration facility outages in the second quarter of 2021; and the Company continuing to maintain a strong financial position and significant liquidity.





TRANSALTA CORPORATION M2
Management’s Discussion and Analysis

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 Company; no significant changes to applicable laws and regulations beyond those that have already been announced; no significant changes to the fuel and purchased power costs; no material adverse impacts to the long-term investment and credit markets; Alberta spot prices of $80/MWh to $90/MWh in 2022; Mid-Columbia spot prices of US$45/MWh to US$55/MWh in 2022; sustaining capital of $150 million to $170 million; the Company's proportionate ownership of TransAlta Renewables Inc. ("TransAlta Renewables") not changing materially; no decline in the dividends to be received from TransAlta Renewables; and the growth of TransAlta Renewables. Forward-looking statements are subject to a number of significant risks and uncertainties 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 risks relating to: the impact of COVID-19, including more restrictive directives of government and public health authorities; increased force majeure claims; 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; our ability to obtain regulatory approvals on the expected timelines or at all in respect of our growth projects; restricted access to capital and increased borrowing costs; changes in short-term and/or long-term electricity supply and demand; fluctuations in market prices, including lower merchant pricing in Alberta, Ontario and Mid-Columbia; reductions in production; increased costs; a higher rate of losses on our accounts receivables due to credit defaults; impairments and/or write-downs of assets; adverse impacts on our information technology systems and our internal control systems, including increased cybersecurity threats; commodity risk management and energy trading risks, including the effectiveness of the Company’s risk management tools associated with hedging and trading procedures to protect against significant losses; 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; operational risks involving our facilities, including unplanned outages; disruptions in the transmission and distribution of electricity; the effects of weather, including man-made or natural disasters and other climate-change related risks; unexpected increases in cost structure; reductions to our generating units’ relative efficiency or capacity factors; disruptions in the source of fuels, including natural gas and coal, as well as the extent of water, solar or wind resources required to operate our facilities; general economic risks, including deterioration of equity markets, increasing interest rates or rising inflation; failure to meet financial expectations; general domestic and international economic and political developments, including armed hostilities, the threat of terrorism, including cyberattacks, diplomatic developments or other similar events that could adversely affect our business; equipment failure and our ability to carry out or have completed the repairs in a cost-effective manner or timely manner or at all, including if the remediation at the Kent Hills 1 and 2 wind facilities is more costly or takes longer than expected; industry risk and competition; fluctuations in the value of foreign currencies; structural subordination of securities; counterparty credit risk; changes to our relationship with, or ownership of, TransAlta Renewables; changes in the payment or receipt of future dividends, including from 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; inadequacy or unavailability of insurance coverage; our provision for income taxes; legal, regulatory and contractual disputes and proceedings involving the Company; 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, 2021.

Readers are urged to consider these factors carefully in evaluating the forward-looking statements, which reflect the Company's expectations only as of the date hereof, and are cautioned not to place undue reliance on them. 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 M3
Management’s Discussion and Analysis


Description of the Business
Portfolio of Assets
TransAlta is a Canadian corporation and one of Canada's largest publicly traded power generators with over 110 years of operating experience. We own, operate and manage a geographically diversified portfolio of assets utilizing a broad range of fuels that includes water, wind, solar, natural gas and thermal coal.

The following table provides our consolidated ownership of our facilities across the regions in which we operate as at Dec. 31, 2021:
As at Dec. 31, 2021Hydro
Wind and Solar(4)
Gas(4)(5)
Energy Transition(6)
Total
Alberta
Gross installed capacity (MW)(1)
834 636 1,960 801 4,231 
Number of facilities17 13 7 2 39 
Weighted average contract life(2)
— 7 1 — 2 
Canada, Excl. Alberta
Gross installed capacity (MW)(1)
91 751 645 — 1,487 
Number of facilities9 9 3 — 21 
Weighted average contract life(3)
7 10 6 — 8 
US
Gross installed capacity (MW)(1)
— 519 29 671 1,219 
Number of facilities— 7 1 2 10 
Weighted average contract life(3)
— 12 4 4 8 
Australia
Gross installed capacity (MW)(1)
— — 450 — 450 
Number of facilities— — 6 — 6 
Weighted average contract life(3)
— — 17 — 17 
Total
Gross installed capacity (MW)(1)
925 1,906 3,084 1,472 7,387 
Number of facilities26 29 17 4 76 
Weighted average contract life(3)
1 9 5 2 5 
(1) Gross installed capacity for consolidated reporting represents 100 per cent output of a facility. Capacity figures for Wind and Solar includes 100 per cent of the Kent Hills wind facilities; Gas includes 100 per cent of the Ottawa and Windsor facilities, 100 per cent of the Poplar Creek facility, 50 per cent of the Sheerness facility and 60 per cent of the Fort Saskatchewan facility.
(2) The weighted average contract life for the assets in Alberta are nil as it is operating primarily on a merchant basis in the Alberta market. Refer to the Alberta Electricity Portfolio section for more information.
(3) For power generated under long-term power purchase agreements ("PPA"), power hedge contracts and short- and long-term industrial contracts, the PPAs have a weighted average remaining contract life (based on gross long-term average gross installed capacity).
(4) The weighted average remaining contract life is related to the contract period for the McBride Lake (38 MW), the Windrise facility (206 MW), Poplar Creek facility (115 MW) and the Fort Saskatchewan facility (71 MW), with remaining wind and gas facilities operated on a merchant basis.in the Alberta market.
(5) Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal generation assets converted to gas from the segment previously known as Alberta Thermal.
(6) Energy Transition segment includes the segment previously known as Centralia and the coal generation assets not converted to gas (including Sundance 4) and mining assets from the segment previously known as Alberta Thermal.

Our Clean Energy Investment Plan, announced in 2019, included converting our existing Alberta coal assets to natural gas and advancing our leadership position in renewable electricity. To date, we have retired 4,064 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas, significantly reducing our carbon footprint. During 2021, we increased our renewable fleet by 334 MW through acquisitions and construction of renewable wind and solar facilities and on Sept 28, 2021, we announced a Clean Electricity Growth Plan that includes strategic growth targets. Please refer to the Accelerated Clean Electricity Growth Plan section of this MD&A for further information.

Approximately 57 per cent of our gross installed capacity is located in Alberta. Our portfolio of merchant assets in Alberta is a combination of hydro facilities, wind facilities, a battery storage facility 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. Please refer to the Alberta Electricity Portfolio section of this MD&A for further information.






TRANSALTA CORPORATION M4
Management’s Discussion and Analysis

Clean Energy Transition
The Company has completed the conversion to gas at its Alberta facilities that were formerly fuelled by coal; these facilities are now running solely on gas. The Company retired the Highvale coal mine effective Dec. 31, 2021, and is no longer mining coal. Our Centralia coal-fired facility in Washington State is committed to be retired under the TransAlta Energy Transition Bill by 2025. Centralia Unit 1 retired on Dec. 31, 2020, and the remaining unit, Centralia Unit 2, is scheduled to retire on Dec. 31, 2025.

The following table shows the Company's completed conversions to gas:
ProjectMW
Cumulative Conversion Project Spend(1)
  Project Completion Date
Keephills Unit 3463 $31 Q4 2021
Keephills Unit 2395 $34 Q2 2021
Sundance Unit 6401 $39 Q1 2021
Sheerness Unit 1(2)
200$7 Q1 2021
Sheerness Unit 2(2)
200$14 Q1 2020
(1) Conversion project spend only includes costs associated with the conversion to gas-burning technology. Any additional planned major maintenance has been included as part of sustaining capital spend.
(2) These facilities are jointly owned by TransAlta Cogeneration L.P. ("TA Cogen") and Heartland Generation Ltd. This represents the portion of the 400 MW facility consolidated by the Company.

During the 2021 Investor Day, the Company announced its decision to retire Keephills Unit 1 and Sundance Unit 4 effective Dec. 31, 2021, and April 1, 2022, respectively. The retirement decisions were largely driven by TransAlta's assessment of future market conditions, the age and condition of the units and the Company's strategic focus on customer-centred renewable energy solutions. As a result of the decision to retire these units, the Company recorded impairment charges of $94 million and $56 million, respectively, on these units based on the estimated salvage value.

Following an in-depth evaluation and assessment of the Sundance Unit 5 repowering project, the Company suspended the project. The decision was made due to escalating costs, changing supply and demand dynamics and forecasted power prices in the Alberta market, as well as risks associated with carbon pricing and the evolving regulatory environment. With the suspension of the project, the Company will redeploy the capital previously allocated to the Sundance Unit 5 repowering project to renewable growth projects. The Company recorded an impairment charge of $191 million in 2021 in relation to the project. The total remaining estimated recoverable amount and salvage value for the Sundance Unit 5 repowering project was $33 million. Of this amount, $25 million was related to assets held for sale. Included in the impairment charge was $141 million for assets under construction and $50 million for the balance of the plant steam equipment. An additional $20 million was expensed for amounts due under contracts as a result of the suspension of the project.

With the suspension of the Sundance Unit 5, we have also impaired a previously recognized deferred asset, as it is no longer likely that we will incur sufficient capital or operating expenditures to utilize the remaining credit. The Company impaired the remaining balance of the credit of $10 million (US$8 million) in 2021.

The Highvale mine is no longer considered to be providing significant economic benefit to the Alberta Merchant cash-generating unit ("CGU") and it has been removed from the CGU, which resulted in an impairment recognized in 2021 of $195 million. An onerous contract provision of $14 million relating to future Highvale mine royalty payments (2022 and 2023), has also been recognized as an expense in 2021.

With the successful completion of the Keephills Unit 3 conversion on Dec. 29, 2021, and the planned closure of the Highvale coal mine effective Dec. 31, 2021, TransAlta’s thermal facilities in Alberta have been fully transitioned to 100 per cent natural gas operation. We have reduced our CO2 emissions by 61 per cent from 2015 levels.





TRANSALTA CORPORATION M5
Management’s Discussion and Analysis

Reporting Segment Changes
With the completion of the Clean Energy Transition plan and the announcement of our strategic focus on customer-centred renewable generation, the Company has realigned its current operating segments to better reflect its current strategic focus and to align with the Company's Clean Electricity Growth Plan. The segment reporting changes reflect a corresponding change in how the Chief Executive Officer assesses the performance of the Company.

The primary changes are the elimination of the Alberta Thermal and the Centralia segments and the reorganization of the North American Gas and Australia Gas segments into a new "Gas" segment. The Alberta Thermal facilities that have been converted to gas are included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new "Energy Transition" segment. No changes have been made to the Hydro, Wind and Solar, Energy Marketing or the Corporate and Other segments. Please refer to the Segmented Financial Performance and Operating Results section of this MD&A for further information.

Performance by Segment with Supplemental Geographical Information
The following table provides the performance of our facilities across the regions we operate in as at Dec. 31, 2021, and Dec. 31, 2020:
Year ended Dec. 31, 2021HydroWind and Solar
Gas(1)
Energy Transition(2)
Energy MarketingCorporate and OtherTotal
Alberta308 63 269 59 — (85)614 
Canada, excl. Alberta14 120 75 — 137 — 346 
US— 79 10 74 — — 163 
Australia— — 140 — — — 140 
Total adjusted EBITDA(3)
322 262 494 133 137 (85)1,263 
Loss before income taxes(380)
Year ended Dec. 31, 2020HydroWind and Solar
Gas(1)
Energy Transition(2)
Energy MarketingCorporate and OtherTotal
Alberta88 18 151 36 — (81)212 
Canada, excl. Alberta17 153 88 — 113 — 371 
US— 77 4 139 — — 220 
Australia— — 124 — — — 124 
Total adjusted EBITDA(3)
105 248 367 175 113 (81)927 
Loss before income taxes(303)
(1) Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal generation assets converted to gas from the segment previously known as Alberta Thermal.
(2) Energy Transition segment includes the segment previously known as Centralia and the coal generation assets not converted to gas and mining assets from the segment previously known as Alberta Thermal.
(3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Presenting this 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 Segmented Financial Performance and Operating 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.





TRANSALTA CORPORATION M6
Management’s Discussion and Analysis

Alberta Electricity Portfolio
Generating capacity in Alberta is 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 Alberta Electric System Operator ("AESO"), based upon offers by generators to sell power in the real-time energy-only market. Our merchant Alberta fleet operates under this framework and we internally manage our offers to sell power.

On Dec. 31, 2020, the legislated Alberta Power Purchase Arrangements ("Alberta PPA") for our Alberta hydro assets ("Alberta Hydro Assets"), Sheerness 1 and 2 Units, and the Keephills 1 and 2 Units expired. Effective Jan. 1, 2021, these facilities began operating on a fully merchant basis in the Alberta market and form a core part of our Alberta portfolio optimization activities.

The Alberta Electricity Portfolio generated gross margin of $864 million, an increase of $405 million compared to the same period in 2020. This performance was driven by strengthened power prices in the province, optimization of production during periods of favourable pricing, partially offset by higher natural gas and carbon pricing and higher transmission costs. Optimization of facilities is driven by the diversity in fuel types, which enables portfolio management and allows for maximization of operating margins. A portion of the baseload generation in the portfolio is hedged to provide cash flow certainty. The portfolio consists of hydro, wind, energy storage and natural gas units operating, primarily, on a merchant basis in the Alberta market. Prior to 2022, the Alberta Electricity Portfolio also included coal units, which are now either retired, have been converted to natural gas or will only operate on gas. Sundance Unit 4 will continue to operate within the portfolio, fuelled only by gas, until its retirement date on April 1, 2022.

Alberta's annual demand expanded approximately 3.0 per cent from 2020 to 2021 as the economy recovered from the impacts of the COVID-19 pandemic and stronger market conditions for energy commodities supported power demand in the province. The average pool price increased from $47/MWh in 2020 to $102/MWh in 2021. Pool prices were higher in each quarter compared to 2020, generally as a result of competition among generators, higher demand in the province, tighter supply conditions due to higher planned outages, and higher natural gas and carbon prices. In addition, in 2021, Alberta experienced very strong weather-driven demand in February, June, July and December.



chart-1ffd97ba6c444cb4a32a.jpg




202120202019
Year ended Dec. 31HydroWind & SolarGasEnergy TransitionTotalHydroWind & SolarGasEnergy TransitionTotalHydroWind & SolarGasEnergy TransitionTotal
Total Production (GWh)(1)
1,586 1,319 7,281 2,591 12,777 1,779 1,320 7,732 2,865 13,696 1,715 1,058 8,691 4,698 16,162 
Revenues358 97 680 257 1,392 126 57 482 207 872 132 59 519 334 1,044 
Fuel and purchased power13 9 258 92 372 6 15 151 73 245 4 6 151 84 245 
Carbon compliance— — 96 60 156 — — 120 48 168 — — 138 77 215 
Gross margin345 88 326 105 864 120 42 211 86 459 128 53 230 173 584 
(1) Units in the Gas and Energy Transition segment in the current and prior years may have operated on coal.




TRANSALTA CORPORATION M7
Management’s Discussion and Analysis

The following table provides information for the Company's Alberta Electricity Portfolio:

Year ended Dec. 31202120202019
Spot power price average per MWh$102 $47 $55 
Natural gas price (AECO) per GJ$3.39 $2.11 $1.68 
Carbon cost per tonne$40 $30 $20 
Realized power price per MWh(1)
$109 $64 $65 
Hydro energy realized power price per MWh$122 $51 $61 
Hydro ancillary realized price per MWh$55 $23 $30 
Wind energy realized power price per MWh$63 $33 $38 
Gas and Energy Transition realized power price per MWh$102 $71 $64 
Hedged volume (MW)(2)
6,992 5,395 5,187 
Hedge position (percentage)(3)
75 100 87 
 Hedged power price average per MWh(2)
$72 $54 $55 
Fuel and purchased power per MWh(4)
$38 $23 $18 
Carbon compliance cost per MWh(4)
$16 $16 $16 
(1) Realized power price for the Alberta Electricity Portfolio is the average price realized as a result of the Company's commercial contracted sales and portfolio optimization activities divided by total GWh produced.
(2) In 2020 and 2019, much of the portfolio in Alberta was still under PPAs and the PPA volumes are not included in the total hedged volumes listed above.
(3) Represents the percentage of production sold forward at the end of the reporting period for the Gas assets only. The hedge program is focused primarily on generation from the merchant Gas and Energy Transition assets.
(4) Fuel and purchased power per MWh and carbon compliance cost per MWh are calculated over production from carbon-emitting generation segments in Gas and Energy Transition.

For the year ended Dec. 31, 2021, the realized power price per MWh of production increased by $45 per MWh, compared with the same period in 2020, primarily due to the optimization of production during periods of favourable pricing. The realized prices include gains and losses from hedging positions that are entered into in order to mitigate the impact of unfavourable market pricing.

For the year ended Dec. 31, 2021, the fuel and purchased power cost per MWh of production increased by $15 per MWh compared to the same period in 2020. Cost per MWh increased due to higher natural gas pricing, higher coal mine depreciation and coal inventory write-downs at the Highvale mine and higher transmission costs.

For the year ended Dec. 31, 2021, carbon compliance costs per MWh of production were consistent with the same period in 2020. Carbon compliance costs have increased in 2021 primarily due to an increase in carbon price from $30 per tonne to $40 per tonne; however, this was substantially offset by changes in fuel ratios as we increased our natural gas combustion compared to coal. The shift in fuel ratio effectively lowered our greenhouse gas ("GHG") compliance costs as natural gas combustion produces fewer GHG emissions than coal combustion.






TRANSALTA CORPORATION M8
Management’s Discussion and Analysis

Accelerated Clean Electricity Growth Plan
On Sept. 28, 2021, TransAlta announced its strategic growth targets and Accelerated Clean Electricity Growth Plan. Our goal is to be a leading customer-centred electricity company, committed to a sustainable future, focused on increasing shareholder value by growing our portfolio of high quality generation facilities with stable and predictable cash flows. Our strategy includes meeting our customers' needs for clean, low-cost, reliable electricity and providing operational excellence and continuous improvement in everything we do.

The Company's enhanced focus on renewable generation and storage solutions for customers is driven largely by global decarbonization policies and the increase in demand and growth projections in the renewable sector, namely for companies to achieve their environment, social and governance ("ESG") ambitions. For additional information on regulatory developments, see the ESG section of this MD&A.

We are primarily evaluating greenfield opportunities in Alberta, Western Australia 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.

Our Accelerated Clean Electricity Growth Plan has established the following strategic priorities and targets to guide our path from 2021 to 2025. These include:
▪Deliver 2 GW of incremental renewable capacity with a targeted capital investment of $3 billion by the end of 2025. These new assets, once fully operational are targeted to deliver incremental average annual EBITDA1 of $250 million;
▪Accelerate growth into customer-centred renewables and storage through the deployment of our 3 GW development pipeline;
▪Expand the Company's development pipeline to 5 GW by 2025 to enable a two-fold increase in its renewables fleet between 2025 and 2030;
▪Realize targeted diversification and value creation by focusing on expanding our platform in each of our core geographies (Canada, United States and Australia);
▪Lead in ESG policy development to enable the successful evolution of the markets in which we operate and compete; and
▪Define the next generation of power solutions and technologies and potential for parallel investments in new complementary sectors by the end of 2025.

We expect the Company's EBITDA generated from renewable sources, including hydro, wind, and solar technologies, to increase from 35 per cent to 70 per cent by the end of 2025.

The Clean Electricity Growth Plan will largely be funded from current cash balances, cash generated from operations, and asset-level financing.

Growth
In 2021, the Company announced 600 MW of new build projects and asset acquisitions and has 240 MW in advanced-stage development. In addition, the current growth pipeline has a potential capacity ranging from 2,085 MW to 2,685 MW from projects in the early stages of development.
Announced Acquisition
North Carolina Solar
On Nov. 5, 2021, the Company closed the previously announced acquisition of a 122 MW portfolio of operating solar sites located in North Carolina (collectively, “North Carolina Solar”). The North Carolina Solar facility consists of 20 solar photovoltaic sites across North Carolina. The sites were commissioned between November 2019 and May 2021 and are all operational. The facility is secured by long-term PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each site. The North Carolina Solar facility is expected to generate an average annual EBITDA1 of approximately US$9 million and average annual cash available for distribution of approximately US$7 million.


1 Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.




TRANSALTA CORPORATION M9
Management’s Discussion and Analysis

Projects under Construction
The following projects have been approved by the Board of Directors ("the Board"), have executed PPAs and are currently under construction. The projects under construction will be financed through existing liquidity in the near term. We will continue to explore project financing or tax equity as a long-term financing solution on an asset-by-asset basis.
 Total project
Target completion date(1)
ProjectTypeRegionMWEstimated
spend		Spent to
date		PPA Term
Average annual EBITDA(2)
Status
Projects Under Construction or Approved for Construction
Canada
Garden Plain(3)
WindAB130$190 —$200$37H2 202218$14 - $18
•Secured all required permits and approvals
•Construction activities commenced in Q4 2021
•On track to be completed on schedule
United States
White Rock WindWindOK300US$460 —US$470US$30H2 2023US$42 - US$46
•Long-term PPA executed
•All major equipment supply and EPC agreements executed
•Detailed design and final permitting on track
Australia
Northern Goldfields SolarHybrid SolarWA48AU$69—AU$73AU$15H2 202216AU$9 - AU$10
•Final Notice to Proceed issued on Sept. 28, 2021
•On track to be completed on schedule
(1) H2 is defined as the second half of the year
(2) This item is not defined and has no standardized meaning under IFRS and is forward-looking. Please refer to the Additional IFRS measures and Non-IFRS Measures section of this MD&A for further discussion.
(3) The Garden Plain PPA with Pembina Pipeline Corporation ("Pembina") is for 100 MW of the total 130 MW capacity of the facility.

Advanced-Stage Development
These projects have detailed engineering, advanced position in the interconnection queue and are progressing offtake opportunities. The following table shows the pipeline of future growth projects currently under advanced-stage development:
ProjectTypeRegionGross Installed Capacity (MW)Estimated Spend
Average Annual EBITDA(1)
Advanced-Stage Development
Horizon HillWindOklahoma200US$290 - US$310US$25 - US$35
Mount Keith 132kV ExpansionTransmissionWestern Australian/aAU$50 - AU$53AU$6 - AU$7
Mount Keith Capacity ExpansionGasWestern Australia40AU$80 - AU$100AU$9 - AU$12
(1) This item is not defined and has no standardized meaning under IFRS and is forward-looking. Please refer to the Additional IFRS measures and Non-IFRS Measures section of this MD&A for further discussion.





TRANSALTA CORPORATION M10
Management’s Discussion and Analysis

Early-Stage Development
These projects are in the early stages and may or may not move ahead. Generally, these projects will have:
▪Collected meteorological data;
▪Begun securing land control;
▪Started environmental studies;
▪Confirmed appropriate access to transmission; and
▪Started preliminary permitting and other regulatory approval processes.

The following table shows the pipeline of future growth projects currently under early-stage development:
ProjectTypeRegionGross Installed Capacity (MW)
Early-Stage Development
Canada
Riplinger WindWindAlberta300 
Willow Creek 1WindAlberta70 
Willow Creek 2WindAlberta70 
TempestWindAlberta100 
WaterChargerBattery StorageAlberta180 
Sunhills SolarSolarAlberta85 
Alberta Solar OpportunitiesSolarAlberta35 
Canadian Wind OpportunitiesWindVarious200 
Brazeau Pumped HydroHydroAlberta300 - 900
Total1,340 - 1,940
US
Prairie VioletWindIllinois130 
Old TownWindIllinois185 
Big TimberWindPennsylvania50 
Other US Wind ProspectsWindVarious240 
Total605 
Australia
Goldfields ExpansionsGas, Solar and WindWestern Australia90 
South Hedland SolarSolarWestern Australia50 
Total140 
Canada, US and AustraliaTotal2,085 - 2,685





TRANSALTA CORPORATION M11
Management’s Discussion and Analysis

Highlights
Consolidated Financial Highlights
Year ended Dec. 31202120202019
Adjusted availability (%)86.6 90.7 90.0 
Production (GWh)22,105 24,980 29,071 
Revenues2,721 2,101 2,347 
Fuel and purchased power(1)
1,054 805 881 
Carbon compliance(1)
178 163 205 
Operations, maintenance and administration511 472 475 
Adjusted EBITDA(2,3,7)
1,263 927 984 
Earnings (loss) before income tax(380)(303)193 
Net earnings (loss) attributable to common shareholders(576)(336)52 
Cash flow from operating activities1,001 702 849 
Funds from operations(2,3)
971 685 757 
Free cash flow(2,3)
562 358 435 
Net earnings (loss) per share attributable to common shareholders, basic and
    diluted		(2.13)(1.22)0.18 
Dividends declared per common share(4)
0.19 0.22 0.12 
Dividends declared per preferred share(5)
1.02 1.27 0.78 
Funds from operations per share(2,3,8)
3.58 2.49 2.67 
Free cash flow per share(2,3,8)
2.07 1.30 1.54 
As at Dec. 31202120202019
Total assets9,226 9,747 9,508 
Total consolidated net debt(3,6)
2,636 2,974 3,110 
Total long-term liabilities
4,702 5,376 4,329 
Total liabilities6,633 6,311 5,446 
(1) Carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes and did not impact previously reported net earnings.
(2) Includes $56 million received on settlement of the dispute with the Balancing Pool in the third quarter of 2019.
(3) 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 Segmented Financial Performance and Operating 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.
(4) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020.
(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.
(6) 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.
(7) In the fourth quarter of 2021, comparable EBITDA was relabelled as adjusted EBITDA to align with industry standard terminology.
(8) Funds from operations ("FFO") per share and free cash flow per share are calculated using the weighted average number of common shares outstanding during the period. The weighted average number of common shares outstanding at Dec. 31, 2021 was 271 million shares (2020 - 275 million shares and 2019 - 283 million shares). Please refer to the Additional IFRS Measures and Non-IFRS Measures section in this MD&A for the purpose of these non-IFRS ratios.

We have seen exceptional performance from our Alberta Electricity Portfolio, driving overall strong performance for the Company. Both the Hydro and Gas segments had high availability on the merchant assets during periods of peak pricing, which resulted from abnormally warm summer and cold winter weather and periods of province-wide planned thermal outages. The Alberta merchant portfolio was positioned to capture opportunities from these strong spot market conditions through both energy and ancillary service revenues. This was further supplemented by strong performance in our Energy Marketing segment.

Adjusted availability for 2021 was 86.6 per cent compared to 90.7 per cent in 2020. The decrease was primarily due to higher planned and unplanned outages in the Energy Transition segment. The unplanned outages at Centralia Unit 2 and Sundance Unit 4 adversely impacted availability. In addition, adjusted availability was reduced by the planned outages for the Keephills Unit 2 and Keephills Unit 3 boiler conversions. The unplanned outage at the Kent Hills 1 and 2 wind facilities further contributed to reduced adjusted availability.




TRANSALTA CORPORATION M12
Management’s Discussion and Analysis

Production for 2021 was 22,105 gigawatt hours ("GWh") compared to 24,980 GWh in 2020. Overall, the decrease in production was primarily due to the planned retirement of Centralia Unit 1, portfolio optimization activities in Alberta, lower wind resources, the outage at the Kent Hills 1 and 2 wind facilities in the Wind and Solar segment and lower capacity loads in the Gas segment. This was partially offset by higher incremental production at our Ada facility within our Gas segment and higher incremental production from the Skookumchuck wind facility, the Windrise wind facility and the North Carolina Solar facility in the Wind and Solar segment.

Revenues for 2021 increased by $620 million compared to 2020, mainly as a result of capturing higher realized prices within the Alberta market through our optimization and operating activities and the elimination of the net payment obligations under the Alberta Hydro PPA required in the prior period. Revenues also increased due to the strong performance from the Energy Marketing segment, an increase in revenues within the Gas segment from the addition of the Ada facility and an increase within the Wind and Solar segment from the addition of the North Carolina Solar facility and the Windrise wind facility. These increases were partially offset by lower production in the Energy Transition, Hydro, Wind and Solar, and Gas segments.

Fuel and purchased power costs in 2021 increased by $249 million compared to 2020. In our Energy Transition segment, our fuel and purchased power costs increased compared to 2020 due to higher fuel transportation costs and the acquisition of higher-priced power during periods of higher merchant pricing to fulfil our contractual obligations during planned and unplanned outages at the Centralia facility. In addition, the Gas and Energy Transition segments experienced higher natural gas pricing, higher coal mine depreciation and coal inventory write-downs at the Highvale mine, all of which contributed to higher fuel costs.

Carbon compliance costs increased by $15 million compared to 2020, due to an increase in the carbon price per tonne, partially offset by reductions in GHG emissions stemming from changes in the fuel mix ratio as we operated more on natural gas and fired less with coal. Additionally, carbon compliance costs were partially offset by lower production in the Gas and Energy Transition segments. Operating with natural gas reduces carbon compliance costs as we produce fewer GHG emissions than by using coal.

Operations, maintenance and administration ("OM&A") expenses for 2021 increased by $39 million compared to 2020. A write-down of $28 million was recorded on parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities. In addition, variability caused by the total return swap resulted in a favourable change of $7 million. During 2021, we received a Canada Emergency Wage Subsidy ("CEWS") of $8 million. Excluding the impact of the total return swap, CEWS funding and inventory write-down, OM&A expenses were higher compared to the same periods in 2020, primarily due to increased staffing costs for growth and strategic initiatives and higher incentive costs. In addition, there were additional costs associated with the legal fees and the settlement of outstanding legal issues. As previously committed, the CEWS funding continues to be used to support incremental employment within the Company.

Adjusted EBITDA increased by $336 million compared to 2020. Adjusted EBITDA increased largely due to higher gross margin, driven by higher realized prices and dispatch optimization in the Alberta market from our merchant facilities residing in the Alberta Electricity Portfolio across the Hydro, Wind and Solar, Gas, and Energy Transition segments. In addition, the Energy Marketing segment also increased adjusted EBITDA due to favourable short-term trading of both physical and financial power and natural gas products across North American markets. This increase was partially offset by the retirement of Centralia Unit 1, unplanned outages at Centralia Unit 2 in the Energy Transition segment and the extended site outage at the Kent Hills 1 and 2 wind facilities. Significant changes in segmented adjusted EBITDA are highlighted in the Segmented Financial Performance and Operating Results section within this MD&A.

Loss before income taxes for 2021 increased by $77 million compared to 2020. Net loss attributable to common shareholders for 2021 was $576 million compared to a loss of $336 million in 2020. The higher loss before income taxes and the higher net loss attributable to common shareholders in 2021 was largely driven by higher asset impairments related to decisions to shut down the Highvale mine, suspend the Sundance 5 repowering project and planned retirements of Sundance Unit 4 and Keephills Unit 1. These higher asset impairments were partially offset by higher adjusted EBITDA largely resulting from the strong performance of the Alberta Electricity Portfolio across all of our fuel segments, higher gains on sale of assets due to the gain on sale of equipment in the Energy Transition segment and the gain from the sale of the Pioneer Pipeline in the Gas segment and lower depreciation. The higher net loss attributable to common shareholders was also impacted by higher income tax expense in 2021 due to higher earnings in the Energy Marketing segment and from the Alberta Electricity Portfolio.

Cash flow from operating activities increased by $299 million compared with 2020, primarily due to higher revenues being realized in Alberta on the merchant assets and changes in non-cash working capital, partially offset by higher fuel and purchased power and OM&A costs as the Company transitioned off coal.




TRANSALTA CORPORATION M13
Management’s Discussion and Analysis

FCF, one of the Company's key financial metrics, totalled $562 million compared to $358 million in 2020. This represents an increase of $204 million, driven primarily by higher adjusted EBITDA, partially offset by an increase in sustaining capital spending related to higher planned maintenance and facility turnarounds, settlement of provisions and higher distributions paid to subsidiaries' non-controlling interests.

Sustaining Capital
We are in a long-cycle, capital-intensive business that requires significant capital expenditures. Our goal is to undertake sustaining capital expenditures that ensures our facilities operate reliably and safely over a long period of time.
Year ended Dec. 31202120202019
Total sustaining capital expenditures199 157 141 

Total sustaining capital expenditures were $42 million higher compared to 2020, mainly due to higher planned major maintenance turnarounds related to Keephills Unit 2 and 3 and Sheerness Unit 1 and distributed planned maintenance expenditures across the entire hydro and wind fleet, with a focus on planned component replacements in the wind fleet.

Ability to Deliver Financial Results
The metrics we use to track our performance are adjusted EBITDA and FCF. The following table compares target to actual amounts for each of the three past fiscal years:
Year ended Dec. 31202120202019
Adjusted EBITDA (1)
Target(2)
1,200-1,300925-1000875-975
Actual1,263 927 984 
FCF (1)
Target(2)
500-560325-375350-380
Actual562 358 435 
(1) These items are not defined and have no standardized meaning under IFRS. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(2) This represents our revised outlook, as a result of strong performance in the second and third quarters of 2021, the Company revised the following 2021 targets: Adjusted EBITDA from the previously announced target range of $960 million - $1,080 million to the target range of $1,200 million - $1,300 million and FCF target range from $340 million - $440 million to the target range of $500 million - $560 million. In addition, during 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.

Significant and Subsequent Events
White Rock Wind Projects and Fully Executed Corporate PPAs
On Dec. 22, 2021, TransAlta executed two long-term PPAs with a new customer with an AA credit rating from S&P Global Ratings for 100 per cent of the generation from its 300 MW White Rock Wind Projects to be located in Caddo County, Oklahoma. The White Rock Wind Projects will consist of a total of 51 Vestas turbines. Construction is expected to begin in late 2022 with a target commercial operation date in the second half of 2023. TransAlta will construct, operate and own the facilities. Total construction capital is estimated at approximately US$460 million to US$470 million and is expected to be financed with a combination of existing liquidity and tax equity financing. Over 90 per cent of the project costs are captured under executed fixed price turbine supply agreements and fixed price engineering, procurement and construction agreements. The project is expected to generate average annual EBITDA2 of approximately US$42 million to US$46 million including production tax credits.

North Carolina Solar Acquisition
On Nov. 5, 2021, the Company closed the acquisition of a 122 MW portfolio of 20 solar photovoltaic sites located in North Carolina. The assets were acquired from a fund managed by Copenhagen Infrastructure Partners for approximately US$99 million (including working capital adjustments) and the assumption of existing tax equity obligations. The acquisition was funded using existing liquidity.

At the closing of the acquisition, TransAlta Renewables acquired a 100 per cent economic interest in North Carolina Solar from a wholly owned subsidiary of TransAlta through a tracking share structure for aggregate consideration of approximately US$102 million.

2 Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.




TRANSALTA CORPORATION M14

Management’s Discussion and Analysis
The facilities are all operational and were commissioned between November 2019 and May 2021. The facilities are secured by PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each facility. North Carolina Solar is expected to generate an average annual EBITDA3 of approximately US$9 million.

Kent Hills Wind Facilities Outage
On Sept. 27, 2021, the Company's subsidiary, Kent Hills Wind LP, experienced a single tower failure at its 167 MW Kent Hills wind facilities in Kent Hills, New Brunswick. The failure involved a collapsed tower located within the Kent Hills 2 site. There were no injuries as a result of the collapse. No one was in the area when the incident occurred and there are no homes in the immediate vicinity. The Company's emergency response team secured the area to ensure safety. The Company recorded an impairment charge of $2 million on the collapsed tower.

The facilities consist of 50 turbines at the Kent Hills 1 and 2 wind facilities and five turbines at Kent Hills 3. Following extensive independent engineering assessments and root cause failure analysis, the Company announced on Jan. 11, 2022, that all 50 turbine foundations at the Kent Hills 1 and 2 wind facilities require a full foundation replacement. The root cause failure analysis indicates that deficiencies in the original design of the foundations had led to subsurface crack propagation within the foundations and that the foundations must be replaced. The Company is in the process of planning the rehabilitation of the wind sites and currently expects the wind facility foundations to be fully replaced by the end of 2023. Based on the recommendations of independent engineers, and in order to maintain the safety of the affected facilities and turbines, the wind turbines will cease to operate until their associated foundations are replaced. The Company has recorded $12 million of accelerated depreciation relating to the 50 foundations that will be replaced.

Foundation replacements will require expenditures of approximately $75 million to $100 million, in aggregate. The remediation plan is expected to begin to be implemented in 2022. The outage is expected to result in foregone revenue of approximately $3.4 million per month on an annualized basis so long as all 50 turbines are offline, based on average historical wind production, with revenue expected to be earned as the wind turbines are returned to service.

TransAlta and New Brunswick Power Corporation continue discussions to enable the safe return to service of the facilities.

The foundation issues at the Kent Hills 1 and 2 wind facilities are unique to the design of those sites and there is no indication of any foundation issue at the Kent Hills 3 facility or any other wind facility in the fleet. The Company is maintaining communication with all key stakeholders and is keeping them fully apprised of the situation. The Company is actively evaluating any options that may be available to recover these costs from third parties and insurance.

As a result of the determination that all 50 foundations require replacement, as well as certain resulting amendments to applicable insurance policies, the Company's operating subsidiary, Kent Hills Wind LP, has provided notice to BNY Trust Company of Canada, as trustee (the “Trustee”), for the approximately $221 million outstanding non-recourse project bonds (the “KH Bonds”) secured by, among other things, the Kent Hills 1, 2 and 3 wind facilities, that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Upon the occurrence of any event of default, holders of more than 50 per cent of the outstanding principal amount of the KH Bonds have the right to direct the Trustee to declare the principal and interest on the KH Bonds and all other amounts due, together with any make-whole amount as at Dec. 31, 2021 — $39 million, to be immediately due and payable and to direct the Trustee to exercise rights against certain collateral. The Company is in discussions with the Trustee and holders of the KH Bonds to negotiate required waivers and amendments while the Company works to remedy the matters described in the notice. Although the Company expects that it will reach agreement with the Trustee and holders of the KH Bonds with respect to terms of an acceptable waiver and amendment, there can be no assurance that the Company will receive such waivers and amendments. Accordingly, the Company has classified the entire carrying value of the KH Bonds as a current liability as at Dec. 31, 2021.

Investor Day
On Sept. 28, 2021, TransAlta held our 2021 Investor Day and announced our Clean Electricity Growth Plan. The Company has established targets to deliver 2 GW of incremental renewables capacity with a targeted investment of $3 billion by 2025. TransAlta will accelerate its growth with a focus on customer-centred renewables and storage through the execution of its 3 GW development pipeline. Please see the Accelerated Clean Electricity Growth Plan section of this MD&A.

3 Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.




TRANSALTA CORPORATION M15

Management’s Discussion and Analysis
Retirement of Sundance Unit 4, Keephills Unit 1 and Sundance Unit 5 Coal-Fired Units
The Company announced, during its recent Investor Day, its decision to suspend the Sundance Unit 5 repowering project and retire Keephills Unit 1 on Jan. 1, 2022 and Sundance Unit 4 in 2022.

On July 29, 2021, in accordance with applicable regulatory requirements, the Company gave notice to the AESO of its intention to retire the currently mothballed coal-fired Sundance Unit 5 effective Nov. 1, 2021, and to terminate the associated transmission service agreement. Refer to the Clean Energy Transition section within the Description of the Business section of this MD&A for additional details on these thermal assets.

TransAlta Achieves Full Phase-Out of Coal in Canada
During the year, the Company completed the full conversion of Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 from thermal coal to natural gas. Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 will maintain the same generator nameplate capacity of 395 MW, 463 MW and 401 MW, respectively. These conversion to gas projects will reduce our CO2 emissions by more than half and completes our plan to generate 100 per cent clean electricity in Alberta by the end of 2021. As of Dec. 31, 2021, the Company has fully transitioned to natural gas in Canada.

Highvale Mine Impairment
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 Company's conversion to gas plans. During the third quarter of 2021, with all of TransAlta's remaining coal-fired units having been converted, in the process of being converted to natural gas or being retired, the Highvale mine was no longer considered to be providing significant economic benefit to the Alberta Merchant CGU and was removed from the CGU. This resulted in an impairment being recognized during 2021 of $195 million. Effective Dec. 31, 2021, the mine has entered its reclamation phase.

Announced Common Dividend Increase
On Sept. 28, 2021, the Company announced that the Board approved an 11 per cent increase on its common share dividend and declared a dividend of $0.05 per common share paid on Jan. 1, 2022, to shareholders of record at the close of business on Dec. 1, 2021. The quarterly dividend of $0.05 per common share represents an annualized dividend of $0.20 per common share.

Northern Goldfields Solar Project
On July 29, 2021, TransAlta Renewables announced that Southern Cross Energy ("SCE"), a subsidiary of the Company and an entity in which TransAlta Renewables owns an indirect economic interest, had reached an agreement to provide BHP Billiton Nickel West Pty Ltd. ("BHP") with renewable electricity to its Goldfields-based operations through the construction of the Northern Goldfields Solar Project. The project consists of the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm, 10 MW/5MWh Leinster Battery Energy Storage System and interconnecting transmission infrastructure, all of which will be integrated into our existing 169 MW Southern Cross Energy North remote network in Western Australia. Construction commenced in the first quarter of 2022 with completion of the projects expected in the second half of 2022. Total construction capital for the project is estimated at approximately AU$69 million to AU$73 million. The project is expected to generate average annual EBITDA4 of approximately AU$9 million to AU$10 million.

On Oct. 22, 2020, SCE replaced and extended its current PPA with 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 with participation rights in integrating renewable electricity generation, including solar and wind, with energy storage technologies, subject to the satisfaction of certain conditions. In addition to the Northern Goldfields Solar Project, evaluation of further renewable energy supply and carbon emissions reduction initiatives under the extended PPA with BHP are underway, including wind generation and lower emission firming generation to support BHP's future power requirements.

4 Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.




TRANSALTA CORPORATION M16

Management’s Discussion and Analysis
Sale of the Pioneer Pipeline
On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. ("ATCO") for the aggregate sale price of $255 million. The net cash proceeds to TransAlta from the sale of its 50 per cent interest was approximately $128 million. Pioneer Pipeline has been integrated into the NOVA Gas Transmission Ltd. ("NGTL") and ATCO Alberta natural gas transmission systems to provide reliable natural gas supply to the Company's power generation stations at Sundance and Keephills. As part of the transaction, TransAlta has entered into additional long-term gas transportation agreements with NGTL for new and existing transportation service of 400 TJ per day by the end of 2023.

Sarnia Cogeneration Facility Contract Extension
On May 12, 2021, the Company executed an Amended and Restated Energy Supply Agreement with one of its large industrial customers at the Sarnia cogeneration facility, which provides for the supply of electricity and steam. This agreement will extend the term of the original agreement from Dec. 31, 2022 to Dec. 31, 2032. The agreement provides that if the Company is unable to enter into a new contract with the Ontario Independent Electricity System Operator (“IESO”) or enter into agreements with its other industrial customers at the Sarnia cogeneration facility that extend past Dec. 31, 2025, then the Company has the option to provide notice of termination in 2022 that would terminate the Amended and Restated Energy Supply Agreement four years following such notice. The Company is in active discussions with the three other existing industrial customers regarding extensions to their supply of electricity and steam from the Sarnia cogeneration facility on comparable terms. The current contract with the IESO in respect of the Sarnia cogeneration facility expires on Dec. 31, 2025. On July 19, 2021, the IESO released its Annual Acquisition Report, which included draft details for medium- and long-term procurement mechanisms for capacity for 2026 and beyond for existing and new generation. The medium-term procurement process is scheduled to be run in 2022. The Company plans to bid into the process, seeking to secure a contract extension for the Sarnia cogeneration facility following the end of the current contract.

Garden Plain Wind Project
On May 3, 2021, the Company announced that it entered into a long-term PPA with Pembina pursuant to which Pembina has contracted for the renewable electricity and environmental attributes for 100 MW of the 130 MW Garden Plain project. Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project (49 per cent of the quantity under the PPA). The option must be exercised no later than 30 days after the commercial operational date. TransAlta would remain the operator of the facility and earn a management fee if Pembina exercises this option. Garden Plain will be located approximately 30 kilometres north of Hanna, Alberta. Construction activities started in the fall of 2021 with completion of the project expected in the second half of 2022. Total construction capital for the project is estimated at approximately $195 million. The project is expected to contribute between $14 million and $18 million of average annual EBITDA5.

TransAlta Renewables is Named on the Best 50 Corporate Citizens List
During the second quarter of 2021, TransAlta Renewables was recognized by Corporate Knights as one of the Best 50 Corporate Citizens for 2021. The Best 50 Corporate Citizens list evaluates and ranks Canadian corporations against a set of 24 key performance indicators covering ESG indicators relative to their industry peers and using publicly available information. The Company is committed to continuous improvement on key ESG issues and to ensuring its economic value creation is balanced with a value proposition for the environment and its communities.

Equity, Diversity and Inclusion Program
On May 3, 2021, TransAlta announced that it received certification from a third party that specializes in measuring and tracking equity, diversity and inclusion ("ED&I") metrics for organizations, due to its continued commitment to and meaningful performance on ED&I in the workplace. The Company developed a five-year ED&I strategy that was approved by the Board in August 2021, and is now executing the first year of that ED&I strategy.

5 Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.




TRANSALTA CORPORATION M17

Management’s Discussion and Analysis
Sustainability-Linked Loan
In March 2021, TransAlta extended its $1.3 billion syndicated credit facility to June 30, 2025, and converted the facility into a Sustainability-Linked Loan (“SLL”). The facility's financing terms will align the cost of borrowing to TransAlta's GHG emission reductions and gender diversity targets, which are part of the Company's overall ESG strategy. The SLL will have a cumulative pricing adjustment to the borrowing costs on the facilities and a corresponding adjustment to the standby fee (the "Sustainability Adjustment"). Depending on performance against interim targets that have been set for each year of the credit facility term, the Sustainability Adjustment is structured as a two-way mechanism and could move either up, down or remain unchanged for each sustainability performance target based on performance. The SLL further underscores TransAlta's dedication to sustainability, including ED&I and emissions reduction.

Mangrove Claim
On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice naming the Company, the members of the Board of the Company on such date, and Brookfield BRP Holdings (Canada) ("Brookfield") as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021.

Fortescue Metals Group Ltd. ("FMG") Dispute at South Hedland Power Station
On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.

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 claimed force majeure under the PPA. ENMAX Energy Corporation ("ENMAX"), the purchaser under the PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.

TransAlta Renewables Acquisitions
The Company completed the sale of its 100 per cent direct interest in the 206 MW Windrise wind project ("Windrise") to TransAlta Renewables on Feb. 26, 2021, for $213 million. The remaining construction costs for Windrise were paid by TransAlta Renewables. On Nov. 10, 2021, Windrise achieved commercial operations. On Dec. 6, 2021, the Company's indirect wholly owned subsidiary, Windrise Wind LP, secured green bond financing by way of private placement for $173 million. The bonds will be amortizing and will bear interest from their date of issue at a rate of 3.41 per cent per annum and mature on Sept. 30, 2041.

On April 1, 2021, the Company completed the sale of its 100 per cent economic interest in the 29 MW Ada cogeneration facility ("Ada") and its 49 per cent economic interest in the 137 MW Skookumchuck wind facility ("Skookumchuck") to TransAlta Renewables for $43 million and $103 million, respectively. Both facilities are fully operational. Pursuant to the transaction, a TransAlta subsidiary owns Ada and Skookumchuck directly and has issued to TransAlta Renewables tracking preferred shares reflecting its economic interest in the facilities. The Ada facility is under a PPA until 2026. The Skookumchuck wind facility is contracted under a PPA until 2040 with an investment grade counterparty.

Normal Course Issuer Bid
On May 25, 2021, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement a normal course issuer bid ("NCIB") for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. 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 TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021, and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election.

No common shares were repurchased under the current or previous NCIB in 2021.





TRANSALTA CORPORATION M18

Management’s Discussion and Analysis
Management Changes
On March 31, 2021, Dawn Farrell retired from the Board and as President and Chief Executive Officer of the Company. John Kousinioris succeeded Mrs. Farrell as President and Chief Executive Officer and joined the Board on April 1, 2021. Prior to his appointment as Chief Executive Officer of TransAlta, Mr. Kousinioris held the roles of Chief Operating Officer, Chief Growth Officer and Chief Legal and Compliance Officer and Corporate Secretary with the Company.

On April 30, 2021, Brett Gellner, our Chief Development Officer, retired after almost 13 years with TransAlta. Mr. Gellner continues to serve on the Board of Directors of TransAlta Renewables as a non-independent director.

Board of Director Changes
On May 4, 2021, the Company announced the election of four new directors: Mr. Thomas O'Flynn, Ms. Laura W. Folse, Mr. Jim Reid and Ms. Sarah Slusser, who each bring diverse expertise and new perspectives to the Board. Mr. Richard Legault, Mr. Yakout Mansour and Mrs. Georgia Nelson did not stand for re-election and retired from the Board immediately following the annual shareholder meeting on May 4, 2021.

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 Company continues to operate under its business continuity plan, which is focused on ensuring that: (i) employees who can work remotely do so; and (ii) employees who operate and maintain our facilities, and who are not able to work remotely, are able to work safely and in a manner that ensures their health and safety. TransAlta has adopted local public health authority and government guidelines in all jurisdictions in which we operate to promote the health and safety of all employees and contractors with our health and safety protocols. All of TransAlta's offices and sites follow health screening and social distancing protocols, including personal protective equipment. Employees can be exempted from rapid testing if they are able to provide proof of vaccination. Further, TransAlta maintains travel limitations that are aligned to local jurisdictional guidance, enhanced cleaning procedures, revised work schedules, contingent work teams and the reorganization of processes and procedures to minimize any workplace transmission of the virus.

Notwithstanding the challenges associated with the pandemic, all of our facilities continue to remain fully operational and are capable of meeting our customers' needs, with the exception of the Kent Hills 1 and 2 wind facilities, which as described above, is not related to the pandemic. The Company 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 as a result of COVID-19. 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.

The Company continues to maintain a strong financial position due in part to its long-term contracts and hedged positions, and its ample financial liquidity.

The Board and management have been monitoring the evolution of the pandemic and are continually assessing its impact to the safety of the Company's employees, operations, supply chains and customers as well as, more generally, to our existing capital projects, and the business and affairs of the Company. Potential impacts of the pandemic on the business and affairs of the Company include, but are not limited to: (i) potential interruptions of production; (ii) supply chain disruptions; (iii) unavailability of employees; (iv) potential delays in capital projects; (v) increased credit risk with counterparties and increased volatility in commodity prices; as well as (vi) increased volatility in the valuation 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.

Strategic Investment by Brookfield
On March 22, 2019, the Company entered into an agreement (the "Investment Agreement") whereby Brookfield agreed to invest $750 million in the Company through the purchase of exchangeable securities, which are exchangeable by Brookfield into an equity ownership interest in certain of TransAlta’s Alberta Hydro Assets in the future at a value based on a multiple of the Alberta Hydro Assets’ future-adjusted 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 and second tranche were used to accelerate our conversion to gas program. In addition, the proceeds from the second tranche of the financing will be used to fund other growth initiatives and for general corporate purposes.




TRANSALTA CORPORATION M19

Management’s Discussion and Analysis
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. At Dec. 31, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,425,696 common shares, representing approximately 13.1 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.

In accordance with the terms of the Investment Agreement, TransAlta 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 Company has committed to pay Brookfield an annual fee of $1.5 million for six years beginning May 1, 2019, which is recognized in the OM&A expense on the Consolidated Statements of Earnings (Loss).

Centralia Unit 1 and 2 Retirement
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, as planned. The Centralia Unit 2 is set to shut down at the end of 2025.

TEC Hedland Pty Ltd. Secures AU$800 Million Financing
On Oct. 22, 2020, TEC Hedland Pty Ltd. ("TEC"), a subsidiary of the Company, 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"). 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 was 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.





TRANSALTA CORPORATION M20

Management’s Discussion and Analysis
Segmented Financial Performance and Operating Results
Segmented Disclosures
Segmented information is prepared on the same basis that the Company manages the business, evaluates financial results and makes key operating decisions. Refer to the Description of the Business section of this MD&A for explanation of the reporting segment changes.

The primary changes are the elimination of the Alberta Thermal and the Centralia segments, and the reorganization of the North American Gas and Australia Gas segments into a new "Gas" segment. The Alberta Thermal facilities that have been converted to gas have been included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new "Energy Transition" segment. No changes were made to the Hydro, Wind and Solar, Energy Marketing or the Corporate and Other segments. Prior years' metrics were adjusted to be comparable to the new segments.

Consolidated Results
The following table reflects the generation and summary financial information on a consolidated basis for the year ended Dec. 31:
LTA generation (GWh)(1)
Actual production (GWh)(2)
Adjusted EBITDA(3)
For the year ended Dec. 31202120202019202120202019202120202019
Hydro2,030 2,030 2,030 1,936 2,132 2,045 322 105 110 
Wind and Solar4,345 3,916 3,549 3,898 4,069 3,355 262 248 231 
Renewables6,375 5,946 5,579 5,834 6,201 5,400 584 353 341 
Gas10,565 10,780 11,819 494 367 403 
Energy Transition5,706 7,999 11,852 133 175 227 
Energy Marketing137 113 89 
Corporate and Other(85)(81)(76)
Total22,105 24,980 29,071 1,263 927 984 
Total earnings (loss) before
  income taxes		(380)(303)193 
(1) Long-term average production ("LTA (GWh)") is calculated based on our portfolio as at Dec. 31, 2021, on an annualized basis from the average annual energy yield predicted from our simulation model based on historical resource data performed over a period of typically 30-35 years for the Wind and Solar segment and 36 years for Hydro segment. LTA (GWh) for Energy Transition is not considered for these facilities as we are currently transitioning these units completely by the end of 2025 and the LTA (GWh) for Gas is not considered as it is largely dependent on market conditions and merchant demand.
(2) Actual production levels are compared against the long-term average to highlight the impact of an important factor that affects the variability in our business results. In the short term, for each segment for Hydro, Wind and Solar, the conditions will vary from one period to the next and over time facilities will continue to produce in line with their long-term averages, which have proven to be reliable indicators of performance.
(3) This item is not defined and has no standardized meaning under IFRS. Please refer to below in this MD&A for further discussion of this item, 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.





TRANSALTA CORPORATION M21

Management’s Discussion and Analysis
Hydro
Year ended Dec. 31202120202019
Gross installed capacity (MW)925925925 
LTA (GWh)2,030 2,030 2,030 
Availability (%)92.4 93.2 95.9 
Production
Energy contract
Alberta Hydro Assets (GWh)(1)
— 1,703 1,653 
Other Hydro energy (GWh)(1)
434 353 331 
Energy merchant
Alberta Hydro Assets (GWh)1,502 — — 
Other Hydro energy (GWh)— 76 61 
Total energy production (GWh)1,936 2,132 2,045 
Ancillary service volumes (GWh)(4)
2,897 2,857 2,978 
Alberta Hydro Assets(1)
185 87 101 
Other Hydro Assets and other revenue(1)(2)
42 45 44 
Capacity payments(3)
— 60 57 
Alberta Hydro ancillary services(4)
160 66 90 
Net payment relating to Alberta Hydro PPA(5)
(4)(106)(136)
Revenues383 152 156 
Fuel and purchased power16 8 7 
Gross margin367 144 149 
Operations, maintenance and administration42 37 36 
Taxes, other than income taxes3 2 3 
Adjusted EBITDA322 105 110 
Supplemental Information:
Gross revenues per MWh
Alberta Hydro Assets energy ($/MWh)1235161
Alberta Hydro Assets ancillary ($/MWh)552330
Sustaining capital26 20 14 
(1) Alberta Hydro Assets include 13 hydro facilities on the Bow and North Saskatchewan river systems included under the PPA legislation. These PPAs expired Dec. 31, 2020. Other hydro facilities include our hydro facilities in BC and Ontario and the hydro facilities in Alberta not included in the legislated PPAs and transmission revenues.
(2) 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.
(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) Ancillary services as described in the AESO Consolidated Authoritative Document Glossary.
(5) The net payment relating to the Alberta Hydro PPA represents the Company's financial obligations for notional amounts of energy and ancillary services in accordance with the Alberta Hydro PPA that expired on Dec. 31, 2020.

2021
Availability for 2021 decreased compared to 2020, primarily due to higher planned and unplanned outages.

Production for 2021 decreased by 196 GWh compared to 2020, mainly due to higher planned outages and lower precipitation.

Ancillary service volumes for 2021 increased by 40 GWh compared to 2020, in line with our expectations.

Adjusted EBITDA for 2021 increased by $217 million compared to 2020. Effective Jan. 1, 2021, with the expiration of the Alberta PPA for our Alberta Hydro Assets, these facilities began operating on a merchant basis in the Alberta power market. This eliminated the net payment obligations under the Alberta PPA. With strong availability during periods of market volatility, the Company captured higher energy and ancillary service revenue, partially offset by increased costs related to portfolio management services, dam safety staffing, dredging and station services.





TRANSALTA CORPORATION M22

Management’s Discussion and Analysis
Sustaining capital expenditures for 2021 were $6 million higher than in 2020, due to higher planned outages in 2021.

2020
Availability for 2020 decreased compared to 2019, primarily due to higher planned and unplanned outages.

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. Ancillary volumes were impacted by weaker market conditions, partially due to COVID-19 and reduced industrial demand in Alberta.

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.

Adjusted 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.

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

Wind and Solar
Year ended Dec. 31202120202019
Gross installed capacity (MW)(1)
1,906 1,5721,495 
LTA (GWh)4,3453,9163,549 
Availability (%)91.9 95.195.0 
Contract production (GWh)2,850 2,871 2,395 
Merchant production (GWh)1,048 1,198 960 
Total production (GWh)3,898 4,069 3,355 
Revenues(2)
348 334 295 
Fuel and purchased power17 25 16 
Gross margin(2)
331 309 279 
Operations, maintenance and administration59 53 50 
Taxes, other than income taxes10 8 8 
Net other operating income(3)
— — (10)
Adjusted EBITDA262 248 231 
Supplemental information:
Sustaining capital13 13 13 
(1) The 2021 gross installed capacity includes 206 MW for the Windrise wind facility and 4 MW for the Oldman Wind facility, which were added in 2021. The 2021 and 2020 gross installed capacity includes 10 MW for the WindCharger battery storage facility and 67 MW for our proportionate share of the Skookumchuck wind facility.
(2) For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS and Non-IFRS Measures section of this MD&A.
(3) Relates to insurance proceeds included in net other operating income.

2021
Availability for the year ended Dec. 31, 2021, decreased compared to 2020, primarily as a result of the unplanned outage at the Kent Hills 1 and 2 wind facilities.

Production for the year ended 2021, decreased 171 GWh compared to 2020, and was impacted by lower wind resources in Eastern Canada and in the US and the unplanned outage at the Kent Hills 1 and 2 wind facilities, which was partially offset by a full year of production from the Skookumchuck wind facility, the commissioning of the Windrise wind facility, and the acquisition of the North Carolina Solar facility.





TRANSALTA CORPORATION M23

Management’s Discussion and Analysis
Adjusted EBITDA for 2021 increased by $14 million compared to 2020, primarily due to higher merchant pricing in Alberta, a full year of operations from the Skookumchuck wind facility and the WindCharger battery storage facility as well as incremental value from the newly commissioned or acquired assets in 2021: consisting of the Windrise wind facility and the North Carolina Solar facility. Also, fuel and purchased power costs were lower in 2021 due to the AESO transmission line loss recorded in 2020. Adjusted EBITDA was negatively impacted by lower wind resources in Eastern Canada and the US, the unplanned outage at the Kent Hills 1 and 2 wind facilities and the weakening US dollar relative to the Canadian dollar.

Sustaining capital expenditures for 2021 were consistent with 2020.

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 GWh, 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 at the Alberta wind facilities.

Adjusted 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 were allocated $8 million in costs in 2020, which has been reflected in fuel and purchased power within the same year.

Sustaining capital expenditures for 2020 were consistent with 2019.

Gas
Year ended Dec. 31202120202019
Gross installed capacity (MW)(1)
3,084 3,084 3,049 
Availability (%)85.7 87.7 92.8 
Contract production (GWh)3,622 7,280 8,101 
Merchant production (GWh)(2)
7,084 3,698 3,810 
Purchased power (GWh)(2)
(141)(198)(92)
Total production (GWh)10,565 10,780 11,819 
Revenues(3)
1,132 848 887 
Fuel and purchased power(3)
374 221 230 
Carbon compliance118 120 138 
Gross margin(3)
640 507 519 
Operations, maintenance and administration(3)
173 166 162 
Taxes, other than income taxes13 13 9 
Net other operating income(3)
(40)(39)(41)
Termination of Sundance B and C PPAs— — (14)
Adjusted EBITDA494 367 403 
Supplemental information:
Sustaining capital128 87 33 
(1) 2021 and 2020 includes 29 MW for the acquisition of the Ada facility.
(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) For details of the adjustments to revenues, fuel and purchased power, operations, maintenance and administration and net other operating income included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The Gas Segment is a new segment as described in the Segmented Financial Performance and Operating Results section of this MD&A. Included in the Gas segment is the previous North American Gas segment, Australian Gas segment and the facilities from the previous Alberta Thermal segment converted to gas.This includes Sheerness Unit 1 and 2, Keephills Unit 2 and 3 and Sundance Unit 6. Previous periods have been adjusted to be comparable to the new segment.





TRANSALTA CORPORATION M24

Management’s Discussion and Analysis
2021
 Availability for the year ended Dec. 31, 2021, decreased compared to 2020, primarily as a result of an increase in unplanned outages and planned boiler conversions of Keephills Unit 2, Keephills Unit 3, and Sheerness Unit 1 in Alberta, partially offset by higher availability of Sundance 6 with the gas conversion completed in 2020.

Production for the year ended Dec. 31, 2021, decreased by 215 GWh compared to 2020, mainly due to higher portfolio optimization activities in Alberta and lower customer loads in Australia, partially offset by higher demand in our other facilities and incremental production from a full year of operations at the Ada cogeneration facility.

Adjusted EBITDA for the year ended Dec. 31, 2021, increased by $127 million compared to 2020, primarily due to higher merchant pricing in the Alberta market, the South Hedland PPA contract settlement and incremental production from a full year of operations at our Ada cogeneration facility, partially offset by an increase in fuel, unplanned short-term steam supply outages at our Sarnia cogeneration facility, higher OM&A costs related to the BHP pass-through projects and legal fees related to the South Hedland PPA contract settlement.

Sustaining capital expenditures for the year ended Dec. 31, 2021, increased by $41 million mainly due to major maintenance costs associated with conversion to natural gas outages of Keephills Unit 2 and Unit 3 and Sheerness Unit 1, planned major maintenance at the Australian gas facilities, and the purchase of an additional engine at the South Hedland facility.

2020
 Availability for the year ended Dec. 31, 2020, decreased compared to 2019, due to the Sundance Unit 6 planned turnaround and conversion to gas, higher unplanned outages and derates.

Production for the year ended Dec. 31, 2020, decreased by 1,039 GWh compared to 2019, mainly due to lower availability, lower merchant production in Alberta and Ontario and lower customer demand in Australia, partially offset by the addition of the Ada cogeneration facility.

Adjusted EBITDA for the year ended Dec. 31, 2020, decreased by $36 million compared to 2019, due to lower revenues from lower realized merchant pricing in Alberta and lower production, higher fuel costs and $14 million related to the settlement on the Sundance B and C PPAs in 2019, partially offset by the addition of the Ada facility, deferral of legal costs, reduced staffing due to cost controls and the strengthening of the Australian dollar against the Canadian dollar.
 
Sustaining capital expenditures for the year ended Dec. 31, 2020, increased by $54 million mainly due to the major maintenance that occurred during the Sheerness dual-fuel conversion and the Sundance Unit 6 turnaround and planned major maintenance at the Southern Cross facility, partially offset by a reduction in sustaining capital associated with a major planned outage for Sarnia cogeneration facility in 2019.






TRANSALTA CORPORATION M25

Management’s Discussion and Analysis
Energy Transition
Year ended Dec. 31202120202019
Gross installed capacity (MW)(1)
1,472 2,548 2,916 
Availability (%)75.3 82.6 78.7 
Adjusted availability (%)(2)
78.8 91.3 84.2 
Contract sales volume (GWh)3,329 5,526 5,622 
Merchant sales volume (GWh)6,052 6,248 10,095 
Purchased power (GWh)(3,675)(3,775)(3,865)
Total production (GWh)5,706 7,999 11,852 
Revenues(3)
728 690 893 
Fuel and purchased power(3)
432 352 499 
Carbon compliance60 48 77 
Gross margin(3)
236 290 317 
Operations, maintenance and administration(3)
97 106 124 
Taxes, other than income taxes6 9 8 
Termination of Sundance B and C PPAs— — (42)
Adjusted EBITDA133 175 227 
Supplemental information:
Highvale mine reclamation spend6715
Centralia mine reclamation spend9711
Sustaining capital19 22 69 
(1) 2021 gross installed capacity excludes Centralia Unit 1 (670 MW retired on Dec. 31, 2020) and Sundance Unit 5 (406 MW) retired during the year. 2021 and 2020 excludes 368 MW from Sundance Unit 3, which retired during 2020.
(2) Adjusted for dispatch optimization.
(3) For details of the adjustments to revenues, fuel and purchased power and operations, maintenance and administration included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The Energy Transition segment is a new segment as described in the Segmented Financial Performance and Operating Results section of this MD&A. Included in the Energy Transition segment is the previous Centralia segment, mine assets and the previous Alberta Thermal segment facilities that were not converted to gas. This includes Keephills Unit 1 and Sundance Unit 4. Previous periods have been adjusted to be comparable to the new segment.

2021
Adjusted availability for the year ended Dec. 31, 2021, decreased compared to 2020 due to higher planned and unplanned outages at Centralia Unit 2 and Sundance Unit 4 related to derates.

Production decreased by 2,293 GWh for the year ended Dec. 31, 2021, compared to 2020, primarily due the planned retirement of Centralia Unit 1 and dispatch optimization of the Alberta assets.

Adjusted EBITDA decreased by $42 million for the year ended Dec. 31, 2021, compared to 2020, primarily due the planned retirement of Centralia Unit 1, higher fuel and purchased power due to unplanned outages at Centralia Unit 2, higher carbon compliance costs for the Alberta assets primarily due to an increase in carbon prices and the weakening of the US dollar relative to the Canadian dollar throughout the year, partially offset by dispatch optimization of the Alberta assets and lower OM&A as a result the planned retirement of Centralia Unit 1.

Mine reclamation spend for the Highvale and Centralia mines was mainly consistent compared to 2020.

Sustaining capital expenditures for the year ended Dec. 31, 2021, were $3 million lower than 2020 mainly due to reduction in planned outage work performed.

2020
Adjusted availability for the year increased compared to 2019 due to reduced forced outages at Centralia Unit 1 and lower planned outages at the Alberta sites.





TRANSALTA CORPORATION M26

Management’s Discussion and Analysis
Production decreased by 3,853 GWh in 2020 compared to 2019 mainly due to lower merchant pricing and Genesee 3 no longer being owned by the company. 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. In 2020, Genesee 3 was not included due to a 2019 ownership swap, resulting in the Company no longer owning a portion of the facility.

Adjusted EBITDA decreased by $52 million compared to 2019, primarily due to lower merchant production in Alberta due to unfavourable market conditions, a $42 million settlement related to the Sundance B and C PPAs in 2019, partially offset by dispatch optimization at Centralia in 2020 and from the increased cost of buybacks due to forced outages.

Mine reclamation spend decreased by $8 million for the Highvale mine and $4 million for the Centralia mine compared to 2019, mainly due to downsizing, an updated mine plan and the mine closure advancement for the Highvale Mine. In addition, due to COVID-19 in 2020, the mine reclamation spend was deferred to future years.

Sustaining capital expenditures for 2020 decreased by $47 million compared to 2019 mainly due to lower planned outage work performed in 2020 and lower mining equipment purchases and maintenance.

Energy Marketing
Year ended Dec. 31202120202019
Revenues(1)
173 143 119 
Operations, maintenance and administration36 30 30 
Adjusted EBITDA137113 89 
(1) For details of the adjustments to revenues included in adjusted EBITDA, refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

2021
Adjusted EBITDA for 2021 increased by $24 million compared to 2020. Results were better primarily due to favourable short-term trading of both physical and financial power and natural gas products across all North American markets. This was partially offset by OM&A increases due to higher incentives related to stronger performance. The Energy Marketing team was able to capitalize on short-term market volatility in the markets in which we trade without materially changing the risk profile of the business unit.

2020
Adjusted 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.

Corporate
Year ended Dec. 31202120202019
Operations, maintenance, and administration84 80 73 
Taxes, other than income taxes1 1 1 
Net other operating loss— — 2 
Adjusted EBITDA(85)(81)(76)
Supplemental information:
Total sustaining capital13 14 12 
 
2021
Adjusted EBITDA for the year ended Dec. 31, 2021, decreased by $4 million compared to 2020, primarily due to higher incentive payments, higher employee costs, higher insurance costs, and higher legal fees for settlement of outstanding legal issues, partially offset by the receipt of CEWS funding and realized gains from the total return swap. A portion of the settlement costs of our employee share-based payment plans is hedged by entering into total return swaps, which are cash settled every quarter. Excluding the impact of the total return swap, staffing costs increased due to additional headcount to support growth initiatives. As previously committed, the CEWS funding is being used to support incremental employment within the Company.





TRANSALTA CORPORATION M27

Management’s Discussion and Analysis
For the year ended Dec. 31, 2021, sustaining capital expenditures were consistent with 2020.

2020
Adjusted EBITDA for the year ended Dec. 31, 2020, decreased by $5 million compared to 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, 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.

For the year ended Dec. 31, 2020, sustaining capital expenditures were $2 million higher than 2019, mainly due to capital spend on information technology.

Fourth Quarter Highlights
Consolidated Financial Highlights
Three months ended Dec. 3120212020
Adjusted availability (%)83.8 87.1 
Production (GWh)5,823 7,704 
Revenues610 544 
Fuel and purchased power272 282 
Carbon compliance39 45 
Operations, maintenance and administration124 118 
Adjusted EBITDA(1)
270 234 
Loss before income taxes(32)(168)
Net loss attributable to common shareholders(78)(167)
Cash flow from operating activities54 110 
FFO(1)
213 161 
FCF(1)
106 52 
Net earnings (loss) per share attributable to common shareholders, basic and diluted(0.29)(0.61)
Dividends declared per common share(2)
0.10 0.09 
Dividends declared per preferred share(3)
0.25 0.50 
FFO per share(1,4)
0.79 0.59 
FCF per share(1,4)
0.39 0.19 
(1) These items are not defined and have no standardized meaning under IFRS. Please refer to the Segmented Financial Performance and Operating 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) Dividends declared vary year over year due to timing of dividend declarations.
(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) The weighted average number of common shares outstanding for the three months ended Dec. 31, 2021 was 271 million shares (2020 - 273 million shares).

Financial Highlights 
During the fourth quarter of 2021, the Company completed the year with solid performance from our Alberta Electricity Portfolio. Hydro, Gas and the Energy Transition segments had high availability in Alberta during periods of peak pricing, which resulted from extreme cold weather and periods of province-wide planned and unplanned outages. The Alberta merchant portfolio was positioned to capture opportunities from these strong spot market conditions through both energy and ancillary services revenues.

Adjusted availability for the three months ended Dec. 31, 2021, was 83.8 per cent compared to 87.1 per cent for the same period in 2020. Higher unplanned outages at our Wind and Solar segment and Energy Transition segment were partially offset by lower unplanned and planned outages at our Hydro segment. Wind and Solar availability was impacted by the unplanned outages at Kent Hills 1 and 2 wind facilities. Energy Transition availability was impacted by unplanned outages in our Centralia Unit 2 facility and dispatch optimization in Alberta.





TRANSALTA CORPORATION M28

Management’s Discussion and Analysis
Production for the three months ended Dec. 31, 2021, was 5,823 GWh compared to 7,704 GWh for the same period in 2020. The decrease in production for the three-month period in 2021 was due to the planned retirement of Centralia Unit 1 and unplanned outage at Centralia Unit 2, lower availability, the outage at the Kent Hills 1 and 2 wind facilities, and lower wind resources in the Wind and Solar segment. This decrease in production was partially offset by incremental production at our North Carolina Solar facility, the Windrise and Skookumchuck wind facilities in the Wind and Solar segment, and higher production at our Ada and Sarnia facilities within our Gas segment.

Revenues for the three months ended Dec. 31, 2021, increased $66 million compared to the same period in 2020, mainly as a result of capturing higher realized prices within the Alberta market through our optimization and operating activities and the elimination of the net payment obligations under the Alberta Hydro PPA required in the prior period. Revenues further increased due to the addition of the North Carolina Solar facility and commercial operation of the Windrise wind facility in the Wind and Solar segment, in addition to increased revenue from the Ada facility within the Gas segment. These increases were partially offset by lower production in the Energy Transition, Hydro and Wind and Solar segments.

Fuel and purchased power costs decreased by $10 million in the three months ended Dec. 31, 2021, compared to the same period in 2020. In our Energy Transition segment, our costs increased compared to 2020 due to higher fuel transportation costs and the acquisition of higher-priced power to fulfil our contractual obligations during planned and unplanned outages during periods of higher merchant pricing at the Centralia facility and higher natural gas pricing within the Gas segment. This was partially offset by lower coal mine depreciation and coal inventory write-downs at the Highvale mine in the fourth quarter of 2021.

Carbon compliance costs decreased by $6 million in the three months ended Dec. 31, 2021, compared to the same period in 2020, due to reductions in GHG emissions stemming from changes in the fuel mix ratio as we operated more on natural gas and fired less with coal, partially offset by an increase in the carbon price per tonne.

OM&A expenses for the three months ended Dec. 31, 2021, increased by $6 million, compared to the same period in 2020, primarily due to increased staffing costs for growth and strategic initiatives and higher incentive costs.

Adjusted EBITDA for the three months ended Dec. 31, 2021, increased by $36 million compared with the same period in 2020, largely due to higher adjusted EBITDA in our Hydro and Gas segments, which was driven by higher realized prices in the Alberta market, partially offset by lower production at Centralia Unit 2 within our Energy Transition segment due to a transformer failure that has now been resolved and an unplanned outage at the Kent Hills 1 and 2 wind facilities.

Net loss attributable to common shareholders in the fourth quarter of 2021 was $78 million compared to net loss of $167 million in the same period of 2020, a decrease of $89 million. The net loss in 2021 was favourably impacted by lower depreciation and amortization expense related to asset retirements and impairments in our Gas and Energy Transition segments and higher adjusted EBITDA.

Cash flow from operating activities in the fourth quarter of 2021 decreased by $56 million compared with the same period in 2020, primarily due to changes in non-cash working capital.

FCF in the fourth quarter of 2021 was $106 million compared to $52 million in the same period of 2020, as a result of higher adjusted EBITDA due to higher realized prices in Alberta, settlement of provisions and lower sustaining capital expenditures, partially offset by higher distributions paid to subsidiaries' non-controlling interests.





TRANSALTA CORPORATION M29

Management’s Discussion and Analysis
Segmented Financial Performance and Operating Results for the Fourth Quarter
A summary of our adjusted EBITDA by segment and total loss before income taxes for the three months ended Dec. 31, 2021 and 2020 is as follows:
Adjusted EBITDA
Three months ended Dec. 3120212020
Hydro67 22 
Wind and Solar76 77 
Gas(1)
110 92 
Energy Transition(2)
37 42 
Energy Marketing9 23 
Corporate and Other(29)(22)
Total adjusted EBITDA270 234 
Loss before income taxes(32)(168)
(1) Gas segment includes the segments previously known as Australian Gas and North American Gas and the coal generation assets converted to gas from the segment previously known as Alberta Thermal.
(2) Energy Transition segment includes the segment previously known as Centralia and the coal generation assets not converted to gas (including Sundance 4) and mining assets from the segment previously known as Alberta Thermal.

Adjusted EBITDA increased by $36 million for the fourth quarter of 2021, compared to 2020, primarily as a result of:
▪Hydro results were $45 million higher due to increased revenues from higher merchant prices in Alberta. Effective Jan. 1, 2021, with the expiration of the PPA for the Alberta Hydro facilities, these facilities began operating on a merchant basis in the Alberta power market. This eliminated the net payment obligations under the Alberta PPA.
▪Wind and Solar results were consistent compared to the prior period; results were impacted by the unplanned outage at the Kent Hills 1 and 2 wind facilities, which was partially offset by higher merchant pricing in Alberta and incremental value from newly commissioned or acquired assets such as the North Carolina Solar facility and the Windrise facility.
▪Gas results were $18 million higher mainly due to higher merchant prices in Alberta and the South Hedland PPA contract settlement, partially offset by higher OM&A costs and legal fees.
▪Energy Transition results were $5 million lower as a result of the retirement of Centralia Unit 1, unplanned outages at Centralia Unit 2 due to a transformer failure that has now been resolved, partially offset by dispatch optimization of Alberta assets.
▪Energy Marketing results were in line with expectations, but lower than prior year by $14 million.
▪Corporate costs were higher primarily due to higher incentive payments and higher staffing costs, partially offset by lower legal dispute settlement costs. Impacts from the total return swap on our share-based payment plans were higher in 2021 compared to 2020.

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 2021Q2 2021Q3 2021Q4 2021
Revenues642 619 850 610 
Adjusted EBITDA310 302 381 270 
Earnings (loss) before income taxes21 72 (441)(32)
Cash flow from operating activities257 80 610 54 
FFO211 250 297 213 
Net earnings (loss) attributable to common shareholders(30)(12)(456)(78)
Net earnings (loss) per share attributable to common shareholders,
   basic and diluted(1)
(0.11)(0.04)(1.68)(0.29)
 Q1 2020Q2 2020Q3 2020Q4 2020
Revenues606 437 514 544 
Adjusted EBITDA220 217 256 234 
Earnings (loss) before income taxes46 (52)(129)(168)
Cash flow from operating activities214 121 257 110 
FFO172 159 193 161 
Net earnings (loss) attributable to common shareholders27 (60)(136)(167)
Net earnings (loss) per share attributable to common shareholders,
   basic and diluted(1)
0.10 (0.22)(0.50)(0.61)
(1) Basic and diluted earnings per share attributable to common shareholders and adjusted 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, adjusted 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:
▪Acquisition of the North Carolina Solar facility in the fourth quarter of 2021;
▪The unplanned outage at Kent Hills 1 and 2 wind facilities and Centralia Unit 2 in the fourth quarter of 2021;
▪Sundance Unit 5 repowering was suspended in the third quarter of 2021 and retired during 2021;
▪Gains relating to the sale of the Pioneer Pipeline in the second quarter of 2021 and gains on sale of Gas equipment in the third quarter of 2021;
▪The unplanned outages at the Sarnia cogeneration facility in the second quarter of 2021;
▪Alberta hydro facilities, Keephills Units 1 and 2 and Sheerness began operating on a merchant basis in the Alberta market effective Jan. 1, 2021;
▪Revenues declined due to weaker market conditions in 2020 as a result of the COVID-19 pandemic and low oil prices;
▪Sundance Unit 3 was retired in the third quarter of 2020;
▪Accelerated plans to shutdown the Highvale Mine resulted in remaining future royalty payments being recognized as an onerous contract in the third quarter of 2021;
▪Sheerness going off-coal 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;
▪Accelerated shutdown of the Highvale Mine, increased mine depreciation included in the cost of coal. Coal inventory write-downs incurred in the first three quarters of 2021 and third and fourth quarters of 2020;
▪Coal-related parts and materials inventory write-downs incurred in the second and third quarters of 2021;
▪The impact of the updated provision estimates for the transmission line loss rule during the first quarter of 2021 and the last three quarters of 2020;
▪Significant foreign exchange gains in the last three quarters of 2020, which more than offset foreign exchange losses experienced during the first quarter of 2020;
▪The effects of impairments and reversals during all periods shown;
▪The effects of changes in decommissioning and restoration provisions for retired assets in all periods shown;
▪The effects of changes in useful lives of certain assets during the third quarter of 2020; and
▪Current tax expense increases since the fourth quarter of 2020, mainly due to the Energy Marketing segment and certain Hydro operations becoming taxable, increased valuation allowances taken on US deferred tax assets along with a decreased deferred tax recovery mainly due to increased revenues in 2021.





TRANSALTA CORPORATION M30

Management’s Discussion and Analysis
Financial Position
The following table highlights significant changes in the consolidated statements of financial position from Dec. 31, 2020, to Dec. 31, 2021:
AssetsDec. 31, 2021Dec. 31, 2020Increase/(decrease)
Current assets
Cash and cash equivalents947 703 244 
Trade and other receivables651 583 68 
Risk management assets308 171 137 
Inventory167 238 (71)
Assets held for sale25 105 (80)
Other current assets(1)
99 102 (3)
Total current assets2,197 1,902 295 
Non-current assets
Risk management assets399 521 (122)
Property, plant and equipment, net5,320 5,822 (502)
Right-of-use assets95 141 (46)
Other non-current assets(2)
1,215 1,361 (146)
Total non-current assets7,029 7,845 (816)
Total assets9,226 9,747 (521)
Liabilities
Current liabilities
Credit facilities, long-term debt and lease liabilities (current)844 105 739 
Other current liabilities(3)
1,087 830 257 
Total current liabilities1,931 935 996 
Non-current liabilities
Credit facilities, long-term debt and lease liabilities2,423 3,256 (833)
Decommissioning and other provisions (long-term)779 614 165 
Risk management liabilities (long-term)145 68 77 
Deferred income tax liabilities354 396 (42)
Other non-current liabilities(4)
1,001 1,042 (41)
Total non-current liabilities4,702 5,376 (674)
Total liabilities6,633 6,311 322 
Equity
Equity attributable to shareholders1,582 2,352 (770)
Non-controlling interests1,011 1,084 (73)
Total equity2,593 3,436 (843)
Total liabilities and equity9,226 9,747 (521)
(1) Includes restricted cash and prepaid expenses.
(2) Includes investments, long-term portion of finance lease receivables, intangible assets, goodwill, deferred income tax assets and other assets.
(3) Includes accounts payable and accrued liabilities, current portion of decommissioning and other provisions, current portion of contract liabilities, income taxes payable and dividends payable.
(4) Includes exchangeable securities, contract liabilities and defined benefit obligation and other long-term liabilities.





TRANSALTA CORPORATION M31

Management’s Discussion and Analysis
Significant changes in TransAlta's consolidated statements of financial position were as follows:

Working Capital
Including the current portion of long term debt and lease liabilities, the excess of current assets over current liabilities was $266 million as at Dec. 31, 2021 (2020 - $967 million). Our working capital decreased year over year mainly due to the reclassification of debt from long-term to current. Excluding the current portion of long-term debt and lease liabilities of $844 million, the excess of current assets over liabilities was $1,110 million as at Dec. 31, 2021 (2020 - $1,072 million), consistent with the previous year.

Current assets increased by $295 million to $2,197 million as at Dec. 31, 2021, from $1,902 million as at Dec. 31, 2020. Strong Alberta pricing has increased operating cash flow and receivables. In addition, a loan receivable relating to Kent Hills Wind LP of $55 million was reclassified as current as it matures in October 2022. This was partially offset by reductions in inventory of $71 million and in assets held for sale of $80 million. Inventory balances have declined with coal inventory write-downs and parts and material write-downs relating to the transition off of coal and the closure of the Highvale mine. Assets held for sale decreased with the closing of the Pioneer Pipeline sale during the year.

Current liabilities increased by $996 million from $935 million as at Dec. 31, 2020, to $1,931 million as at Dec. 31, 2021, mainly due to the reclassification to current of $510 million Senior Notes coming due in 2022 and the reclassification of the Kent Hills bond of $221 million as the KH Bonds may be in default at the end of the year. We currently expect to refinance the senior notes maturing in 2022. Management is in discussions with the Trustee and holders of the KH Bonds to negotiate waivers and amendments related to the KH Bonds.

Derivative financial instruments also contributed favourably to the working capital balance.

Non-Current Assets
Non-Current assets at Dec. 31, 2021 was $7,029 million, a decrease of $816 million from $7,845 million as at Dec. 31, 2020. The decrease was primarily due to the asset impairments that have occurred during the year. The Energy Transition segment recognized $345 million of asset impairment charges in the year as a result of the decision to suspend the Sundance Unit 5 repowering project and the planned retirements of Keephills Unit 1 and Sundance Unit 4. In addition, with the completion of the transition to gas of the Alberta coal fleet, the Highvale mine was removed from the Alberta Merchant CGU, which resulted in an impairment recognized on the remaining mine assets, further reducing the property, plant and equipment ("PP&E") balance by $195 million. These impacts were partially offset by the construction of the Windrise wind facility and Garden Plain wind project, as well as the acquisition of the North Carolina Solar facility.

During 2021, the Company completed the sale of the Pioneer Pipeline to ATCO and derecognized the right- of-use asset of $43 million relating to the natural gas transportation agreement that was terminated as part of the transaction.

Non-Current Liabilities
Non-Current liabilities as at Dec. 31, 2021, are $4,702 million, a decrease of $674 million from $5,376 million as at Dec. 31, 2020, mainly due to a $833 million decrease in long-term debt and lease liabilities related in most part to the reclassification of the Senior Notes and KH Bonds to current liabilities, derecognition of the lease liability on the termination of the natural gas transportation agreement and from scheduled principal repayments on long-term debt and lease liabilities. This was partially offset by a $120 million increase in the wind decommissioning provisions resulting from a review of a recent wind engineering study on the decommissioning of the wind sites. The change in estimate is unrelated to the tower failure identified in the fourth quarter of 2021. In addition, the Company had a $47 million increase related to the Sundance and Keephills facilities to reflect a change in the timing of the expected reclamation work resulting from asset retirements and change in useful lives.

Total Equity
As at December 31, 2021, the decrease in total equity of $843 million was mainly due to the total comprehensive loss of $610 million, distributions to non-controlling interests of $156 million and dividends declared on common and preferred shares of $90 million, partially offset by the effect of shared-based payment plans of $13 million.





TRANSALTA CORPORATION M32

Management’s Discussion and Analysis
Financial Capital
The Company 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 Company's financing costs, liquidity and operations and affect the Company's ability to obtain short-term and long-term financing and/or the cost of such financing. Maintaining a strong balance sheet also allows the Company to enter into contracts with a variety of counterparties on terms and prices that are favourable to the Company’s financial results and provide TransAlta with better access to capital markets through commodity and credit cycles.

In 2021, Moody’s reaffirmed its Corporate Family Rating of Ba1 and maintained its rating outlook at stable. During 2021, DBRS Limited confirmed the Company’s Issuer Rating and Unsecured Debt/Medium-Term Notes rating of BBB (low), and the Company's Preferred Shares rating of Pfd-3 (low), all with stable trends. During 2021, S&P Global Ratings reaffirmed the Company’s Issuer Credit Rating and Senior Unsecured Debt 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.

Capital Structure
A strong financial position provides the Company with better access to capital markets through commodity and credit cycles. We use total capital to help evaluate the strength of our financial position.





TRANSALTA CORPORATION M33

Management’s Discussion and Analysis
Our capital structure consists of the following components as shown below:
As at Dec. 31202120202019
 $  %  $  %  $  %
TransAlta Corporation
Net senior unsecured debt
Recourse debt — CAD debentures
251 4 249 3 647 9 
Recourse debt —US senior notes
888 16 886 13 905 13 
Credit facilities— — 114 2 — — 
Other4 — 7 — 9 — 
Less: cash and cash equivalents(703)(12)(121)(2)(348)(5)
Less: other cash and liquid assets(1)
(19)— (13)— (17)— 
Net senior unsecured debt421 8 1,122 16 1,196 17 
Other debt liabilities
Exchangeable debentures335 6 330 5 326 5 
Non-recourse debt
TAPC Holdings LP bond
102 2 111 2 119 2 
TransAlta OCP bond263 5 284 4 305 4 
Other— — — — 2 — 
Lease liabilities78 1 112 2 119 2 
Total net debt — TransAlta Corporation
1,199 22 1,959 29 2,067 30 
TransAlta Renewables
Net TransAlta Renewables reported debt
Credit facility— — — — 220 3 
Non-recourse debt
Pingston bond45 1 45 1 45 1 
Melancthon Wolfe Wind bond235 4 268 4 298 4 
New Richmond Wind bond120 2 127 2 134 2 
Kent Hills Wind bond221 4 230 3 241 3 
   Windrise Wind bond 171 3 — — — — 
Lease liabilities22 — 22 — 23 — 
Less: cash and cash equivalents(244)(4)(582)(9)(63)(1)
Debt on TransAlta Renewables Economic Investments
US tax equity financing(2)
135 2 134 2 145 2 
South Hedland non-recourse debt(3)
732 13 772 11 — — 
Total net debt — TransAlta Renewables
1,437 25 1,016 14 1,043 14 
Total consolidated net debt(4)(5)
2,636 47 2,975 43 3,110 44 
Non-controlling interests1,011 18 1,084 16 1,101 15 
Exchangeable preferred securities(5)
400 7 400 6 — — 
Equity attributable to shareholders
Common shares2,901 51 2,896 43 2,978 42 
Preferred shares942 17 942 14 942 13 
Contributed surplus, deficit and accumulated other comprehensive
   income		(2,261)(40)(1,486)(22)(959)(14)
Total capital5,629 100 6,811 100 7,172 100 
(1) Includes principal portion of TransAlta OCP restricted cash and fair value asset of hedging instruments on debt.
(2) TransAlta Renewables has an economic interest in the entities holding these debts.
(3) TransAlta Renewables has an economic interest in the Australia entities holding these debts.
(4) The tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in these amounts.
(5) In 2021, total consolidated net debt excludes the exchangeable preferred securities as they are considered equity with dividend payments for credit purposes. In 2020, 50 per cent of the exchangeable preferred securities were classified as debt and included in total consolidated net debt. 2020 has been revised to be consistent with the change in 2021. For accounting purposes, they are accounted for as debt with interest expense in the consolidated financial statements.







TRANSALTA CORPORATION M34

Management’s Discussion and Analysis
Total capital consists of long-term debt, exchangeable securities and equity, less:
▪Available cash and cash equivalents, 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;
▪The principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt; and
▪The fair value of economic and designated hedging instruments on debt in an asset or liability, as the carrying value of the related debt is impacted by changes in foreign exchange rates.

We continued strengthening our financial position during 2021 and have sufficient liquidity to fund our growth strategy.
We have enhanced shareholder value through the following:

2021
▪Obtained $173 million in project financing related to our Windrise wind facility.

2020
▪Obtained 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;
▪Redeemed our outstanding 5 per cent $400 million medium-term notes due on Nov. 25, 2020; and
▪Purchased and cancelled 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.

2019
▪Obtained US$126 million in tax equity financing to fund the Big Level and Antrim wind facilities;
▪Entered into a strategic investment with Brookfield whereby Brookfield agreed to invest $750 million in the Company. 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
▪Purchased and cancelled 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.

Between 2022 and 2024, we have $1,104 million of debt maturing, including $515 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments. We currently expect to refinance the senior notes maturing in 2022.

Credit Facilities
The Company's credit facilities are summarized in the table below:
As at Dec. 31, 2021Facility
size		UtilizedAvailable
capacity		Maturity
date
Outstanding letters of credit(1)
Actual drawings
TransAlta Corporation
Committed syndicated bank facility(2)
1,250618—632Q2 2025
Canadian committed bilateral credit facilities240186—54Q2 2023
TransAlta Renewables
Committed credit facility(2)
70098—602Q2 2025
Total2,190902—1,288
(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, 2021, we provided cash collateral of $55 million.
(2) TransAlta has letters of credit of $157 million and TransAlta Renewables has letters of credit of $98 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities.





TRANSALTA CORPORATION M35

Management’s Discussion and Analysis
The US dollar relative to the Canadian dollar weakened from Dec. 31, 2020 to Dec. 31, 2021, with no impact on our long-term debt balances as at Dec. 31, 2021. The weakening of the US dollar decreased our long-term debt balances as at Dec. 31, 2020 by $24 million. Almost all our US-denominated debt is hedged either through financial contracts or net investments in our US operations.

US Tax Equity Financing
The Company owns equity interests in some facilities that are eligible for tax incentives available for renewable energy facilities in the United States. With its current portfolio of renewable energy facilities, TransAlta cannot fully monetize such tax incentives. To take full advantage of these incentives, the Company partners with Tax Equity Investors (“TEI”) who invest in these facilities in exchange for a share of the tax credits.

Some TEI financing structures include a partial pay as you go ("Pay-go") funding arrangement under which, when the actual annual MWh production exceeds a certain production threshold, the TEI are obligated to make a cash contribution (“Pay-go Contribution”) to the Company. The Pay-go arrangement results in a lower initial investment by the TEI and provides them with some protection from potential underperformance of the asset.

TransAlta recognizes the TEI contributions as long-term debt, at an amount representing the proceeds received from the TEI in exchange for shares of a subsidiary of TransAlta, net of the following elements:
▪Production tax credits ("PTC")— Allocation of PTCs to the TEI derived from the power generated during the period is recognized in other revenues as earned and as a reduction in tax equity financing;
▪Tax shield — Allocation of tax benefits and attributes to the TEI, such as investment tax credits and tax depreciation, is recognized in net interest expense as claimed and as a reduction in tax equity financing;
▪Interest expense — Interest expense using the effective interest rate method is recognized in net interest expense as incurred and as an increase in tax equity financing;
▪Pay-go contributions — Additional cash contributions made by the TEI when the annual production exceeds the contractually determined threshold and is recognized as an increase in tax equity financing; and
▪Cash distributions — Cash payments to the TEI, recognized as a reduction in tax equity financing.

Production Tax Credit Program
Current United States tax law allows qualified wind energy projects to receive tax credits that are earned for each MWh of generation during the first 10 years of the projects' operation. The TEIs are allocated a portion of the renewable energy facility's taxable income (losses) and PTCs produced and a portion of the cash generated by the facility until they achieve an agreed-upon after-tax investment return (“Flip Point”). After the Flip Point, the TEI will retain a lesser portion of the cash and the taxable income (losses) generated by the facility.
FacilityCommercial operation dateExpected Flip PointInitial TEI investment ($)Expected annual PTC generation ($)Expected annual Pay-go Contribution ($)TEI allocation of taxable income and PTCs
(pre-Flip Point)		TEI allocation of cash distributions
(pre-Flip Point) ($)
Lakeswind2014202945 4 — 99 %22 
Big Level and Antrim20192030126 9 — 99 %58 
Skookumchuck(1)
20202029 - 2030121 10 — 99 %29 
(1) The Company has 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.





TRANSALTA CORPORATION M36

Management’s Discussion and Analysis
Non-Recourse Debt
The Melancthon Wolfe Wind LP, Pingston, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd notes, Windrise Wind LP and TransAlta OCP LP non-recourse bonds with a carrying value of $1.9 billion (Dec. 31, 2020 — $1.8 billion) are subject to customary financing conditions and covenants that may restrict the Company’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 fourth quarter of 2021, except the Kent Hills non-recourse bond as discussed below. However, funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2022. At Dec. 31, 2021, $67 million (Dec. 31, 2020 — $73 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.

In connection with the foundation issues at Kent Hills 1 and 2 wind facilities, Kent Hills Wind LP has provided notice to the Trustee, BNY Trust Company of Canada, for the approximately $221 million outstanding non-recourse KH Bonds secured by, among other things, the Kent Hills 1, 2 and 3 wind facilities, that events of default may have occurred under the trust indenture governing the terms of such bonds. The Company is in discussions with the Trustee and holders of the KH Bonds to negotiate waivers and amendments. Refer to the Significant and Subsequent Events section of this MD&A for further details on the Kent Hills 1 and 2 wind facilities outage.

Returns to Providers of Capital
Net Interest Expense
The components of net interest expense are shown below:
Year ended Dec. 31202120202019
Interest on debt163 158 161 
Interest on exchangeable debentures29 29 20 
Interest on exchangeable preferred shares28 5 — 
Interest income(11)(10)(13)
Capitalized interest(14)(8)(6)
Interest on lease liabilities7 8 4 
Credit facility fees, bank charges and other interest18 18 15 
Tax shield on tax equity financing(1)
(9)1 (35)
Interest on the line loss proceeding— 5 — 
Other(2)
2 2 10 
Accretion of provisions32 30 23 
Net interest expense245 238 179 
(1) Credit in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar facility that was assigned to the tax equity investor. Credit in 2019 primarily relates to the tax benefit associated with bonus tax depreciation claimed in 2019 on the Big Level and Antrim wind facilities 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 and investment tax credits (as applicable) is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.
(2) In 2021, other interest expense included approximately nil (2020 — nil; 2019 — $5 million) for the significant financing component required under IFRS 15.

Net interest expense was higher in 2021 primarily due to the full year of interest incurred on the exchangeable preferred shares issued in the fourth quarter of 2020, project financing related to the South Hedland non-recourse debt obtained in the fourth quarter of 2020 and additional project financing related to the Windrise wind facility obtained in the fourth quarter of 2021, partially offset by an increase in capitalized interest on the construction of development projects, the redemption of the $400 million medium-term notes in the fourth quarter of 2020 and lower interest on other debt balances due to scheduled repayments and investment tax credits related to the North Carolina Solar facility tax equity.

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 Agreement 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 wind facilities offset by the termination of the Keephills 3 contract liability in 2019, resulting in the deferred financing costs being recognized.





TRANSALTA CORPORATION M37

Management’s Discussion and Analysis
Share Capital
On March 18, 2021, the Company announced that 1,417,338 of its 10.2 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") and 871,871 of its 1.8 million Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares") were tendered for conversion, on a one-for-one basis, into Series B Shares and Series A Shares, respectively, after having taken into account all election notices. As a result of the conversion, the Company had 9.6 million Series A Shares and 2.4 million Series B Shares issued and outstanding at March 31, 2021.

The following tables outline the common and preferred shares issued and outstanding:
As atFeb. 23, 2022Dec. 31, 2021Dec. 31, 2020
 
Number of shares (millions)
Common shares issued and outstanding, end of period271.2271.0 269.8 
Preferred shares   
Series A9.6 9.6 10.2 
Series B2.4 2.4 1.8 
Series C11.0 11.0 11.0 
Series E9.0 9.0 9.0 
Series G6.6 6.6 6.6 
Preferred shares issued and outstanding in equity, end of period38.6 38.6 38.6 
Series I - Exchangeable Securities(1)
0.4 0.4 0.4 
Preferred shares issued and outstanding, end of period39.0 39.0 39.0 
(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.

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 2021:
 CommonPreferred Series dividends per share
 Payable datedividends     
Declaration dateCommon sharesPreferred sharesper shareABCEG
May 3, 2021Jul 1, 2021Jun 30, 20210.0450 0.17981 0.13108 0.25169 0.32463 0.31175 
Aug 5, 2021Oct.1, 2021Sept. 30, 20210.0450 0.17981 0.13479 0.25169 0.32463 0.31175 
Nov 1, 2021Jan 1, 2022Dec. 31. 20210.0500 0.17981 0.13970 0.25169 0.32463 0.31175 
Dec 31, 2021Apr 1, 2022Mar 31, 20220.0500 0.179810.133090.251690.324630.31175

Non-Controlling Interests
As of Dec. 31, 2021, the Company owns 60.1 per cent (2020 — 60.1 per cent) of TransAlta Renewables.

In 2020, our ownership per cent (60.1 per cent) decreased from our ownership in 2019 (60.4 per cent) due to TransAlta Renewables issuing approximately one 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 (Sheerness) for 2021 which will operate as a natural-gas-fired facility in 2022. 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.





TRANSALTA CORPORATION M38

Management’s Discussion and Analysis
Reported earnings attributable to non-controlling interests for the year ended Dec. 31, 2021, increased by $78 million to $112 million compared to 2020. Earnings increased at TransAlta Renewables in 2021 mainly due to higher finance income from investments in subsidiaries of TransAlta and no fair value losses recognized in the current year, partially offset by liquidating damages provisions related to unplanned outages at Sarnia cogeneration facility, unfavourable steam reconciliation adjustment to Canadian Gas, lower wind production from the Canadian wind fleet, lower foreign exchange gains and higher asset impairments. Earnings from TA Cogen were higher in 2021 mainly due to higher prices in the Alberta market. Refer to Note 13 of the consolidated financial statements for further details.
 
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 and 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.

Other Consolidated Analysis
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, 2021, we provided letters of credit totalling $902 million (2020 — $621 million) and cash collateral of $55 million (2020 — $49 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. The increase in the amount of letters of credit issued during 2021 relates to the increased energy marketing activity, including the full requirements business, as well as pension plan commitments and the Highvale mine pension plan and reclamation obligations.

Commitments
Contractual commitments are as follows:
 202220232024202520262027 and thereafterTotal
Natural gas, transportation and other contracts47 54 45 44 45 508 743 
Transmission9 9 6 6 2 — 32 
Coal supply and mining agreements76 98 90 75 — — 339 
Long-term service agreements89 46 43 32 25 54 289 
Operating leases(1)
4 3 3 1 1 31 43 
Long-term debt(2)
836 155 113 127 127 1,840 3,198 
Exchangeable securities(3)
— — — 750 — — 750 
Principal payments on lease liabilities(4)
(6)4 3 3 3 93 100 
Interest on long-term debt and lease liabilities(5,6)
149 120 115 109 104 787 1,384 
Interest on exchangeable securities(3,6)
53 53 62 — — — 168 
Growth(7)
941 276 — — — — 1,217 
TransAlta Energy Transition Bill6 6 — — — — 12 
Total2,204 824 480 1,147 307 3,313 8,275 
(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 2022.
(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.
(7) For further details on growth commitments, refer to the Accelerated Clean Electricity Growth Plan section of this MD&A.




TRANSALTA CORPORATION M39

Management’s Discussion and Analysis
Contingencies 
Transmission Line Loss Rule Proceeding 
The Company 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. The AUC approved an invoice settlement process and all three planned settlements have been received. The first two invoices were settled by the first quarter of 2021 and the third invoice settled in the second quarter of 2021. The true-up invoices issued by the AESO in the fourth quarter of 2021 were settled by Dec. 31, 2021, with no further invoices expected.

FMG Dispute at South Hedland Power Station
On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.

Mangrove Claim
On April 23, 2019, Mangrove commenced an action in the Ontario Superior Court of Justice naming the Company, the incumbent members of the Board of the Company on such date, and Brookfield as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 2021.

Keephills 1 Stator Force Majeure Appeal
The Balancing Pool and 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 was heard on July 8, 2021. After the hearing, counsel for ENMAX raised concerns that one of the three justices on the appeal panel was distracted during the hearing. The justice has since recused herself from the hearing and the parties made submissions with respect to whether the remaining two justices can continue to issue the decision or whether a new hearing is required. On Nov. 8, 2021, the Alberta Court of Appeal released its decision and ordered that the appeal be re-heard by a new three-person panel of the Court of Appeal, which was heard on Jan. 27, 2022. TransAlta remains of the view 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 claimed force majeure under the Alberta PPA. ENMAX, the purchaser under the Alberta PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.

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 2022 or early 2023. 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
The Balancing Pool claims to be entitled to emission performance credits ("EPCs") earned by the Hydro facilities as a result of opting those facilities into the Carbon Competitiveness Incentive Regulation from 2018-2020 inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs or from any purported change in law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced, and the hearing is scheduled for Feb. 6-10, 2023.




TRANSALTA CORPORATION M40

Management’s Discussion and Analysis
Direct Assigned Capital Deferral Account ("DACDA") Application
AltaLink Management Ltd. ("AltaLink") and TransAlta (as a secondary applicant) filed an application before the AUC to recover its 2016-2018 DACDA costs incurred for the 240 kV line upgrades for the Edmonton Region Project. The AUC disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta disputed this finding and filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC (the “R&V”). The AUC dismissed the R&V application on April 22, 2021. The permission to appeal was subsequently discontinued on July 5, 2021, which concludes this matter.

Sarnia Outages
The Sarnia cogeneration facility experienced three separate outages between May 19, 2021 and June 9, 2021 that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent at the Sarnia cogeneration facility. The Company conducted an investigation to determine the root cause of each of the three events, which concluded that all three events do not qualify as events of force majeure. As such, liquidated damages in an amount dictated by the applicable agreements are payable by TransAlta to the customers for the three outages and have been accrued within contract liabilities.

Kaybob 3 Cogeneration Dispute
The Company is engaged in a dispute with Energy Transfer Canada ULC, formerly SemCAMS Midstream ULC (“ET Canada”) as a result of ET Canada’s purported termination of agreements between the parties to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing facility. TransAlta commenced an arbitration seeking full compensation for ET Canada's wrongful termination of the agreements. ET Canada seeks a declaration that the agreements were lawfully terminated. A hearing is scheduled for two weeks starting Jan. 9, 2023.

Cash Flows
The following chart highlights significant changes in the consolidated statements of cash flows for the years ended Dec. 31, 2021, Dec. 31, 2020 and Dec. 31, 2019:
Year ended Dec. 3120212020Increase/ (decrease)
Cash and cash equivalents, beginning of year703 411 292 
Provided by (used in):  
Operating activities1,001 702 299 
Investing activities(472)(687)215 
Financing activities(282)272 (554)
Translation of foreign currency cash(3)5 (8)
Cash and cash equivalents, end of year947 703 244 

Cash provided by operating activities for the year ended Dec. 31, 2021, increased compared with 2020 primarily due to to higher revenues being realized in Alberta on the merchant assets, partially offset by higher fuel and purchased power and OM&A costs as the Company transitions off coal.

Cash used in investing activities for the year ended Dec. 31, 2021, decreased compared with 2020, largely due to:
▪No acquisitions of investments in 2021 compared to Skookumchuck and EMG International LLC ("EMG") in 2020 ($102 million);
▪Proceeds on the sale of Pioneer Pipeline ($128 million) and the sale of equipment within the Energy Transition segment ($39 million); and
▪Higher cash spent on the North Carolina Solar facility acquisition ($120 million) in 2021 compared to the Ada acquisition of ($32 million) in 2020.

Cash used in financing activities for the year ended Dec. 31, 2021, increased compared with 2020, largely due to:
▪Lower debt issuances in 2021. Issuance of the Windrise Wind LP bond of $173 million in 2021 compared to $753 million in long-term debt from the TEC Offering and $400 million in exchangeable securities in 2020;
▪Increased distributions paid to subsidiaries' non-controlling interests ($59 million);
▪Partially offset by lower repayments on long term debt ($397 million); and
▪Lower common share repurchases under the NCIB ($53 million).





TRANSALTA CORPORATION M41

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 earnings ("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 that 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 M42

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, 2021, Level III instruments had a net asset carrying value of $159 million (2020 — $582 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, 2020.

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, 2021, 2020 and 2019. Presenting these line items provides management and investors with a measurement of ongoing operating performance that is readily comparable from period to period.

We use a number of financial measures to evaluate our performance and the performance of our business segments, including measures and ratios that are presented on a non-IFRS basis, as described below. Unless otherwise indicated, all amounts are in Canadian dollars and have been derived from our audited annual consolidated financial statements prepared in accordance with IFRS. We believe that these non-IFRS amounts, measures and ratios, read together with our IFRS amounts, provide readers with a better understanding of how management assesses results.

Non-IFRS amounts, measures and ratios do not have standardized meanings under IFRS. They are unlikely to be comparable to similar measures presented by other companies and should not be viewed in isolation from, or as an alternative for, or more meaningful than our IFRS results.

Non-IFRS Financial Measures
Adjusted EBITDA, FFO, FCF, total net debt, total consolidated net debt and adjusted net debt are non-IFRS measures that are presented in this MD&A. See the Segmented Financial Performance and Operating Results, Segmented Financial Performance and Operating Results for the Fourth Quarter, Selected Quarterly Information, Financial Capital and Key Non-IFRS Financial Ratios sections of this MD&A for additional information, including a reconciliation of such non-IFRS measures to the most comparable IFRS measure.
 




TRANSALTA CORPORATION M43

Management’s Discussion and Analysis
Adjusted EBITDA
In the fourth quarter of 2021, comparable EBITDA was relabelled as adjusted EBITDA to align with industry standard terminology. Each business segment assumes responsibility for its operating results measured to adjusted EBITDA. Adjusted EBITDA is 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, certain reclassifications and adjustments are made to better assess results excluding those items that may not be reflective of ongoing business performance. This presentation may facilitate the readers analysis of trends. Adjusted EBITDA is a non-IFRS measure. The following are descriptions of the adjustments made.

Adjustments to revenue
▪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.
▪Adjusted EBITDA is adjusted to exclude the impact of unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions.

Adjustments to fuel and purchased power
▪We adjust for depreciation on our mining equipment included in fuel and purchased power.
▪We adjust for items resulting from the decision in 2020 to accelerate being off-coal and accelerating the shutdown of the Highvale mine by the end of 2021 as not reflective of ongoing business performance. Within fuel and purchased power this included coal inventory write-downs.
▪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.

Adjustments to operations, maintenance and administration
▪We adjust for write-down of parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities.
▪We adjust for the curtailment gain related to the Highvale mine defined-benefit pension plan.

Adjustments to net other operating income (expense)
▪We adjust for the onerous contract provision for future royalty payments recognized with the shutdown of the Highvale mine.
▪We adjust for the Sheerness going off-coal which 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.

Adjustments to earnings in addition to interest, taxes, depreciation and amortization
▪Asset impairment charges (reversals) are removed as these are accounting adjustments that impact depreciation and amortization and do not reflect business performance.
▪Any gains or losses on asset sales or foreign exchange gains or losses are not included as these are not part of operating income.

Adjustments for equity accounted investments
▪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 adjusted EBITDA of Skookumchuck in our total adjusted EBITDA. In addition, in the Wind and Solar adjusted 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 adjusted EBITDA in our total adjusted EBITDA as it does not represent our regular power-generating operations.






TRANSALTA CORPORATION M44

Management’s Discussion and Analysis
Average Annual EBITDA
Average annual EBITDA is a non-IFRS financial measure that is forward-looking, used to show the average annual EBITDA that the project currently under construction is expected to generate upon completion.

Funds From Operations ("FFO")
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. FFO is a non-IFRS measure.

Adjustments to cash from operations
▪Includes FFO related to the Skookumchuk wind facility, which is treated as an equity accounted investment under IFRS and equity income, net of distributions from joint ventures is included in cash flow from operations under IFRS. As this investment is part of our regular power generating operations, we have included our proportionate share of FFO.
▪Payments received on finance lease receivables reclassified to reflect cash from operations.
▪We adjust for items included in cash from operations related to the decision in 2020 to accelerate being off-coal and accelerating the shutdown of the Highvale mine by the end of 2021, and the write-down on parts and material inventory for our coal operations ("Clean energy transition provisions and adjustments").

Free Cash Flow
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. FCF is a non-IFRS measure.

Non-IFRS Ratios
FFO per share, FCF per share, FFO before interest to adjusted interest coverage and adjusted net debt to adjusted EBITDA are non-IFRS ratios that are presented in the MD&A. See the Reconciliation of Cash Flow from Operations to FFO and FCF and Key Non-IFRS Financial Ratios sections of this MD&A for additional information.

FFO per Share and FCF per Share
FFO per share and FCF per share are calculated using the weighted average number of common shares outstanding during the period. FFO per share and FCF per share is a non-IFRS ratio.

Supplementary Financial Measures
Financial highlights presented on a proportional basis of TransAlta Renewables, deconsolidated adjusted EBITDA, deconsolidated FFO and deconsolidated adjusted EBITDA to deconsolidated FFO are supplementary financial measures the Company uses to present adjusted EBITDA on a deconsolidated basis. See the Financial Highlights on a Proportional Basis of TransAlta Renewables and Key Non-IFRS Financial Ratios sections of this MD&A for additional information.

The Alberta Electricity Portfolio metrics disclosed are also supplementary financial measures used to present the gross margin by segment for the Alberta market. See the Alberta Electricity Portfolio section of this MD&A for additional information.




TRANSALTA CORPORATION M45

Management’s Discussion and Analysis
Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment
The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the three months ended Dec. 31, 2021:
Attributable to common shareholders
Hydro
Wind & Solar(1)
GasEnergy TransitionEnergy
Marketing		CorporateTotal
Equity accounted investments(1)
Reclass adjustmentsIFRS financials
Revenues84 98 172 238 26 (2)616 (6)— 610 
Reclassifications and adjustments:
Unrealized mark-to-market
  (gain) loss		— 3 82 (8)(12)— 65 — (65)— 
Decrease in finance lease
  receivable		— — 11 — — — 11 — (11)— 
Finance lease income— — 6 — — — 6 — (6)— 
Unrealized foreign exchange
  (gain) loss on commodity		— — — — — — — — — — 
Adjusted revenues84 101 271 230 14 (2)698 (6)(82)610 
Fuel and purchased power9 6 110 149 — (2)272 — — 272 
Reclassifications and adjustments:
Australian interest income— — (1)— — — (1)— 1 — 
Mine depreciation— — — (11)— — (11)— 11 — 
Coal Inventory write-down— — — (1)— — (1)— 1 — 
Adjusted fuel and purchased
  power		9 6 109 137 — (2)259 — 13 272 
Carbon compliance— — 14 25 — — 39 — — 39 
Gross margin75 95 148 68 14 — 400 (6)(95)299 
OM&A7 17 46 20 5 29 124 — — 124 
Reclassifications and adjustments:
Parts and materials write-down— — — 3 — — 3 — (3)— 
Curtailment gain— — — 6 — — 6 — (6)— 
Adjusted OM&A7 17 46 29 5 29 133 — (9)124 
Taxes, other than income taxes1 2 2 1 — — 6 — — 6 
Net other operating income— — (10)(8)— — (18)— — (18)
Reclassifications and adjustments:
Royalty onerous contract and
  contract termination penalties		— — — 9 — — 9 — (9)— 
Adjusted net other operating
  income		— — (10)1 — — (9)— (9)(18)
Adjusted EBITDA67 76 110 37 9 (29)270 
Equity income4 
Finance income from subsidiaries6 
Depreciation and amortization(134)
Asset impairment
(28)
Net interest expense(59)
Foreign exchange loss(6)
Gain on sale of assets and other(2)
Loss before income taxes
(32)
(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. Includes reclassification adjustments.




TRANSALTA CORPORATION M46

Management’s Discussion and Analysis
The following table reflects Adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the three months ended Dec. 31, 2020:
Attributable to common shareholders
Hydro
Wind & Solar(1)
GasEnergy TransitionEnergy
Marketing		CorporateTotal
Equity accounted investments(1)
Reclass adjustmentsIFRS financials
Revenues31 92 167 230 19 8 547 (3)— 544 
Reclassifications and adjustments:
Unrealized mark-to-market
  (gain) loss		— 10 34 (10)10 — 44 — (44)— 
Decrease in finance lease
  receivable		— — 6 — — — 6 — (6)— 
Finance lease income— — 3 — — — 3 — (3)— 
Unrealized foreign exchange
  (gain) loss on commodity		— — 4 — — — 4 — (4)— 
Adjusted revenues31 102 214 220 29 8 604 (3)(57)544 
Fuel and purchased power(1)11 98 166 — 8 282 — — 282 
Reclassifications and adjustments:
Australian interest income— — (1)— — — (1)— 1 — 
Mine depreciation— — (40)(18)— — (58)— 58 — 
Coal inventory write-down— — — (15)— — (15)— 15 — 
Adjusted fuel and purchased
  power		(1)11 57 133 — 8 208 — 74 282 
Carbon compliance— — 30 15 — — 45 — — 45 
Gross margin32 91 127 72 29 — 351 (3)(131)217 
OM&A9 13 42 27 6 21 118 — — 118 
Taxes, other than income taxes1 1 2 3 — 1 8 — — 8 
Net other operating expense
  (income)		— — 19 — — — 19 — — 19 
Reclassifications and adjustments:
Impact of Sheerness going
  off-coal		— — (28)— — — (28)— 28 — 
Adjusted net other operating
  income		— — (9)— — — (9)— 28 19 
Adjusted EBITDA22 77 92 42 23 (22)234 
Equity income1 
Finance income from subsidiaries4 
Depreciation and amortization(173)
Asset impairment(17)
Net interest expense(64)
Foreign exchange loss2 
Gain on sale of assets and other7 
Loss before income taxes
(168)
(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment. Includes reclassification adjustments.




TRANSALTA CORPORATION M47

Management’s Discussion and Analysis
Reconciliation of Cash flow from operations to FFO and FCF  
The table below reconciles our cash flow from operating activities to our FFO and FCF for the three months ended Dec. 31, 2021 and 2020: 
Three months ended Dec. 3120212020
Cash flow from operating activities(1)
54 110 
Change in non-cash operating working capital balances148 25 
Cash flow from operations before changes in working capital202 135 
Adjustments  
Share of adjusted FFO from joint venture(1)
6 3 
Decrease in finance lease receivable11 6 
Clean energy transition provisions and adjustments(2)
(6)15 
Other(3)
— 2 
FFO(4)
213 161 
Deduct:  
Sustaining capital(1)
(55)(58)
Productivity capital(2)(3)
Dividends paid on preferred shares(10)(9)
Distributions paid to subsidiaries’ non-controlling interests(38)(29)
Principal payments on lease liabilities(1)
(2)(10)
FCF(4)
106 52 
Weighted average number of common shares outstanding in the period271 273 
FFO per share(4)
0.79 0.59 
FCF per share(4)
0.39 0.19 
(1) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.
(2) Includes write-down on parts and material inventory for our coal operations, write-down on coal inventory to net realizable value and amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project.
(3) Other consists of production tax credits which is a reduction to tax equity debt.
(4) These items are not defined and have no standardized meaning under IFRS. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF for the three months ended Dec. 31, 2021 and 2020:
Three months ended Dec. 3120212020
Adjusted EBITDA(1)
270 234 
Provisions(18)(10)
Interest expense(2)
(51)(56)
Current income tax expense(2)
3 5 
Realized foreign exchange loss(4)(1)
Decommissioning and restoration costs settled(2)
(5)(5)
Other non-cash items18 (6)
FFO(3)
213 161 
Deduct:
Sustaining capital(2)
(55)(58)
Productivity capital(2)(3)
Dividends paid on preferred shares(10)(9)
Distributions paid to subsidiaries’ non-controlling interests(38)(29)
Principal payments on lease liabilities(2)
(2)(10)
 FCF(3)
106 52 
(1) Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to earnings (loss) before income taxes above.
(2) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.
(3) FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to cash flow from operating activities above.





TRANSALTA CORPORATION M48

Management’s Discussion and Analysis
Reconciliation of Non-IFRS Measures on a Consolidated Basis by Segment
The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings (loss) before income taxes for the year ended Dec. 31, 2021:
Attributable to common shareholders
Hydro
Wind & Solar(1)
GasEnergy TransitionEnergy
Marketing		CorporateTotal
Equity accounted investments(1)
Reclass adjustmentsIFRS financials
Revenues383 323 1,109 709 211 4 2,739 (18)— 2,721 
Reclassifications and adjustments:
Unrealized mark-to-market
  (gain) loss		— 25 (40)19 (38)— (34)— 34 — 
Decrease in finance lease
  receivable		— — 41 — — — 41 — (41)— 
Finance lease income— — 25 — — — 25 — (25)— 
Unrealized foreign exchange
  gain on commodity		— — (3)— — — (3)— 3 — 
Adjusted revenues383 348 1,132 728 173 4 2,768 (18)(29)2,721 
Fuel and purchased power16 17 457 560 — 4 1,054 — — 1,054 
Reclassifications and adjustments:
Australian interest income— — (4)— — — (4)— 4 — 
Mine depreciation— — (79)(111)— — (190)— 190 — 
Coal inventory write-down— — — (17)— — (17)— 17 — 
Adjusted fuel and purchased
  power		16 17 374 432 — 4 843 — 211 1,054 
Carbon compliance— — 118 60 — — 178 — — 178 
Gross margin367 331 640 236 173 — 1,747 (18)(240)1,489 
OM&A42 59 175 117 36 84 513 (2)— 511 
Reclassifications and adjustments:
Parts and materials write-down— — (2)(26)— — (28)— 28 — 
Curtailment gain— — — 6 — — 6 — (6)— 
Adjusted OM&A42 59 173 97 36 84 491 (2)22 511 
Taxes, other than income taxes3 10 13 6 — 1 33 (1)— 32 
Net other operating expense
  (income)		— — (40)48 — — 8 — — 8 
Reclassifications and adjustments:
Royalty onerous contract and
  contract termination penalties		— — — (48)— — (48)— 48 — 
Adjusted net other operating
  income		— — (40)— — — (40)— 48 8 
Adjusted EBITDA322 262 494 133 137 (85)1,263 
Equity income from associate9 
Finance lease income
25 
Depreciation and amortization(529)
Asset impairment(648)
Net interest expense(245)
Foreign exchange gain
16 
Gain on sale of assets and other54 
Loss before income taxes
(380)
(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.




TRANSALTA CORPORATION M49

Management’s Discussion and Analysis
Year ended Dec. 31, 2020 Attributable to common shareholders
Hydro
Wind & Solar(1)
GasEnergy TransitionEnergy
Marketing		CorporateTotal
Equity accounted investments(1)
Reclass adjustmentsIFRS financials
Revenues152 332 787 704 122 7 2,104 (3)— 2,101 
Reclassifications and adjustments:
Unrealized mark-to-market
  (gain) loss		— 2 33 (14)21 — 42 — (42)— 
Decrease in finance lease
  receivable		— — 17 — — — 17 — (17)— 
Finance lease income— — 7 — — — 7 — (7)— 
Unrealized foreign exchange
loss on commodity		— — 4 — — — 4 — (4)— 
Adjusted revenues152 334 848 690 143 7 2,174 (3)(70)2,101 
Fuel and purchased power8 25 325 435 — 12 805 — — 805 
Reclassifications and adjustments:
Australian interest income— — (4)— — — (4)— 4 — 
Mine depreciation— — (100)(46)— — (146)— 146 — 
Coal inventory write-down— — — (37)— — (37)— 37 — 
Adjusted fuel and purchased
  power		8 25 221 352 — 12 618 — 187 805 
Carbon compliance— — 120 48 — (5)163 — — 163 
Gross margin144 309 507 290 143 — 1,393 (3)(257)1,133 
OM&A37 53 166 106 30 80 472 — — 472 
Taxes, other than income taxes2 8 13 9 — 1 33 — — 33 
Net other operating expense
  (income)		— — (11)— — — (11)— — (11)
Reclassifications and adjustments:
Impact of Sheerness going
  off-coal		— — (28)— — — (28)— 28 — 
Adjusted net other operating
  income		(39)— — — (39)— 28 (11)
Adjusted EBITDA105 248 367 175 113 (81)927 
Equity income from associate1 
Finance lease income7 
Depreciation and amortization(654)
Asset impairment(84)
Net interest expense(238)
Foreign exchange loss17 
Gain on sale of assets and other9 
Loss before income taxes(303)
(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.





TRANSALTA CORPORATION M50

Management’s Discussion and Analysis
Year ended Dec. 31, 2019 Attributable to common shareholders
HydroWind & SolarGasEnergy TransitionEnergy
Marketing		CorporateTotalReclass adjustmentsIFRS financials
Revenues156 312 851 905 129 (6)2,347 — 2,347 
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss— (17)6 (12)(10)— (33)33 — 
Decrease in finance lease receivable— — 24 — — — 24 (24)— 
Finance lease income— — 6 — — — 6 (6)— 
Adjusted revenues156 295 887 893 119 (6)2,344 3 2,347 
Fuel and purchased power7 16 315 539 — 4 881 — 881 
Reclassifications and adjustments:
Australian interest income— — (4)— — — (4)4 — 
Mine depreciation— — (81)(40)— — (121)121 — 
Adjusted fuel and purchased power7 16 230 499 — 4 756 125 881 
Carbon compliance— — 138 77 — (10)205 — 205 
Gross margin149 279 519 317 119 — 1,383 (122)1,261 
OM&A36 50 162 124 30 73 475 — 475 
Taxes, other than income taxes3 8 9 8 — 1 29 — 29 
Net other operating expense (income)— (10)(41)— — 2 (49)— (49)
Termination of Sundance B and C PPAs— — (14)(42)— — (56)— (56)
Adjusted EBITDA110 231 403 227 89 (76)984 
Finance lease income6 
Depreciation and amortization(590)
Asset impairment(25)
Gain on termination of Keephills 3 coal
  rights contract		88 
Net interest expense(179)
Foreign exchange loss(15)
Gain on sale of assets and other46 
Earnings before income taxes193 







TRANSALTA CORPORATION M51

Management’s Discussion and Analysis
Reconciliation of Cash flow from operations to FFO and FCF  
The table below reconciles our cash flow from operating activities to our FFO and FCF:
Year ended Dec. 31202120202019
Cash flow from operating activities(1)(2)
1,001 702 849 
Change in non-cash operating working capital balances(174)(89)(121)
Cash flow from operations before changes in working capital827 613 728 
Adjustments  
Share of adjusted FFO from joint venture(2)
13 3 — 
Decrease in finance lease receivable41 17 24 
Clean energy transition provisions and adjustments(3)
79 37 — 
Other(4)
11 15 5 
FFO(5)
971 685 757 
Deduct:  
Sustaining capital(2)
(199)(157)(141)
Productivity capital(4)(4)(9)
Dividends paid on preferred shares(39)(39)(40)
Distributions paid to subsidiaries’ non-controlling interests(159)(102)(111)
Principal payments on lease liabilities(2)
(8)(25)(21)
FCF(5)
562 358 435 
Weighted average number of common shares outstanding in the year271 275 283 
FFO per share(5)
3.58 2.49 2.67 
FCF per share(5)
2.07 1.30 1.54 
(1) 2019 includes 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.
(3) Includes write-down on parts and material inventory for our coal operations, write-down on coal inventory to net realizable value, amounts due to contractors for not proceeding with the Sundance Unit 5 repowering project and impairment of a previously recognized deferred asset, as it is no longer likely that we will incur sufficient capital or operating expenditures to utilize the remaining credit.
(4) Other consists of production tax credits which is a reduction to tax equity debt.
(5) These items are not defined and have no standardized meaning under IFRS. Refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.

The table below bridges our adjusted EBITDA to our FFO and FCF:
Year ended Dec. 31202120202019
Adjusted EBITDA(1)(2)
1,263 927 984 
Provisions and other(43)7 13 
Interest expense(3)
(200)(192)(174)
Current income tax expense(3)
(55)(35)(35)
Realized foreign exchange gain (loss)(2)8 (6)
Decommissioning and restoration costs settled(3)
(18)(18)(34)
Other cash and non-cash items(4)
26 (12)9 
FFO(5)
971 685 757 
Deduct:  
Sustaining capital(3)
(199)(157)(141)
Productivity capital(4)(4)(9)
Dividends paid on preferred shares(39)(39)(40)
Distributions paid to subsidiaries’ non-controlling interests(159)(102)(111)
Principal payments on lease liabilities(3)
(8)(25)(21)
FCF(5)
562 358 435 
(1) 2019 amounts include the PPA Termination Payments.
(2) Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to earnings (loss) before income taxes above.
(3) Includes our share of amounts for Skookumchuck, an equity accounted joint venture.
(4) Other consists of production tax credits which is a reduction to tax equity debt.
(5) FFO and FCF are defined in the Additional IFRS Measures and Non-IFRS Measures section and reconciled to cash flow from operating activities above.

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

FCF decreased by $77 million in 2020 compared to 2019, primarily due to lower segmented cash flows for the Alberta Thermal facilities included in the Gas and Energy Transition segments and higher sustaining capital expenditures, partially offset by strong cash flows for the Centralia Unit in the Energy Transition segment and lower distributions paid to subsidiaries' non controlling interests. There were no PPA Termination Payments included in 2020.




TRANSALTA CORPORATION M52

Management’s Discussion and Analysis
Financial Highlights on a Proportional Basis of TransAlta Renewables
The proportionate financial information below reflects TransAlta's share of TransAlta Renewables relative to TransAlta's total consolidated figures. The financial highlights presented on a proportional basis of TransAlta Renewables are supplementary financial measures to reflect TransAlta Renewables' portion of the consolidated figures.

Consolidated Results for the year ended Dec. 31
The following table reflects the generation and summary financial information on a consolidated basis for the year ended Dec. 31:
Actual generation (GWh)Adjusted EBITDAEarnings (loss) before income taxes
202120202019202120202019202120202019
TransAlta Renewables
Hydro434 429 393 17 21 18 
Wind and Solar(1)
3,898 4,042 3,355 248 256 238 
Gas(1)
3,236 2,919 3,089 217 205 202 
Corporate— — — (19)(20)(20)
TransAlta Renewables before adjustments7,568 7,390 6,837 463 462 438 133 188 232 
Less: Proportion of TransAlta Renewables not owned by TransAlta Corporation(3,020)(2,938)(2,694)(185)(182)(173)(53)(74)(91)
Portion of TransAlta Renewables owned by TransAlta Corporation4,548 4,452 4,143 278 280 265 80 114 141 
Add: TransAlta Corporation's owned assets excluding TransAlta Renewables
Hydro1,502 1,703 1,652 305 84 92 
Wind and Solar— 27 — 14 (8)(7)
Gas7,329 7,861 8,730 277 162 201 
Energy Transition5,706 7,999 11,852 133 175 227 
Energy Marketing— — — 137 113 89 
    Corporate— — — (66)(61)(56)
TransAlta Corporation with Proportionate Share of TransAlta Renewables19,085 22,042 26,377 1,078 745 811 (433)(377)102 
Non-controlling interests3,020 2,938 2,694 185 182 173 53 74 91 
TransAlta Consolidated22,105 24,980 29,071 1,263 927 984 (380)(303)193 
(1) Wind and Solar and Gas segments include those assets that TransAlta Renewables holds an economic interest in.





TRANSALTA CORPORATION M53

Management’s Discussion and Analysis
Key Non-IFRS 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 2021.
 
Funds from Operations before Interest to Adjusted Interest Coverage
For the year ended Dec. 31202120202019
FFO(1)
971 685 757 
Less: PPA Termination Payments— — (56)
Add: Interest on debt, exchangeable securities and preferred shares and leases, net of
  interest income and capitalized interest(2)
202 182 166 
FFO before interest1,173 867 867 
Interest on debt, exchangeable securities and leases, net of interest income(2)(3)
188 185 172 
Add: 50 per cent of dividends paid on preferred shares(3)
33 22 20 
Adjusted interest221 207 192 
FFO before interest to adjusted interest coverage (times)5.3 4.2 4.5 
(1) See the Segmented Financial Performance and Operating Results section in this MD&A for reconciliation of cash flow from operating activities to FFO. See also the Additional 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.

The FFO before interest to adjusted interest coverage ratio is used by management to assess our ability to pay interest on outstanding debts. Our target for FFO before interest to adjusted interest coverage is 4.0 to 5.0 times. While 2020 and 2019 are within our target range, the 2021 ratio exceeds the high end of our target, and increased compared to 2020, mainly due to higher FFO in 2021 compared to 2020.

Adjusted Net Debt to Adjusted EBITDA (Excluding PPA Termination Payments)
As at Dec. 31202120202019
Period-end long-term debt(1)
3,267 3,361 3,212 
Exchangeable securities335 330 326 
Less: Cash and cash equivalents(947)(703)(411)
Add: 50 per cent of issued preferred shares and exchangeable preferred shares(2)
671 671 471 
Other(3)
(19)(13)(17)
Adjusted net debt(4)
3,307 3,646 3,581 
Adjusted EBITDA(5)
1,263 927 984 
Less: PPA Termination Payments(5)
— — (56)
Adjusted EBITDA (excluding PPA Termination Payments)(5)
1,263 927 928 
Adjusted net debt to adjusted EBITDA (excluding PPA Termination Payments) (times)
2.6 3.9 3.9 
(1) Consists of current and long-term portion of debt, which includes lease liabilities and tax equity financing.
(2) Exchangeable preferred shares are considered equity with dividend payments for credit-rating purposes. For accounting purposes, they are accounted for as debt with interest expense in the Consolidated Financial Statements. For purpose of this ratio, we consider 50% of issued preferred shares, including these, as debt.
(3) Includes principal portion of TransAlta OCP restricted cash and fair value of hedging instruments on debt (included in risk management assets and/or liabilities on the Consolidated Statements of Financial statements).
(4) The tax equity financing for Skookumchuck, an equity accounted joint venture, is not represented in the amounts. Adjusted net debt 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. See the Additional IFRS Measures and Non-IFRS Measures section of this MD&A.
(5) Last 12 months.

The Company's capital is managed internally and evaluated by management using a net debt position. Our current and long-term debt is adjusted for 50 per cent of the exchangeable preferred shares plus 50 per cent of outstanding preferred shares less available cash and cash equivalents, principal portion of TransAlta OCP restricted cash and including fair value assets of hedging instruments on debt, to provide a more readily comparable debt figure from period to period. We use the adjusted net debt to adjusted EBITDA ratio as a measurement of financial leverage and assess our ability to pay off debt. Our target for adjusted net debt to adjusted EBITDA (excluding PPA Termination Payments) is 3.0 to 3.5 times. Our adjusted net debt to adjusted EBITDA ratio for 2021 was better than the low end of our target, and improved compared to 2020, as a result of strong adjusted EBITDA, debt repayments and higher cash and cash equivalents.




TRANSALTA CORPORATION M54

Management’s Discussion and Analysis
Deconsolidated Adjusted EBITDA by Segment
We invest in our assets directly as well as with joint venture partners. Deconsolidated financial information is a supplementary financial measure, and is not intended to be presented in accordance with IFRS.

Adjusted EBITDA is a key metric for TransAlta and TransAlta Renewables and provides management and shareholders a representation of core business profitability. Deconsolidated adjusted 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 adjusted EBITDA to deconsolidated adjusted EBITDA by segment results is set out below:
202120202019
TransAlta ConsolidatedTransAlta RenewablesTransAlta DeconsolidatedTransAlta ConsolidatedTransAlta RenewablesTransAlta DeconsolidatedTransAlta ConsolidatedTransAlta RenewablesTransAlta Deconsolidated
Hydro322 17 105 21 11018 
Wind and Solar262 248 248 256 231238 
Gas494 217 367 205 403 202 
Energy Transition133 — 175 — 227 — 
Energy
  Marketing		137 — 113 — 89— 
Corporate(85)(19)(81)(20)(76)(20)
Adjusted
  EBITDA(1)
1,263 463 800 927 462 465 984 438 546 
Less: TA Cogen
 adjusted EBITDA		(133)(54)(80)
Less: Termination
  of Sundance B
  and C PPAs(1)
— — (56)
Less: EBITDA
  from joint
  venture
  investments(2)
— (3)— 
Add: Dividend
  from TransAlta
  Renewables(1)
151 151 151 
Add: Dividend
  from TA Cogen(1)
34 17 37 
Deconsolidated
 TransAlta
 adjusted EBITDA		852 576 598 
(1) Last 12 months.
(2) Represents our share of amounts for Skookumchuck, an equity accounted joint venture.





TRANSALTA CORPORATION M55

Management’s Discussion and Analysis
Deconsolidated FFO
The Company has set capital allocation targets based on deconsolidated FFO available to shareholders. Deconsolidated financial information is a supplementary financial measure and 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 Additional 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:
202120202019
TransAlta ConsolidatedTransAlta RenewablesTransAlta DeconsolidatedTransAlta ConsolidatedTransAlta RenewablesTransAlta DeconsolidatedTransAlta ConsolidatedTransAlta RenewablesTransAlta Deconsolidated
Cash flow from operating activities1,001 336 702 267 849 331 
Change in non-
  cash operating
  working capital
  balances		(174)(13)(89)31 (121)23 
Cash flow from operations before changes in working capital827 323 613 298 728 308 
Adjustments:
Decrease in finance lease receivable41 — 17 — 24 — 
Clean energy transition provisions and adjustments79 — 37 — — — 
Share of FFO from joint venture(1)
13 — 3 — — — 
Finance income - economic interests— (108)— (69)— (76)
FFO - economic interests(2)
— 191 — 180 — 153 
Other(3)
11 — 15 — 5 — 
FFO971 406 565685 409 276757 385 372
Dividend from
  TransAlta
  Renewables		151 151 151 
Distributions to
  TA Cogen's
  Partner		(56)(17)(37)
Less: Share of
  adjusted FFO
  from joint
  venture(1)
— (3)— 
Less: PPA
  Termination
  Payments		— — (56)
Deconsolidated
  TransAlta FFO		660 407 430 
(1) Represents our share of amounts for Skookumchuck, an equity accounted joint venture.
(2) FFO - economic interests calculated as Free Cash Flow economic interests plus sustaining capital expenditures economic interests plus/minus currency adjustment and in 2021 less distributions from equity accounted joint venture.
(3) Other consists of production tax credits, which is a reduction to tax equity debt and in 2021 less distributions from equity accounted joint venture.





TRANSALTA CORPORATION M56

Management’s Discussion and Analysis
Deconsolidated Net Debt to Deconsolidated Adjusted EBITDA
In addition to reviewing fully consolidated ratios and results, management reviews net debt to adjusted EBITDA on a deconsolidated basis to highlight TransAlta's financial flexibility, balance sheet strength and leverage. Deconsolidated financial information is a supplementary financial measure and is not defined under IFRS, and may not be comparable to those used by other entities or by rating agencies. See also the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further details.
As at Dec. 31202120202019
Adjusted net debt(1)
3,307 3,646 3,581 
Add: TransAlta Renewables cash and cash equivalents244 582 63 
Less: TransAlta Renewables long-term debt(814)(692)(961)
Less: US tax equity financing and South Hedland debt(2)
(867)(906)(145)
Deconsolidated net debt1,870 2,630 2,538 
Deconsolidated adjusted EBITDA(3)
852 576 598 
Deconsolidated net debt to deconsolidated adjusted EBITDA(4) (times)
2.2 4.6 4.2 
(1) Refer to the Adjusted Net Debt to Adjusted EBITDA (Excluding PPA Termination Payments) calculation under the Key Non-IFRS Financial Ratios section of this MD&A for the reconciliation and composition of adjusted net debt.
(2) Relates to assets where TransAlta Renewables has economic interests.
(3) Refer to the Deconsolidated Adjusted EBITDA by Segment section of this MD&A for the reconciliation and composition of deconsolidated adjusted EBITDA.
(4) The non-IFRS ratio is not a standardized financial measure under IFRS and might not be comparable to similar financial measures disclosed by other issuers.

Our target for deconsolidated net debt to deconsolidated adjusted EBITDA is 2.5 to 3.0 times. Our deconsolidated net debt to deconsolidated adjusted EBITDA ratio decreased compared with 2020, due to lower deconsolidated net debt which was partially offset by higher deconsolidated adjusted EBITDA. Lower deconsolidated net debt is a result of scheduled repayments on corporate debt and an increase in cash balances.

2022 Financial Outlook
The following table outlines our expectation on key financial targets and related assumptions for 2022 and should be read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of this MD&A:
Measure2022 Target2021 Actuals
Adjusted EBITDA(1)
$1,065 million - $1,185 million$1,263 million
FCF(1)
$455 million - $555 million$562 million
Dividend$0.20 per share annualized$0.20 per share annualized
(1) These items are not defined and have no standardized meaning under IFRS. Please refer to the Reconciliation of Non-IFRS Measures 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.

Range of key power price assumptions
Market2022 Assumption
Alberta Spot ($/MWh)$80 - $90
Mid-C Spot (US$/MWh)US$45 - US$55
AECO Gas Price ($/GJ)$3.60
Other assumptions relevant to the 2022 financial outlook
Sustaining capital$150 million - $170 million
Energy Marketing gross margin$95 million - $115 million

Alberta Hedging
Range of hedging assumptions2022
Hedged production (GWh)6,278
Hedge Price ($/MWh)$75
Hedged gas volumes (GJ)50 million
Hedge gas prices ($/GJ)$2.75





TRANSALTA CORPORATION M57

Management’s Discussion and Analysis
Adjusted EBITDA is estimated to be between $1.065 billion to $1.185 billion. FCF is expected to be between $455 million and $555 million and excludes the impact of rehabilitation capital expenditures required at Kent Hills 1 and 2 wind facilities. The midpoint of the range represents a 5 per cent decrease from the midpoint of the 2021 outlook largely driven by lower expectations on Alberta power pricing, a return to normal performance from Energy Marketing, and a step-up in mine reclamation expenditures, partially offset by the contribution from new assets, settlements of non-recurring provisions in 2021 and lower expected sustaining capital.

The Company expects its outlook for 2022 to be impacted by a number of factors detailed further below.

Market Pricing
For 2022, we see continuing strong merchant pricing levels in Alberta and the Pacific Northwest though at lowered target ranges for both regions. Lower year-over-year pricing in Alberta is expected to be driven by fewer planned outages and the expected additions of new wind and solar supply, including TransAlta’s new Windrise wind facility and Garden Plain wind facility, expected to achieve commercial operation in late 2022. Weather and demand are also major factors in actual settled prices. Lower year-over-year pricing in the Pacific Northwest will be impacted by natural gas prices and hydro generation resulting from actual weather and hydrology of the year. Ontario power prices for 2022 are expected to be higher than 2021 due to higher natural gas prices and additional nuclear refurbishment outages.

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.

Kent Hills Wind Facilities Outage
It is expected that the outage at Kent Hills 1 and 2 wind facilities will continue and rehabilitation efforts for all of the foundations is expected to commence during the second quarter of 2022 with the aim of fully returning the wind facilities to service by the end of 2023. The outage is expected to result in foregone revenue of approximately $3.4 million per month on an annualized basis so long as all 50 turbines at Kent Hills 1 and 2 wind facilities are offline, based on average historical wind production, with revenue expected to be earned as the wind turbines are returned to service.

Addition of Windrise and North Carolina Solar
On Nov. 5, 2021, TransAlta Renewables completed the acquisition of the economic interest in the fully contracted 122 MW North Carolina Solar portfolio, which is expected to generate an average annual EBITDA6 of approximately US$9 million.

On Dec. 2, 2021, TransAlta Renewables announced commercial operation of the Windrise wind facility in Alberta was achieved on Nov. 10, 2021. Windrise is expected to generate an average annual EBITDA6 of approximately $20 million to $22 million.

Fuel and Compliance Costs
For the Gas fleet, coal consumption in Alberta is expected to be zero in 2022 given TransAlta has now retired or fully converted all its coal-fired facilities to gas. Increased gas consumption in the Gas fleet 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. This will be partially offset by an increased carbon tax in Alberta.

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 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 2022 is expected to be marginally higher than 2021 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.

6 Average annual EBITDA is not defined and has no standardized meaning under IFRS, and is forward-looking. Please refer to the Additional IFRS Measures and Non-IFRS Measures section of this MD&A for further discussion.




TRANSALTA CORPORATION M58

Management’s Discussion and Analysis
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.
 
Energy Marketing
Adjusted EBITDA from our Energy Marketing segment is affected by prices and volatility in the market, overall strategies adopted and changes in regulation and legislation. Our outlook has been adjusted to reflect the exceptional performance achieved in 2021. We continuously monitor both the market and our exposure to maximize earnings while still maintaining an acceptable risk profile. Our 2022 objective for Energy Marketing is for the segment to contribute between $95 million to $115 million in gross margin for the year, which is consistent with normalized performance expectations.
 
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.
 
Decommissioning and Restoration Costs
Decommissioning and restoration costs are expected to be higher in 2022 due to the closure of the Highvale coal mine and increased reclamation activity at Centralia due to deferral of certain activities impacted by COVID-19.

Sustaining Capital Expenditures
The Company expects sustaining capital to be in the range of $150 million to $170 million. The midpoint for the range represents a 25 per cent decrease from the midpoint of the 2021 outlook. This is driven by fewer planned maintenance outages at the thermal fleet in Alberta due to the completion of gas conversions that occurred in 2021, partially offset by increased sustaining capital expenditures at the Sarnia cogeneration facility for planned major maintenance, as well as increased dam safety and major maintenance across our Hydro fleet. The Kent Hills foundation rehabilitation capital expenditure has been segregated from our sustaining capital range due to the extraordinary and rare nature of this expenditure. The initial estimated range for the rehabilitation at Kent Hills is between $75 million to $100 million with approximately $40 million to $60 million estimated to be incurred in 2022.

Our estimate for total sustaining capital is as follows:
Spent in 2020Spent in 2021Expected spend in 2022
Total sustaining capital157 199 150 -170

Liquidity and Capital Resources
We expect to maintain adequate available liquidity under our committed credit facilities. We currently have access to $2.2 billion in liquidity, including $947 million in cash. We expect to be well positioned to refinance the upcoming debt maturity in 2022. The funds required for committed growth, sustaining capital and productivity projects are not expected to be significantly impacted by the current economic environment. Please refer to the Description of Business and Financial Capital sections of this MD&A for further details.
 
Net Interest Expense
Interest expense for 2022 is expected to be higher than in 2021 largely due to higher levels of debt. The increase in debt is mainly due to the $173 million Windrise project financing that was completed in November 2021. 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.

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.
 




TRANSALTA CORPORATION M59

Management’s Discussion and Analysis
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 material accounting policies are described in Note 2 of the consolidated financial statements. 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
Identification of Performance Obligations
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
In determining the transaction price and estimates of variable consideration, management considers the past history of customer usage and capacity requirements when estimating the goods and services to be provided to the customer. The Company 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 Company expects to be entitled to in exchange for transferring the good or service.

The Company’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 Company 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.

Revenue from Other Sources
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 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.





TRANSALTA CORPORATION M60

Management’s Discussion and Analysis
Merchant Revenue
Revenues from non-contracted capacity (i.e., merchant) are comprised of energy payments, at market price, for each MWh produced and are recognized upon delivery.

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.

Level Determinations and Classifications
 
The Level I, II and III classifications in the fair value hierarchy utilized by the Company 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. Refer to Note 15(B)(I) from our audited annual consolidated financial statements for further details on the inputs used for each level.

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, 2021, is an estimated total upside of $105 million (2020 — $68 million upside) and total downside of $220 million (2020 — $94 million) impact to the carrying value of the financial instruments. Fair values are stressed for volumes and prices. The amount of $22 million upside (2020 — $35 million upside) and $145 million downside (2020 — $59 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$28 to US$51/MWh (Dec. 31, 2020 — US$24-US$32/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 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 Agreement 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 $32 million (2020 — $33 million downside) potential impact to the carrying value of nil as at Dec. 31, 2021 (2020 — nil). The sensitivity analysis has been prepared using the Company’s assessment that a change in the implied discount rate of the future cash flow of one per cent is a reasonably possible change.

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.

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.





TRANSALTA CORPORATION M61

Management’s Discussion and Analysis
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 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 2021.

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. Please refer to the Financial Position 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 2021, 2020 and 2019 annual goodwill impairment reviews, the Company determined the recoverable amounts of the CGUs by calculating the fair value less costs of disposal using discounted cash flow projections based on the Company’s long-range forecasts for the period extending to the last planned asset retirement in 2072. The resulting fair value measurement is categorized within Level III of the fair value hierarchy.
 
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.

Project Development Costs
Project development costs include external, direct and incremental costs that are necessary for completing an acquisition or construction project. 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.





TRANSALTA CORPORATION M62

Management’s Discussion and Analysis
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
 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. 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.
 
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.

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.
 
We estimate the undiscounted amount of cash flow required to settle the decommissioning and restoration provisions is approximately $1.6 billion, which will be incurred between 2022 and 2072. The majority of these costs will be incurred between 2025 and 2050.
 




TRANSALTA CORPORATION M63

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.

Classification of Joint Arrangements
Upon entering into a joint arrangement, the Company 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 Company 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.

Significant Influence
Upon entering into an investment, the Company must classify it as either an investment as an associate or an investment under IFRS 9. In making this classification, the Company exercises judgment in evaluating whether the Company 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 Company 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 Company and investee, interchange of managerial personnel or providing essential technical information are considered when assessing if the Company has significant influence over an investee.

Accounting Changes
Current Accounting Changes
Amendments to IAS 1 Presentation of Financial Statements: Material Accounting Policies
Effective for the 2021 annual financial statements, the Company early adopted amendments to IAS 1 Presentation of Financial Statements in advance of its mandatory effective date of Jan. 1, 2023, which requires entities to disclose their material accounting policy information rather than their significant accounting policies. The Company has updated the accounting policies disclosed in Note 2 based on its assessment of the amended standard.

Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use
Effective Jan. 1, 2021, the Company early adopted amendments to IAS 16 Property, plant and equipment (“IAS 16 Amendments”) in advance of its mandatory effective date of Jan. 1, 2022. The Company adopted the IAS 16 Amendments retroactively. No cumulative effect of initially applying the guidance arose. The IAS 16 Amendments prohibit deducting from the cost of an item of property, plant and equipment any proceeds from selling items produced while bringing that asset to the location and condition necessary for it to be capable of operating in a manner intended by management. Instead, an entity recognizes the proceeds from selling such items, and the cost of producing those items, in profit or loss. No adjustments resulted from early adopting the amendments.

IFRS 7 Financial Instruments: Disclosures — Interest Rate Benchmark Reform
The transition of the London Interbank Offered Rates ("LIBOR") has begun with the cessation of the publication of one-week and two-month USD LIBOR occurring on Dec. 31, 2021. The remaining overnight, one-, three-, six-, and 12-month USD LIBOR will continue to be published until their cessation date on June 30, 2023. Existing financial instruments may continue to use USD LIBOR while they are published until they mature, however, new financial instruments will not be using USD LIBOR if entered into after Dec. 31, 2021. 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 were effective Jan. 1, 2021, and were adopted by the Company on Jan. 1, 2021. There was no financial impact upon adoption.

The Company's credit facilities references USD LIBOR for US-dollar drawings and the Canadian Dollar Offered Rate for Canadian drawings, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. For the year ended Dec. 31, 2021, there were no drawings under the credit facilities. The Company has interest rate swap agreements in place with a notional amount of US$150 million referencing three-month LIBOR, expected to settle in the third quarter of 2022.




TRANSALTA CORPORATION M64

Management’s Discussion and Analysis
Future Accounting Changes
Amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets
On May 14, 2020, the IASB issued Onerous Contracts — Cost of Fulfilling a Contract and amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets to specify which costs to include when assessing whether a contract will be loss-making. The amendments are effective for annual periods beginning on or after Jan. 1, 2022, and will be adopted by the Company in 2022. The amendments are effective for contracts for which an entity has not yet fulfilled all its obligations on or after the effective date. No financial impact is expected upon adoption.

Amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction
On May 7, 2021, the IASB issued amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction. The amendments clarify that the initial recognition exemption under IAS 12 does not apply to transactions such as leases and decommissioning obligations. These transactions give rise to equal and offsetting temporary differences in which deferred tax should be recognized.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, with early application permitted. The Company's current position aligns with the amendment and no financial impact is therefore expected upon adoption on the effective date.

Amendments  to  IAS  1  Classification  of  Liabilities  as  Current  or  Non‐Current 
In January 2020, the IASB issued amendments to IAS 1 Presentation of Financial Statements, to provide a more general approach to the presentation of liabilities as current or non‐current based on contractual arrangements in place at the reporting date. These amendments specify that the rights and conditions existing at the end of the reporting period are relevant in determining whether the Company has a right to defer settlement of a liability by at least 12 months, provide that management's expectations are not a relevant consideration as to whether the Company will exercise its rights to defer settlement of a liability and clarify when a liability is considered settled.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, and are to be applied  retrospectively. The Company has not yet determined the impact of these amendments on its consolidated financial statements. 

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 M65

Management’s Discussion and Analysis
Environmental, 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.

Our key strategic sustainability pillars build on our corporate strategy and weave through our business. 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 ED&I), 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

We have been reporting on sustainability since 1994. This year, we have structured the ESG section of this MD&A to help stakeholders better understand the most material issues affecting our ESG performance.

Reporting on Our Material Sustainability Factors
TransAlta’s ESG content is integrated within this MD&A to provide information on how ESG affects our business (including material focus areas) and is guided by leading ESG reporting frameworks. 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.

Climate-related data to be disclosed is informed by climate change questionnaires from CDP (the global disclosure system for environmental impacts known formerly as Carbon Disclosure Project) and the Task Force on Climate-related Financial Disclosures ("TCFD") recommendations. In 2021, we conducted a climate-related scenario analysis that enhanced our alignment with both international sustainability frameworks. GHG emissions data for scopes 1 and 2 follow the accounting and reporting standards of the GHG Protocol. For further information on climate change management and the findings of our scenario analysis, please refer to the Decarbonizing Our Energy Mix section of this MD&A.

We adopt guidance from the Global Reporting Initiative and Sustainability Accounting Standards Board ("SASB") requirements for 'Electric Utilities and Power Generators'. We continue to monitor the development of sustainability disclosure standards to assess our future reporting, such as the International Sustainability Standards Board and the Taskforce on Nature-related Financial Disclosures.

The disclosure of our most relevant sustainability factors is guided by our sustainability materiality assessment. Our materiality assessment is developed through evaluation of key sector-specific research on material issues and supported by internal and external engagement on key sustainability issues. Our Enterprise Risk Management ("ERM") program is designed to help the organization focus its efforts on key enterprise risks, within the planning horizon, that could significantly impact the success of its strategy, including its sustainability objectives. We consider a sustainability factor as material if it could substantively affect our ability to create value. Our major environmental risk factors include climate change, weather, environmental disasters, exposure to the elements, environmental compliance risk and current and emerging environmental regulation. Our major social risk factors include Indigenous and stakeholder relationships, local communities, public health and safety, employee and contractor health and safety, employee retention, supply chain and cybersecurity. For further guidance on our risk factors, please refer to the Governance and Risk Management section of this MD&A.













TRANSALTA CORPORATION M66

Management’s Discussion and Analysis
Transforming Our Business Model to Become Carbon Neutral by 2050
At TransAlta, our mission is to provide safe, low-cost and reliable clean electricity to our customers. As a customer-centred clean energy leader, we are well positioned to support our customers' ESG and sustainability goals. To achieve this goal, in today's evolving economy and increasingly electrified world, our strategy focuses on renewable electricity growth and a deep commitment to sustainability. We believe we are uniquely positioned as the world continues to electrify and adopt sustainability practices. For further information, please refer to the Description of the Business section of this MD&A.

Our President and Chief Executive Officer, John Kousinioris, speaks about our decarbonization journey in the sections below.

How is TransAlta’s strategy contributing to energy transition?
“In our sector, there is a lot of agreement about what is required to achieve a low-carbon energy transition. First, we need to transition away from high-emitting coal generation. As of the end of 2021, TransAlta has completed this transition in Canada and we will retire our single remaining coal unit in the US at the end of 2025. Second, we need to significantly expand the supply of zero-emission renewable electricity. TransAlta already has a leading portfolio of renewable assets and our growth plan will see us expand our wind and solar business by 2 GW over the next five years. Finally, we need to achieve breakthroughs that allow us to harness intermittent renewables to provide reliable electricity for consumers. TransAlta’s WindCharger facility was the first utility-scale battery project linked to a renewables facility in Alberta and our growth plan includes further investments in energy storage. The key elements of TransAlta’s strategy are aligned with the energy transition underway in the global economy.”

How does the company’s strategy align with global climate efforts?
"We are very proud of our emissions track record to date. Our Company has achieved a 29 million tonne annual GHG emission reduction from 2005 levels. This reduction already exceeds the national 2030 emissions targets in Canada, the US and Australia where we operate. In that sense, we are already ahead of the ambitious national efforts in our home markets. That said, we recognize that decarbonizing the electricity sector is a key pillar of global climate efforts because electrification enables emission reductions in other sectors, such as transportation. This means we have to continually raise our level of ambition as we did last year by setting our carbon neutrality target for 2050 and we did this year by enhancing and accelerating our near-term reduction target.

"We are the first publicly traded Canadian energy company to commit to setting a science-based emissions target. This step is critical in ensuring that our actions are aligned with the steps required to achieve global climate goals. Further, we were pleased to join the Powering Past Coal Alliance during the 26th UN Climate Change Conference of the Parties ("COP26") in Glasgow. The Alliance is a group of governments and companies committed to achieving one of the key steps in the global energy transition."

TransAlta accelerated and strengthened its GHG emissions reduction target. Why did the Company choose to take that step?
"Our new target is a function of our new growth strategy. Simply put, by focusing on growing our contracted renewables assets we are growing our business and not our emissions. This type of growth, coupled with coal-to-gas conversions that cut emissions from our thermal assets, and efficient on-site cogeneration, creates an emissions pathway for our Company that delivers substantial reductions over the next five years. We believe it is important for the Company to publicly hold itself accountable for delivering these results and ensuring our investors, customers and stakeholders are aware of where we are going in this important effort."

How can TransAlta help customers to decarbonize?
"Most importantly, TransAlta helps our customers by reliably delivering and operating renewable and storage projects and on-site generation that meet their energy needs. Underneath that core commitment is a set of technologies and contracting options that we tailor to ensure customers receive the energy they require, and environmental outcomes aligned with their ESG commitments. In 2021, we were proud to announce a major wind project in Oklahoma which will provide electricity to a leading US-based company, a major wind project in Alberta to provide electricity to Pembina Pipelines as well as a smaller-scale solar and battery project with BHP in Australia. All are examples of a tailored approach designed to meet the unique needs of customers as they advance their own decarbonization goals. In the future, we see more demand for reliable zero-emission electricity and our growth strategy is designed to position the Company to deliver these projects effectively for new and existing partners in all of our markets."





TRANSALTA CORPORATION M67

Management’s Discussion and Analysis
2022+ Sustainability Targets 
Our 2022 and longer-term sustainability targets support the long-term success of our business so that the Company will continue to be positioned as an ESG leader in the future. Goals and targets are established to improve our ESG performance and to manage current and emerging material sustainability issues, in support of the United Nations Sustainable Development Goals ("UN SDGs") and the Future-Fit Business Benchmark. TransAlta is committed to decarbonizing our energy generation and to accelerating clean energy growth. We believe we can make a greater positive impact on UN SDG 7 “Affordable and Clean Energy” and SDG 13 “Climate Action”, while supporting several other SDGs.

In December 2021, TransAlta approved a more stringent climate-related target to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year. We estimate that this is in line with limiting global warming to 1.5°C and, in December 2021, committed to setting a science-based emissions reduction target through the Science Based Targets initiative. In 2021, the Company established a Sustainability-Linked Loan that will align the cost of borrowing to TransAlta's GHG emission reductions and gender diversity targets. For further details on the Sustainability-Linked Loan, please refer to the Significant and Subsequent Events section of this MD&A. In 2021, the Company's indirect wholly owned subsidiary, Windrise Wind LP, secured green bond financing. This supports our goal to deliver on our customers’ needs for clean electricity. Please refer to the TransAlta Renewables Acquisitions section of this MD&A for further details.

Targets are outlined below:
ESG Alignment: Environment
TransAlta Sustainability GoalTransAlta Sustainability TargetAlignment with UN SDG Target or Future-Fit Business Benchmark
Reclaim land utilized for miningBy 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 AlbertaFuture-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 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 wasteBy 2022, reduce total waste generation by 80 per cent over a 2019 baselineUN 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 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 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from a 2015 base year
UN SDG Target 13.2: "Integrate climate change measures into national policies, strategies and planning."

By 2050, achieve carbon neutrality




TRANSALTA CORPORATION M68

Management’s Discussion and Analysis
ESG Alignment: Social
TransAlta Sustainability GoalTransAlta Sustainability TargetAlignment with UN SDG Target or Future-Fit Target
Reduce safety incidentsAchieve a Total Recordable Injury Frequency rate below 0.61UN 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."
Support prosperous Indigenous communitiesSupport equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunitiesUN 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 2023UN 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 GoalTransAlta Sustainability TargetAlignment with UN SDG Target or Future-Fit Target
Strengthen gender equalityAchieve 50 per cent female representation on the Board by 2030UN 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 Company by 2030
Maintain equal pay for women in equivalent roles as men
Demonstrate leadership on ESG reporting within financial disclosuresMaintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworksUN 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 GoalTransAlta Sustainability TargetAlignment with UN SDG Target or Future-Fit Target
Coal transitionNo further coal generation by the end of 2025 with 100 per cent of our owned net generation capacity to be from renewables and gasUN SDG Target 7.1: "By 2030, ensure universal access to affordable, reliable and modern energy services."
Clean energy solutions for customersDevelop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductionsUN SDG Target 7.2: "By 2030, increase substantially the share of renewable energy in the global energy mix."








TRANSALTA CORPORATION M69

Management’s Discussion and Analysis
Our 2021 Sustainability Performance
In 2021, we achieved an environmental performance milestone in our journey to grow our clean electricity fleet with the completion of our coal-to-gas conversions in Canada. Overall, the converted units generate nearly 50 per cent fewer CO2 emissions fuelled by natural gas compared to coal. The completed unit conversions and the end of production at the Highvale coal mine in Alberta also contributed to the goals of the Powering Past Coal Alliance, which TransAlta joined at COP26. Our social performance was highlighted by our positive contribution to support equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunities.

Performance against our 2021 sustainability targets is outlined below:
ESG Alignment: Environment
TransAlta Sustainability GoalTransAlta Sustainability TargetResultsComments
Reclaim land utilized for miningBy 2040, complete full reclamation of our Centralia coal mine in Washington State On trackReclamation work at our Centralia and Highvale mines has been executed progressively.
By 2046, complete full reclamation of our Highvale coal mine in AlbertaOn trackOur Highvale coal mine in Alberta retired on Dec. 31 2021, and reclamation has been executed progressively.
Responsible water management
By 2026, reduce fleet-wide water consumption (withdrawals minus discharge) by 20 million m3 or 40 per cent over a 2015 baseline
On track
In 2021, we reduced fleet-wide water consumption by 4 million m3 or 11 per cent over 2020 levels.
Reduce operational wasteBy 2022, reduce total waste generation by 80 per cent over a 2019 baselineOn track
In 2021, we reduced total waste generation by 620,000 tonnes equivalent or 55 per cent over 2020 levels.
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
On track
Since 2005, we have reduced SO2 emissions by 90 per cent and NOx emissions by 77 per cent. In 2021, we reduced SO2 emissions by 42 per cent and NOx emissions by 29 per cent over 2020 levels.
Reduce GHG emissionsBy 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 warmingAchieved
Since 2015, we have reduced GHG emissions by 61 per cent. In 2021, we reduced approximately 3.9 million tonnes of CO2e or 24 per cent over 2020 levels.
By 2050, achieve carbon neutralityOn track
Since 2015, we have reduced GHG emissions by 61 per cent. In 2021, we reduced approximately 3.9 million tonnes of CO2e or 24 per cent over 2020 levels.
ESG Alignment: Social
TransAlta Sustainability GoalTransAlta Sustainability TargetResultsComments
Reduce safety incidentsAchieve a Total Recordable Injury Frequency rate below 0.61Not achieved
TRIF performance year over year has remained relatively unchanged. In 2021, we achieved a TRIF of 0.82 compared to 0.81 in 2020. Our focus on safety culture transformation remains as we continue to work to meet and exceed our goal of 0.61 in the future.
Support prosperous Indigenous communitiesSupport equal access to all levels of education for youth and Indigenous peoples through financial support and employment opportunitiesAchieved
Support in 2021 represented a total value of $375,000 and provided 14 bursaries through a partnership with Indspire; funded academic upgrading programs through the Southern Alberta Institute of Technology; and maintained communication on employment opportunities through various mediums to support different access options for Indigenous communities.
Provide Indigenous cultural awareness training to all TransAlta employees by the end of 2023.On track
In 2021, we committed to and began development of Indigenous Awareness training that will be provided to all Canadian, Australian and US employees by the end of 2023.




TRANSALTA CORPORATION M70

Management’s Discussion and Analysis
ESG Alignment: Governance
TransAlta Sustainability GoalTransAlta Sustainability TargetResultsComments
Strengthen gender equalityAchieve 50 per cent female representation on the Board by 2030On track
As of Dec. 31, 2021, women made up 42 per cent of our total Board composition compared to 45 per cent in 2020, due to the retirement of one female Board member. In 2021, we achieved 50 per cent female representation on the Board, excluding the two nominees from Brookfield.
Achieve at least 40 per cent female employment among all employees of the Company by 2030On track
As of Dec. 31, 2021, women made up 24 per cent of all employees, an increase over 2020 levels (21 per cent).
Maintain equal pay for women in equivalent roles as menAchievedEqual pay for women in the Company was maintained in 2021.
Demonstrate leadership on ESG reporting within financial disclosuresMaintain our position as a leader on integrated ESG disclosure through increased annual alignment with leading sustainability disclosure frameworksAchieved
In 2021, we conducted a climate-related scenario analysis that enhanced our alignment with TCFD and CDP (the global disclosure system for environmental impacts known formerly as Carbon Disclosure Project).
ESG Alignment: Environment and Social
TransAlta Sustainability GoalTransAlta Sustainability TargetResultsComments
Leading clean power company by 2025No further coal generation by the end of 2025 with 100 per cent of our owned net generation capacity to be from clean electricity (renewables and gas)On track
In 2021, Sundance Unit 5 was retired, and Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 were converted to natural gas. The Highvale coal mine was closed. Centralia Unit 1 retired on Dec. 31, 2020, and the remaining unit is set to retire on Dec. 31, 2025.
Discontinue coal power generation in Canada by the end of 2021AchievedIn 2021, our Sundance 5 facility was retired, and Keephills Unit 2, Keephills Unit 3 and Sundance 6 facilities were converted to natural gas. The Highvale coal mine was closed.
Clean energy solutions for customersDevelop new renewable projects that support customer sustainability goals to achieve both long-term power price affordability and carbon reductionsAchieved
In 2021, the Company purchased a 122 MW portfolio of operating solar facilities in North Carolina and started the construction of a 48 MW solar and battery storage system in Western Australia. We also entered into long-term PPAs for the off take of 100 MW from our Garden Plain wind project in Alberta and 100 per cent of our 300 MW White Rock East and White Rock West wind projects in Oklahoma.





TRANSALTA CORPORATION M71

Management’s Discussion and Analysis
Decarbonizing Our Energy Mix
ESG is more than simply a business strategy at TransAlta; it is a competitive advantage. Sustainability is one of our core values; therefore, we strive to integrate climate change into governance, decision-making, risk management and our day-to-day business operations. The outcome of our climate change focus is continuous improvement on key climate-related issues and ensuring our economic value creation is balanced with a value proposition for the environment and people.

We recognize the impact of climate change on society and our business both today and into the future. Our renewable energy commitment began more than one hundred years ago when we built the first hydro assets in Alberta, which still operate today. In 2002, we acquired our first wind farm, in 2015, our first solar farm, and in 2020, our first battery storage facility. Today, we operate over 50 renewable facilities across Canada, the US and Australia.

Our climate-change-related reporting is guided by the TCFD. This framework helps inform discussion and provide context on how climate change affects our business.

The following are examples of how we have transitioned our business to manage climate change risk and opportunity, how we have demonstrated leadership through action on climate change-related issues and how we are positioned for climate resiliency.
▪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 nameplate renewable energy capacity from approximately 900 MW in 2000 to over 2,800 MW in 2021.
▪Our business demonstrates climate change resiliency by reducing GHG emissions – we have a target to reduce annual CO2e emission by 75 per cent over 2015 levels by 2026. Since 2015, we have reduced our annual emissions by 19.7 million tonnes of CO2e or 61 per cent, putting us on track to achieve our 2026 target.
▪As a leader in North American renewable electricity, we are well-positioned to build renewable energy facilities and hybrid facilities to support customer decarbonization goals. Our strategy involves retiring our single coal unit by the end of 2025 and achieving a 100 per cent mix of renewables and natural gas with 70 per cent of EBITDA from renewables.

Climate Change Governance
Climate-related risks and opportunities can significantly impact our business, especially regulatory changes and shifting customer preferences toward lower-carbon energy. Therefore, we actively manage risks and opportunities so that we can continue to grow and achieve our goals. Climate-related issues are identified at every level of management, including the Board, executive team, business units and corporate functions (for example, government relations, regulatory, emissions trading, sustainability, commercial, customer relations, investor relations). Ensuring climate-related issues are acknowledged and addressed at the most senior levels of the Company (including at the Board and executive level) has allowed us to establish actionable emission reduction targets and grow our generation capacity through renewable energy and storage.

Oversight by the Board of Directors
The highest level of climate change oversight is at the Board level, with specific oversight of certain aspects of the Company's response to climate change being delegated to our Governance, Safety and Sustainability Committee (“GSSC”), our Audit, Finance and Risk Committee ("AFRC"), and our Investment Performance Committee (“IPC”).

Meeting quarterly, the GSSC assists the Board in monitoring and assessing compliance with climate change regulation and reporting. The GSSC receives management reports on changes in climate-related legislation and the potential impact of policy developments on TransAlta's operations. The GSSC then supports the Board in developing Company-wide climate change strategies, policies and practices. The GSSC also reviews environmental protection guidelines, including GHG mitigation, and considers whether our environmental procedures are being effectively implemented.

The AFRC and IPC also play a role in managing TransAlta's climate-related risks and opportunities. The AFRC assists the Board in overseeing the integrity of our consolidated financial statements and ensures climate risks and opportunities are factored into financial decision-making. Further, the AFRC is responsible for approving our Commodity and Financial Exposure Management policies and reviewing quarterly ERM reporting. The IPC considers and assesses risks related to capital projects, including overseeing climate risk assessments and mitigation plans. As a result, climate-related capital expenditures, acquisitions and budgets are reviewed by the AFRC and IPC on a case-by-case basis.

Our Board is composed of individuals with a mix of skills, knowledge and experience critical to our strategy success and business growth. Notably, five of our Board members have identified environment/climate change among their top four relevant competencies.





TRANSALTA CORPORATION M72

Management’s Discussion and Analysis
Role of Senior Management
TransAlta’s President and CEO maintains the highest level of oversight on climate-related issues at the executive level. Our business units and corporate functions work closely together to support the executive team in understanding climate-related risks and opportunities. Our executive team reviews risks and opportunities quarterly and reports to the GSSC and AFRC.

At the business unit level, climate change risks are identified through our Total Safety Management System, asset management function and systems, energy and trading business, communication with stakeholders, active monitoring and participation in working groups.

Notably, we tie a component of executive compensation to reducing GHG emissions and climate change management. We link our corporate executive annual incentive plans (short-term incentive or yearly bonus and long-term share incentives) to performance on our strategic goals. Our strategic goals include growing renewable energy, reducing GHG emissions, and supporting our customers' sustainability goals to decarbonize through on-site low carbon energy generation.

For further information on incentives for ESG performance, please refer to the ESG-Linked Compensation in Building a Diverse and Inclusive Workforce section of this MD&A.

Strategy and Risk Management
Climate Change Strategy
As described in the following sections, our risks and opportunities assessment and climate scenarios analysis support the development and continuous improvement of our climate change strategy. We actively monitor and manage climate-related risks and opportunities as part of our overall business strategy to ensure we remain resilient across all scenarios.
TransAlta remains committed to creating a path to resiliency in a decarbonizing world so that we support the goals proposed under the Paris Agreement and those solidified during successive meetings, such as COP26. Our strategy is focused on the operation of our existing assets (wind, hydro, solar, gas, storage and coal), the phase-out of coal-fired electricity generation and the development of renewable energy and storage projects. Our customers are increasingly integrating ESG risk into their business decisions; therefore, we see an advantage in growing our clean power business to support our customers' sustainability goals. Our investments and growth in renewable energy are highlighted by our portfolio of renewable energy-generating assets. From 2000 to 2021, we grew our nameplate renewables capacity from approximately 900 MW to over 2,800 MW. Today, our diversified renewable fleet makes us one of the largest renewable power producers in North America, one of the largest producers of wind power in Canada and the largest producer of hydro power in Alberta.

Another way we contribute to our customers’ sustainability goals is through environmental attributes. The environmental attributes we generate include carbon offsets, renewable energy credits and emission offsets. Our customers can use environmental attributes to lower compliance costs attributed to carbon policies or renewable portfolio standards. Further, environmental attributes can help achieve voluntary corporate sustainability or carbon reduction goals.

To combat the challenges of renewable energy intermittency, we continue to invest in battery storage. In 2020, we launched WindCharger, a "first of its kind" battery storage project in Alberta that stores energy produced by our Summerview II wind facility and discharges electricity onto the Alberta grid during system supply shortages. Further, in 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP through the construction of the Northern Goldfields Solar Project in Western Australia. This project will support BHP in meeting its emissions reduction targets and delivering lower carbon, sustainable nickel to its customers. With a target operation date in early 2023, the Northern Goldfields Solar Project is expected to reduce BHP's scope 2 electricity GHG emissions by 540,000 tonnes of CO2e over the first 10 years of operation.





TRANSALTA CORPORATION M73

Management’s Discussion and Analysis
In support of our own path to climate resiliency, we have taken significant steps to reduce our carbon footprint over the last several years. In 2021, we adopted a more stringent climate-related target to reduce 75 per cent of our scope 1 and 2 GHG emissions by 2026 from a 2015 base year. TransAlta estimates that this is in line with limiting global warming to 1.5°C and, in 2021, committed to setting a science-based emissions reduction target through the Science Based Targets initiative. In addition, we have a target to be carbon neutral by 2050, while growing renewable energy and optimizing natural gas. We are also taking strategic steps to decarbonize the power sector and support the energy transition. In 2021, we completed our conversion of existing Canadian coal assets to natural gas, achieving our goal of transitioning off coal in Canada. In 2021, we also announced our Clean Electricity Growth Plan which will see the Company execute on 2 GW of renewables growth by 2025. In 2025 we will also retire our single remaining coal unit, located in the United States, to complete TransAlta's transition away from coal generation.

To date, we have retired 4,064 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas. Overall, our converted natural gas units generate nearly 50 per cent fewer CO2 emissions compared to coal. Repurposing the facilities rather than decommissioning them reduces the cost and emissions associated with new construction and aligns with the UN SDGs, specifically "Goal 9: Industry, Innovation and Infrastructure." The completed conversions and the closure of the Highvale coal mine also contributes to the goals of the Powering Past Coal Alliance, which TransAlta joined in November 2021 at COP26.

We actively engage policymakers and stakeholders on how to facilitate a transition where the electricity systems we serve can reach net-zero emissions while maintaining reliability. We will continue investing in renewables and assessing the best options to deliver energy storage, including incorporating learnings from our industrial-scale battery into our Company strategy and sharing those learnings with government. At the same time, natural gas will play an essential role in the electricity sector, providing baseload generation to support current system demands and a smooth energy transition. We always seek energy-efficiency improvements and opportunities to achieve emissions reductions at competitive costs. Further, we are committed to investing in climate change mitigation solutions to maximize value for our shareholders, customers, local communities and the environment.





TRANSALTA CORPORATION M74

Management’s Discussion and Analysis
Climate Scenarios
In 2021, we conducted climate scenario analysis to understand risks and opportunities and assess our strategy's resiliency under several future climate scenarios. The analysis utilized scenarios from the International Energy Agency’s ("IEA") 2020 World Energy Outlook, a large-scale simulation model designed to replicate how energy markets function. We used three scenarios, Stated Policies (“STEPS”), Sustainable Development (“SDS”) and Net Zero Emissions by 2050 (“NZE”).

scenariosa.jpg

In STEPS, the energy system has no major additional climate and environmental policies enacted by government(s). STEPS assumes that carbon pricing continues in Canada while no carbon price is set in the US or Australia. STEPS also assumes that the power sector reduces emissions by 45 per cent by 2040 while natural gas generation capacity increases. Finally, STEPS is limited to the deployment of commercial-ready technologies, including wind and solar.

In SDS, the goals of the Paris Agreement (2015) are achieved, resulting in net-zero emissions by 2070. The SDS assumes a rapid increase in clean energy policies and investments that position the energy system to also achieve key UN SDGs. In SDS, all current net-zero pledges are achieved, and there are extensive efforts to reduce emissions. SDS assumes that carbon pricing continues in Canada and is set in the US and Australia. It also assumes that the power sector reduces emissions by 90 per cent by 2040 while natural gas capacity remains stable into 2030 and declines toward 2040. Finally, SDS assumes that beyond wind and solar, the energy system relies on batteries, storage and some level of carbon capture, utilization and storage (“CCUS”) and hydrogen.

NZE represents a pathway for the global energy sector to achieve net-zero emissions by 2050. This scenario also assumes key energy-related SDGs are achieved through universal energy access by 2030 and major improvements in air quality. NZE is built upon the idea that a global increase in electrification supports the journey to net-zero. It assumes that an aggressive carbon price is set in Canada, the US and Australia. It also assumes the power sector reaches net-zero emissions by 2035 in advanced economies while natural gas capacity is stable to 2030 and declines significantly into 2040. Like the SDS, NZE assumes that beyond wind and solar, the energy system relies on batteries, storage and some level of CCUS and hydrogen.






TRANSALTA CORPORATION M75

Management’s Discussion and Analysis
Key Climate Scenario Findings
Using climate scenarios, we analyzed the resiliency of our business and determined specific risks and opportunities for our individual assets. All three scenarios present opportunities for TransAlta’s growth related to renewables, storage solutions and ancillary services. The scenario analysis found that our wind and solar assets have the highest prospects for growth, which aligns with our growth strategy. Under all scenarios, hydro remains a valuable asset as it allows for expansion to include storage.

The figures in the following sections highlight TransAlta's top risks, opportunities and management response across all scenarios.

Top Identified Climate-Related Risks by Scenario
Increased competitionDecreased demand of natural gas electricityIncreased operational costs
DescriptionSubsidies/funds available for clean energy transition increase as governments aim to grow installed capacity of renewables to meet rising electricity demand and compensate for the closure of carbon-intensive power plants. It is expected that major grid decarbonization investments will flow into Alberta as many other markets where TransAlta operates are heavily regulated and/or are already low carbon. This will increase competition in the merchant market, making a large part of the generating fleet frequently bid at zero, driving down the average price of dispatched electricity. Simultaneously the cost of renewables, expected to decline across all scenarios, decreases the capital barrier to entry. These combined factors will increase competition for TransAlta. The IEA scenarios do not provide clear indication of electricity pricing and how it can be affected by increased competition. As such, this remains a point of uncertainty. Some structural market changes may be required to guarantee returns for power generators and successfully decarbonize the grid.Demand of power from natural gas declines as the market shifts towards cleaner power. An additional decline from Canadian oil & gas customers can occur as oil production levels drop under NZE and SDS. The transition to a lower-carbon world will likely result in volatility and market uncertainty. Counterintuitively, natural gas power may be necessary to provide power in the transition if the pace of decarbonization is slower than expected in the scenarios or if grid-scale storage solutions do not develop/commercialize as modelled. In these cases, with coal phased out, natural gas assets will be relied on for baseload generation. This means that natural gas assets may still play a role for a smooth and efficient energy transition. Optimization of natural gas assets is required, and additional investments need to be assessed with caution to consider the pace of decarbonization and consequent risk of decreased demand for natural gas power. Carbon price increases the cost of natural gas operations. Additional mandated emission reductions could force remaining plants to invest in technologies like CCUS, increasing the operating costs for natural gas plants further. Natural gas assets in the US and Australia face less risk compared to assets in Alberta as they are contracted and can pass down carbon costs to their clients. Current and anticipated regional carbon pricing monitoring is required to plan and assess increases in operational costs and impacts on new projects and investments.
NZEBy 2040, renewables are expected to comprise over 85 per cent of the total electricity generations in the regions we operate. This surge in renewables will increase competition and drive electricity pricing down. The change in electricity prices and increased market uncertainty are expected to impact our profits. The share of natural gas electricity generation is expected to decline over 50 per cent in the regions where we operate by 2040 compared to 2019 levels. This lower demand for natural gas power is expected to impact our natural gas assets if no management responses are implemented.
Higher operational costs driven by an increase in carbon price to US$205/tonne CO2e by 2040 in all our operating regions (advanced economies under IEA scenarios) and lower operational capacity is expected to impact the profits from our natural gas assets.




TRANSALTA CORPORATION M76

Management’s Discussion and Analysis
Top Identified Climate-Related Risks by Scenario
Increased competitionDecreased demand of natural gas electricityIncreased operational costs
SDS
Fewer subsidies/funds are expected under this scenario compared to NZE. However, renewable costs will still decline approximately 10 per cent in wind and 55 per cent in solar by 2040 compared to 2019 levels. This decline with some level of subsidy will increase competition and potentially decrease electricity prices, which is expected to impact our profits. Natural gas electricity generation still falls over 50 per cent in North America while remaining flat in Australia by 2040 when compared to 2019 levels. Demand for natural gas power is expected to decrease at slower pace than under NZE. This could potentially impact our natural gas assets if no management responses are implemented.
Increase in operational costs would happen at a slower rate compared to NZE but carbon costs are still expected to reach US$140/tonne CO2e by 2040 in all of our operating regions. This could potentially impact the operational capacity and profits from our natural gas assets, depending on the ability to pass carbon prices on through our contracts.
STEPS
While minimal subsidies are expected and the cost of entry will not decline at the same rate as SDS or NZE, renewable costs are still expected to decline approximately 8 per cent in wind and 45 per cent in solar by 2040 compared to 2019 levels. This will still cause an increase in competition that is expected to be offset by additional electricity demand and therefore it is not expected to impact our profits.Natural gas electricity generation is expected to increase over 15 per cent in the regions we operate by 2040 compared to 2019 levels. These changes are not expected to affect our natural gas assets. Operational costs are not expected to significantly increase under this scenario as only Canada sees a carbon price in 2040. Therefore, profits from our natural gas assets are not expected to be affected.
Management ResponseNavigating the uncertainty around market dynamics (structure, pricing and competition), government policies and planning is critical for TransAlta. We use hedging and PPAs to stabilize pricing and are planning on leading clean energy growth where we operate. See more details of our strategy and risk management under the Climate Strategy section and Managing Climate Change Risks and Opportunities section of this MD&A.
Optimize gas assets to maximize value and cash flows to support renewables and storage growth. Our converted natural gas units generate nearly 50 per cent fewer CO2 emissions compared to coal. Repurposing the coal facilities rather than decommissioning them reduces the cost and emissions associated with new construction and aligns with the UN SDGs, specifically "Goal 9: Industry, Innovation and Infrastructure." In parallel, we continue growing our renewable fleet; by 2025 we will have achieved a 100 per cent portfolio mix of renewables and natural gas with 70 per cent of EBITDA attributable to renewables.
We have taken significant steps to reduce our carbon footprint. In 2021, we achieved a total reduction of 61 per cent compared to our 2015 emission levels. By 2026, we have a commitment to reduce scope 1 and 2 GHG emissions by 75 per cent from a 2015 base year and plan to achieve carbon neutrality by 2050. Further, our corporate functions apply regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks of uncertainty in the carbon market.
















TRANSALTA CORPORATION M77

Management’s Discussion and Analysis
Top Identified Climate-Related Opportunities by Scenario
Renewables become major energy sourceNew technology development
DescriptionOpportunities to grow the renewable fleet exist across all scenarios. Renewable assets (hydro, wind, solar) are expected to become the default form of generation with demand for power from these type of assets increasing. Hydro is likely to grow in value given increased renewables penetration and the need for reliable zero-emitting generation. This can make hydroelectric power a stronger source of baseload electricity in many regions. The decreasing cost of renewables also facilitates the growth of a renewable fleet, especially under NZE and SDS. Opportunities for development of battery or hydroelectric storage systems and ancillary services exist across all scenarios as renewable energy continues to penetrate the grid. Developments in these areas are required to keep electricity flowing when the renewables in a region are not producing. Storage is specially anticipated to play an important role in the energy transition. Cost-competitive battery storage enables greater adoption of renewables.
NZEA growth of renewable electricity generation of approximately 950 per cent is expected by 2040 compared to 2019 levels. This results in renewables comprising more than 85 per cent of the electricity generation in the regions we operate. The transition of hydro to baseload capacity is expected to create upside for TransAlta. An increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues. Increased revenues through access to new and emerging markets are expected to enable growth and higher revenues under NZE. With more than 85 per cent of electricity in areas we operate made up of renewables, there will be big steps forward in storage and ancillary services technologies. Storage capacity is expected to grow to approximately 250 GW in the US by 2040.
SDS
A growth of renewable electricity generation of approximately 550 per cent is expected by 2040 compared to 2019 levels. This results in renewables comprising more than 75 per cent of the electricity generation in the regions where we operate. An increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues. Increased revenues through access to new and emerging markets are expected to enable growth and higher revenues under SDS. A lower share of renewables than in NZE will allow swing production to remain present; however, growth in ancillary and storage capacity will still be needed to support the market. Storage capacity is expected to grow to approximately 110 GW in the US by 2040.
STEPS
STEPS growth is muted relative to the other scenarios but still sees a growth of renewables of 280 per cent by 2040 compared to 2019 levels. This growth will allow approximately 50 per cent of electricity generation to come from renewables in areas where we operate by 2040. Increase in TransAlta’s renewable capacity and demand are expected to enable growth and higher revenues. Access to new and emerging markets would be limited under this scenario compared to NZE and SDS. While growth in renewables is expected, the need for new technologies is not a necessity in this market and may not be profitable. Therefore, our revenues are not expected to be affected.
Management ResponseOur renewable energy commitment began more than 100 years ago when we built the first hydro assets in Alberta, which still operate today. Today we operate over 50 renewable facilities across Canada, the US and Australia. By the end of 2025, we expect 70 per cent of our EBITDA to be derived from renewables. Our strategy is focused on the operation of our existing assets (wind, hydro, solar, gas, storage and coal) and the development of renewable energy, storage and low-carbon natural gas generation. Our investments and growth in renewable energy are highlighted by our portfolio of renewable energy-generating assets. From 2000 to 2021, we grew our nameplate renewables capacity from approximately 900 MW to over 2,800 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.To leverage this opportunity and combat the challenges of renewable energy intermittency, we continue to invest in battery storage. In 2020, we launched WindCharger, a "first of its kind" battery storage project that stores energy produced by our Summerview II wind facility and discharges electricity onto the Alberta grid during system supply shortages. Further, in 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP through the construction of the Northern Goldfields Solar Project in Western Australia. This project will support BHP in meeting its emissions reduction targets and delivering lower carbon, sustainable nickel to its customers.




TRANSALTA CORPORATION M78

Management’s Discussion and Analysis
NZE: The most significant risks include increased competition, decreased demand for natural gas and increased operational costs due to increased carbon pricing and emission reduction mandates. The most significant opportunities include a shift toward renewables as the default energy source and new technology developments, including battery storage systems and ancillary services. It is worth noting that there are additional risks and opportunities for TransAlta under NZE. For example, changes in how energy market services are offered could positively or negatively impact our business. Further, as carbon credit policies evolve, so will our ability to use credits. Lastly, as renewables become the primary energy source, a rethinking of ancillary services will be necessary but could create significant opportunities for TransAlta.

SDS: The risks and opportunities remain the same under SDS as NZE; however, the impacts are reduced as market changes are slower and less extreme. Renewables still become the primary electricity source, and there are new technology opportunities, particularly in batteries. Natural gas electricity demand still declines by 2040. Carbon pricing exists in the US and Australia, but the price is reduced compared to NZE. Lastly, a reevaluation of ancillary services still presents an opportunity for TransAlta.

STEPS: Under STEPS, renewable generation sees significant growth but does not become the predominant energy source. Implementing new technologies is much slower, and the demand for batteries is reduced. The demand for natural gas electricity does not decline, and there are no large-scale market changes making services, pricing and ancillary services more stable. This removes the risk associated with natural gas electricity demand but eliminates the opportunity for growth in ancillary services. Physical risks become more relevant under this scenario than transitional risks.

To mitigate risks and capitalize on opportunities, we have developed climate signposts to monitor the evolution of future climate scenarios. Signposts are indicators that suggest the likelihood of a particular climate scenario. Examples of signposts include directional change in carbon and oil prices. As demonstrated in the following figure, the findings from the climate scenarios and these signposts work alongside our sustainability metrics and targets to inform the evolution and resiliency of our Company strategy and financial planning, risk management, opportunity assessment and planning for uncertainty.

The figure below shows how we integrate climate into our overall risk management strategy:

climategovernancea.jpg






TRANSALTA CORPORATION M79

Management’s Discussion and Analysis
Managing Climate Change Risks and Opportunities
We actively monitor and manage climate-related risks through our company-wide enterprise risk management processes. In 2021, we established a formal process to review specific risks using climate scenario analysis. As previously mentioned, climate change risks and opportunities are addressed at each of the Board level, executive and management level, business unit level and through our corporate functions. The business units and corporate functions work closely together and provide information on risks and opportunities to management, the executive team and the Board.

Climate change risks at the asset or business unit level are identified through our Total Safety Management System, asset management function and systems, energy and trading business, communication with stakeholders, active monitoring and participation in working groups. All identified material risks are added to our ERM register and scored based on likelihood and impact. We do not consider risks in isolation, and major risks are the focus of management response and mitigation plans. Further discussion can be found in the Governance and Risk Management section of this MD&A.

We divide our climate change risks into two major categories as per guidance from the TCFD: (i) risks related to the transition to a lower-carbon economy and (ii) risks related to the physical impacts of climate change.

Transition Risks to a Lower Carbon Economy
We actively aim to understand and manage the impact of climate change on our business as the world shifts to a lower-carbon society.

Policy and Legal Risks
Changes in current environmental legislation do have, and will continue to have, an impact upon our operations and our business in Canada, the US and Australia. For a more detailed assessment of policy and regulatory risks please refer to the Governance and Risk Management section of this MD&A.

Canada
The Government of Canada has set out ambitious objectives for carbon emissions reduction, including achieving a 40 to 45 per cent national emissions reduction over 2005 levels by 2030, a net-zero electricity grid by 2035 and a net-zero national economy by 2050. The government plans to rely on several policy tools to achieve its emissions objectives, including carbon pricing, emissions performance regulations, funding for industrial energy transition, a Clean Fuel Regulation and incentives for consumers.

In 2021, a Supreme Court of Canada decision confirmed the federal government has significant authority to set national carbon pricing standards. We anticipate the federal government will use this authority to align provincial carbon pricing systems with national carbon targets. Canada’s provinces have significant jurisdiction over their respective electricity sectors and play an important role in setting carbon pricing policy and emissions performance standards, as well as developing and operating their own funding and incentive programs. Negotiation to align carbon pricing, funding and regulatory standards will likely require significant effort and create the risk of tension and misalignment between federal and provincial governments.

Risks
▪Escalation in carbon prices and emissions performance regulation may impact TransAlta’s natural gas generation fleet in Canada as governments escalate policy stringency to meet 2030, 2035 and 2050 targets.
▪Increased government funding for industrial energy transition may create out of market incentives for competing generation.
▪Regulatory incentives, including emissions reduction crediting, may create out of market incentives for competing generation.
▪Lack of federal/provincial coordination with respect to climate policy and regulation may lead to investment uncertainty.





TRANSALTA CORPORATION M80

Management’s Discussion and Analysis
Opportunities
▪Independent estimates suggest that achieving Canada’s climate targets will require a minimum of twice Canada’s current non-emitting generation. This presents strong policy alignment with TransAlta’s Clean Electricity Growth Plan.
▪Government funding for innovative technology to reduce emissions from the electricity sector offers TransAlta the potential opportunity to gain project support for uneconomic new technologies, which will enable the Company to grow its ESG and policy-aligned generation and energy storage fleet.
▪Government support for industrial electrification and consumer incentives mandates for electrification, such as for the purchase of electric vehicles, will grow the electricity load over time and create new opportunities for contracted clean generation.

Management Response
▪TransAlta’s Clean Electricity Growth Plan will reduce the proportional Company exposure to potential policy and regulatory decisions that negatively impact natural gas generation.
▪Our coal-to-gas facilities fit well within government plans to continue providing reliable and competitively priced electricity for consumers and industry.
▪Our remaining natural gas facilities operate under contract, reducing TransAlta’s exposure to changes in carbon pricing.
▪TransAlta actively engages with the federal and provincial governments in Canada to inform and influence policy development to ensure that our generating fleet continues to serve our customers as the country undertakes a broader energy transition.
▪We actively work, directly and through industry associations, to encourage governments to adopt a level playing field within funding and crediting programs so that all new projects receive equitable governments incentives and funding.
▪TransAlta actively engages with all relevant Canadian governments to seek policy alignment across carbon pricing and regulatory and funding programs to create the greatest possible degree of investment certainty.

United States
The US government has set out ambitious objectives for carbon emissions reduction, including achieving a 50 to 52 per cent national emissions reduction over 2005 levels by 2030, a net-zero electricity grid by 2035 and a net-zero national economy by 2050. The US does not have a national carbon pricing regime but does offer federal incentives for renewable generation, which makes the US policy environment less predictable than in other countries where we operate.

State and regional climate and market policies have a significant impact on the pace of energy transition in the US with many governments operating under renewable portfolio standards and carbon pricing regimes. Similar to Canada, independent estimates suggest that the US will require substantial growth in zero-emissions generation to meet its national climate targets.

Risks
▪TransAlta operates two thermal generating facilities in the US that could be subject to short-term climate policy changes, but our exposure to this policy risk is low (please refer to Management Response below).
▪Given overall political uncertainty, renewable growth projects face elevated uncertainty with respect to long-term federal incentive programs.

Opportunities
▪Achieving US climate goals requires continued growth in zero-emissions electricity generation. TransAlta’s Clean Electricity Growth Plan is focused on providing renewable electricity to contracted customers in a manner aligned with federal and, where applicable, state goals.
▪US tax incentive programs offer significant support for new renewable projects, making the US an attractive growth market.

Management Response
▪TransAlta’s single coal unit in Washington State is subject to a retirement agreement with the state government that exempts the facility from carbon pricing prior to its end of life in 2025. TransAlta’s cogeneration unit at Ada operates under a contract that reduces the Company’s exposure to policy risk.
▪Our Clean Electricity Growth Plan is focused on developing and acquiring contracted assets that provide long-term certainty with respect to revenue and eligibility for government incentive programs. TransAlta actively assesses available government renewable tax legislation and programs to maximize, wherever possible, access to project incentives.




TRANSALTA CORPORATION M81

Management’s Discussion and Analysis
Australia
The Government of Australia has a 26 to 28 per cent national emissions reduction target over 2005 levels by 2030 and a goal to achieve a net-zero national economy by 2050. The government has stated it does not plan to adopt carbon pricing but intends to offer incentives for energy transition. Australian state governments have all adopted net-zero goals and a number of states have interim targets for 2030 and 2040. These state policies are driving demand for zero-emissions electricity and energy storage.

Risks
▪TransAlta’s Australian natural gas assets may face policy risk related to changes in government policies but remain well positioned to mitigate those risks (please refer to Management Response below).

Opportunities
▪Our Clean Electricity Growth Plan is focused on building new, clean generation in Australia and other markets. Government policies and funding programs are generally supportive of the types of projects contemplated within TransAlta’s strategy.

Management Response
▪TransAlta’s assets are predominantly contracted and serve remote industrial load. As a result, the Company faces reduced policy risk.

Technology Risks
Technological changes to support the low-carbon transition present both risks and opportunities for TransAlta. We evaluate existing and emerging impacts of technology through our technologies team and our ERM process. Examples of technology risks and opportunities include infrastructure changes (such as shift to distributed energy and away from large-scale power generation infrastructure assets and projects) and digitization combined with greater adoption of energy efficiency (less use of our end product). Cost-competitive battery storage will enable greater adoption of renewables and 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. In 2020, we completed our first battery storage (10 MW) project at one of our wind farms in southern Alberta. In 2021, we agreed to deliver a hybrid system of solar with battery storage (48 MW) in Western Australia. We continue to investigate the possibility of battery storage at our other facility locations. Our teams continuously adopt improved technology at each of our new developments, which helps protect our shareholder value and maintain reliable and affordable electricity delivery.

We are well-positioned to take advantage of technological opportunities in storage through hydro and/or battery power. We are also well-positioned to take advantage of advancements in renewable technologies as we build new facilities. We are actively accelerating our renewable growth strategy, with $3 billion in investment and 2 GW of growth planned by 2025. We will continue monitoring new technologies such as storage, hydrogen and CCUS for future deployment. For further information on technology and innovation, please refer to the Technology Adoption and Innovation Focus section of this MD&A.

Market Risks
Our major market risks are associated with our coal and natural gas assets. Increased costs for natural gas supply due, in part, to carbon pricing changes could impact our operating costs. We actively monitor market risks through our energy marketing and asset optimization teams and our ERM process. We manage the market risks to our coal assets by converting them to natural gas and plan to fully transition off coal by 2025. Further, our corporate functions apply regionally specific carbon pricing, both current and anticipated, as a mechanism to manage future risks of uncertainty in the carbon market. To simultaneously manage our risks and leverage market opportunities, we continue operating our hydro, wind and solar facilities and are investing in expanding our renewable energy fleet.

We currently have over 20 renewable projects that are either under construction or in the development stage. We are committed to growing our clean energy fleet and since 2019 have added over 400 MW of renewables and storage, including utility-scale battery storage. In 2021, we retired or converted 2,260 MW of coal generation. Further, we established approximately 3 GW of wind and solar pipelines and organized Canadian, US and Australian clean energy growth teams. Our renewable fleet makes our overall portfolio more resilient to climate risk, provides increased flexibility in generation and creates incremental environmental value through environmental attributes. Lastly, we recognize the opportunity to grow our ancillary services, such as systems support, providing flexibility to the decarbonizing grid.





TRANSALTA CORPORATION M82

Management’s Discussion and Analysis
Reputation Risks
Negative reputational impacts, including revenue loss and reduced customer base, are evaluated through our ERM process. In the past, we experienced negative reputational impacts due to our coal operations, including a negative impact on the market price of our common shares. Our transition away from coal mitigates this reputational risk. As consumer trends move in favour of renewable and clean electricity, we are investing in a diversified mix of renewable generation and optimizing our natural gas fleet. We continue to actively monitor and manage reputational risks by delivering renewable power solutions while maintaining competitive costs and reliability.

Physical Impact Risks of Climate Change
As we learn more about the physical risks associated with climate change, we continue to consider acute and chronic risks that could significantly impact our operations.

Acute Physical
We have operating assets in three countries and varied geographic locations, many of which could be impacted by extreme weather events. We are thus continuously evaluating the potential impact of acute climate change on our business. Our facilities, construction projects and operations are exposed to potential interruption or loss from environmental disasters (e.g., floods, strong winds, wildfires, ice storms, earthquakes, tornados, cyclones). A significant climate change event could disrupt our ability to produce or sell power for an extended period. Therefore, we strive to mitigate future impacts with climate adaptation solutions.

For example, our gas facility at South Hedland, Australia, is built with climate adaptation in mind. We designed the facility to withstand a category 5 cyclone (the highest cyclone rating). We have mitigated the risk of floods that can occur in the area by constructing the facility above normal flood levels. In 2019, a category 4 cyclone hit this facility but did not impact operations. We were able to continue generating electricity through the storm despite widespread flooding and the shutdown of the nearby port. For further information on weather-related risks, please refer to Weather in the Progressive Environmental Stewardship section of this MD&A.

Chronic Physical
We continuously investigate the physical impacts of chronic climate change on our operating assets and actively integrate climate modelling into our long-term planning. For example, changes to water flow or wind patterns could impact our hydro and wind businesses and associated revenue generation.

Climate Change Metrics and Targets
Metrics and Targets
At TransAlta, climate change management and performance are a top priority. We establish our goals and targets with reference to the UN SDGs and the Future-Fit Business Benchmark. Our sustainability targets support the long-term success of our business. Over time, we have set ourselves apart with actions that demonstrate climate change leadership, including reducing our annual emissions by over 19 million tonnes of CO2e since 2015. We are committed to evolving our leading sustainability target-setting process, ensuring our goals are meaningful and ambitious, and securing TransAlta's competitiveness, both today and in the future.

The following targets outline our pathway to becoming a leader in clean, affordable, and reliable power. We establish goals and targets to manage key and emerging sustainability issues and improve our performance in these areas. We will continue to evolve and adapt our targets to focus on key anticipated climate-related issues.





TRANSALTA CORPORATION M83

Management’s Discussion and Analysis
Progress towards our climate-related targets are presented below:
Clean Energy Growth
TargetDevelop new renewable projects that support our customers' sustainability goals to achieve both long-term power price affordability and carbon reductionsNo further coal generation; 100% of our owned net generation capacity from renewables and gas
Year20212025
Progress
(% of target met)
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Notes
In 2020, we developed WindCharger, a "first of its kind" battery storage project; in 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP through the construction of the Northern Goldfields Solar Project in Western Australia. In 2021, we also entered into long-term PPAs for the off take of 100 MW from our Garden Plain wind project in Alberta and 100 per cent of our 300 MW White Rock East and White Rock West wind projects in Oklahoma.
One of our major strategic goals is to be coal-free in Canada by the end of 2021 with the remaining US unit retiring by 2025. In 2021, we achieved full phase-out of coal in Canada. This means TransAlta’s thermal facilities in Alberta have been fully transitioned to a 100% natural gas operation. The Highvale coal mine was closed. In the US, Centralia Unit 1 retired on Dec. 31, 2020, and the remaining unit is set to retire on Dec. 31, 2025. Thus far, we have retired or converted 90% of our existing coal fleet and will retire the remaining 10% by 2025.
UN SDG Alignment
Target 7.2: "By 2030, increase substantially the share of renewable energy in the global energy mix."Target 7.1: "By 2030, ensure universal access to affordable, reliable and modern energy services.”
Emissions Reduction
TargetBy 2026, achieve a 75 per cent reduction of scope 1 and 2 GHG emissions from a 2015 base year.Achieve carbon neutrality
Year20262050
Progress
(% of target met)
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Notes
We are well on track to achieve our target of 75 per cent GHG emissions reductions by 2026. We estimate that this is in line with limiting global warming to 1.5°C and, in 2021, committed to setting a science-based emissions reduction target through the Science Based Targets initiative. Since 2015, we have reduced our annual GHG emission by approximately 19.7 million tonnes CO2e or 61%. In 2021, we reduced approximately 3.9 million tonnes of CO2e over 2020 levels.
In 2021, we 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.
UN SDG AlignmentTarget 13.2: "Integrate climate change measures into national policies, strategies and planning."Target 13.2: "Integrate climate change measures into national policies, strategies and planning."






TRANSALTA CORPORATION M84

Management’s Discussion and Analysis
GHG Disclosures
Our GHG emissions are calculated using a number of different methodologies depending on the technologies available at our facilities. Emissions data has been aligned with the “Setting Organizational Boundaries: Operational Control” methodology set out in the GHG Protocol: A Corporate Accounting and Reporting Standard developed by the World Resources Institute and the World Business Council for Sustainable Development. We report emissions on an operation control basis, which means we report 100 per cent of emissions at the facilities we operate.

The GHG Protocol 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 1 or 2) that occur in the value chain of the reporting company, including both upstream and downstream emissions.

We compile our corporate GHG inventory using our business segment GHG calculations. As a result, emission factors and global warming potentials used in our GHG calculations can vary due to difference in regional compliance guidance. The Clean Energy Regulator in Australia amended global warming potentials in August 2020. Therefore, the use of global warming potentials in our GHG calculations related to our Australian assets differs from the rest of our fleet. Applying harmonized global warming potentials across our fleet would result in a minor variance to our overall calculated GHG totals.

Our 2021 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.

The following tables detail our GHG emissions by scope, business segment and country in million tonnes of CO2e. Some values do not sum to the indicated total due to rounding of tabulated emissions. Zeros (0.0) indicate truncated values.

Year ended Dec. 31202120202019
Scope 112.416.320.5
Scope 20.10.10.1
Total GHG emissions12.516.420.6

Year ended Dec. 31202120202019
Hydro0.00.00.0
Wind & Solar0.00.00.0
Gas6.57.79.3
Energy Transition6.08.611.3
Corporate and Energy Marketing0.00.00.0
Total GHG emissions12.516.420.6

Year ended Dec. 31202120202019
Australia1.01.11.1
Canada7.99.411.6
US3.65.98.0
Total GHG emissions12.516.420.6
In 2021, our GHGs emissions (scopes 1 and 2) were estimated to be 12.5 million tonnes as a result of normal operating activities. Compared to 2020, this represents a reduction of approximately 24 per cent or 3.9 million tonnes CO2e. Reductions in GHG emissions were primarily due to shutdowns during coal-to-gas conversions and coal unit retirements. Because we sell the environmental attributes generated from our renewable energy facilities, we do not subtract this amount from our total emissions, but it should be noted that TransAlta’s customers are reporting GHG reductions using our renewable energy assets, projects and operations.





TRANSALTA CORPORATION M85

Management’s Discussion and Analysis
GHG emissions are verified to a level of reasonable assurance in locations where we operate within a carbon regulatory framework. Any historical revisions to GHG data will be captured and reported in future disclosure. The majority of our GHG emissions result from carbon dioxide emissions from stationary combustion from coal and natural-gas-powered generation.

The following highlights our scope 1 and 2 GHG emission reductions since 2015 and our targeted emissions in 2026 (in line with our new GHG target). The actual GHG emissions for the Company in 2026 will vary from that presented below depending on, among other things, the growth of the Company, including its on-site generation business.

Year ended Dec. 312026 (forecast)20212015
Total GHG emissions (million tonnes CO2e)
8.112.532.2

We estimate our scope 3 emissions in 2021 to be in the range of four million tonnes of CO2e, which is primarily attributed to our non-operated joint venture interests.

The table below shows the alignment of our climate change management disclosure with TCFD recommendations.

Recommended DisclosuresLocation
Governance
Describe the board’s oversight of climate-related risks and opportunitiesOversight by the Board of Directors
Describe management’s role in assessing and managing climate-related risks and opportunitiesRole of Senior Management
Strategy
Describe the climate-related risks and opportunities the organization has identified over the short, medium, and long termKey Scenario Findings
Describe the impact of climate-related risks and opportunities on the organization’s businesses, strategy and financial planningClimate Change Strategy, Key Climate Scenario Findings
Describe the resilience of the organization’s strategy, taking into consideration different climate-related scenarios, including a 2°C or lower scenarioClimate Scenarios, Key Climate Scenario Findings
Risk Management
Describe the organization’s processes for identifying and assessing climate-related risksClimate Change Strategy
Describe the organization’s processes for managing climate-related risksManaging Climate Change Risks and Opportunities
Describe how processes for identifying, assessing and managing climate-related risks are integrated into the organization’s overall risk management
Managing Climate Change Risks and Opportunities
Metrics and Targets
Disclose the metrics used by the organization to assess climate-related risks and opportunities in line with its strategy and risk management processClimate Change Metrics and Targets
Disclose scope 1, scope 2 and, if appropriate, scope 3 greenhouse gas (GHG) emissions and the related risksClimate Change Metrics and Targets
Describe the targets used by the organization to manage climate-related risks and opportunities and performance against targetsClimate Change Metrics and Targets





TRANSALTA CORPORATION M86

Management’s Discussion and Analysis
Engaging with Our Stakeholders to Create Positive Relationships
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 fostering positive relationships with Indigenous neighbours, communities, stakeholders, governments, industry and landowners in the areas where we operate, as well as public health and safety. This section covers sustainability factors of social and relationship capital and intellectual capital as per guidance from the International Integrated Reporting Framework.

Human Rights
TransAlta is committed to honouring domestic and internationally accepted labour standards and supports the protection of human rights of all its employees, contractors, suppliers, partners, Indigenous partners and other stakeholders. We abide by human rights and modern slavery legislation in Canada, the US and Australia. 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 have governance practices in place for the protection of human rights.

Our Human Rights and Discrimination Policy communicates our commitment to human rights in our operations and supply chain to ensure that our personnel policies and practices in our global operations will respect fundamental rights. Expected behaviours of all our employees are set out in our Corporate Code of Conduct. We are committed to creating a work environment where all workers feel safe and are valued for the diversity they bring to our business. In 2021, we launched mandatory Code of Conduct training for employees to complete before signing the Code of Conduct. The training completion rate was 100 per cent. We also have adopted a Supplier Code of Conduct that defines the principles and standards expected of suppliers, their employees and contractors to meet while in the provision of goods and/or services to TransAlta.

Our Whistleblower Policy provides a mechanism for our employees, officers, directors and contractors to report, among other things, any actual or suspected ethical or legal violations. We would seek to remedy the impact promptly in order to establish a corrective action plan in collaboration with the relevant individuals and stakeholders.

In Australia, we report under the Australian modern slavery legislation. Our Modern Slavery Act Statements demonstrate the actions we have taken to assess and address modern slavery risks within our operations and supply chain. These annual statements are approved by our Board of Directors and are publicly available.

Indigenous Relationships and Partnerships
At TransAlta, we value relationships and partnerships with our Indigenous neighbours, aspiring to the highest standards in our relationships with Indigenous people. Our core values of safety, innovation, sustainability, respect and integrity represent how we do business and engage with Indigenous people. Our commitment to Indigenous relations is led by a centralized corporate team who foster a relationship-based approach, involving employees at each facility and within each business unit. These employees and teams build relationships with the neighbouring Indigenous communities and work to develop respectful, trusting relationships that help TransAlta continually improve its business practices.

Our Indigenous Relations Policy focuses on four key areas: community engagement and consultation; business development; community investment; and employment. We ensure that TransAlta’s principles for engagement are upheld and that the Company fulfils its commitments to Indigenous communities. Efforts are focused on building and maintaining solid relationships and 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 and unlock opportunities.

Methods of engagement include:
▪Relationship building through regular communication and meetings with representatives at various levels within Indigenous communities and organizations;
▪Hosting company-community activities to share both business information and cultural knowledge;
▪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 CORPORATION M87

Management’s Discussion and Analysis
TransAlta takes a proactive approach in engagement by initiating communication early in project development to allow concerns to be identified and addressed, minimizing potential project delays. We strive to maintain relationships through the life cycle of our operations, from project development and construction, through operation, until decommissioning phases are complete. We work with communities to build relationships based on a foundation of ongoing communication and mutual respect. This is recognized in our Indigenous Relations Policy, which was recently updated to include our acknowledgement and understanding of the intent of the recommendations of the United Nations Declaration on the Rights of Indigenous Peoples. In addition, TransAlta is a member of the Canadian Council for Aboriginal Business (“CCAB”) and is certified at the Bronze level in the CCAB’s Progressive Aboriginal Relations program.

Participation in Indigenous Ceremonies
In 2021, TransAlta was honoured to participate in three ceremonies with Elders and other representatives from Indigenous communities in Canada: a Water Ceremony with the Aamjiwnaang First Nation; a Water Ceremony with the Wesley First Nation of the Stoney Nakoda Sioux Nations; and a Blessing Ceremony with an Elder from Paul First Nation at the Highvale mine for tree planting.

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 move forward to become future leaders in their communities. We are keen to help young Indigenous students reach their full potential and achieve their dreams. We also believe in providing support to Indigenous primary school students, helping to instill a passion for lifelong learning.

In 2021, TransAlta provided more than $375,000 to support Indigenous youth, education and employment programs, representing 13 per cent of TransAlta’s total community investment. Highlights include:

▪Mother Earth's Children's Charter School ("MECCS") – Located in Treaty 6 territory, Alberta, 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 student population is diverse and includes Métis, Cree, Nakota Sioux and Stoney. Volunteers from TransAlta travel to the school to deliver Christmas gifts, providing both our employees and the students the opportunity to engage with each other. Due to the COVID-19 pandemic, this tradition has been conducted remotely. In 2021, more than 200 Christmas gifts were purchased for students at Mother Earth’s Children’s Charter School and Wihnemne School on Paul First Nation.
▪Spirit North – TransAlta is proud to support Spirit North, a national charitable organization that uses land-based activities to improve the health and well-being of Indigenous youth. Through the transformative power of sport and play, participants learn important lessons, discover untold potential and build the confidence and courage needed to overcome the hardships Indigenous youth often face.
▪Southern Alberta Institute of Technology 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.
▪The Banff Centre for Arts and Creativity – This year, TransAlta continued our ongoing partnership with the Banff Centre and supported scholarship funding for Indigenous community members to participate in leadership training.
▪Books In Homes – Funding supports an early literacy program for the children of Tjiwarl Aboriginal Corporation members in Western Australia.
▪Mount Royal University Foundation – Continued partnership with the Mount Royal University Foundation in support of the Indigenous Family Housing Program, which features an Indigenous family tipi in an outdoor space dedicated to Indigenous students and supporting Indigenous cultural programming.
▪Indspire – Continued support for Indspire, a national Indigenous registered charity. Through this program, 14 bursaries of $3,000 each were given to recipients from the following communities: Blood (Kanai) First Nation, Ermineskin Cree Nation, Enoch Cree Nation, Montana First Nation, Simpcw First Nation and Squamish First Nation.
▪Diamond Willow Youth Lodge – In partnership with the United Way of Calgary & Area, designated funding was provided 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.




TRANSALTA CORPORATION M88

Management’s Discussion and Analysis
Indigenous Cultural Awareness Training for TransAlta Employees
In 2021, we adopted a new sustainability target that will see that all employees complete Indigenous cultural awareness training by the end of 2023. We believe education is the foundation to ensuring respectful and strong relationships with Indigenous peoples into the future.

In addition to our training commitment, in 2021 our Indigenous Relations team led three company-wide cultural awareness initiatives in recognition of National Reconciliation Week in Australia and National Indigenous History Month and National Indigenous Peoples Day in Canada.

In 2021, September 30 marked the first National Day for Truth and Reconciliation, which is a federal statutory holiday in Canada and TransAlta chose to adopt this day as one of its statutory holidays. This is an important day for Canadians to take time to pause, reflect and focus to deepen their awareness and understanding of the Canadian residential school system. This day also provides an opportunity to consider how each of us can contribute to ongoing reconciliation with Indigenous peoples. Coinciding with the announcement of unmarked graves of Indigenous school children in British Columbia and Saskatchewan, TransAlta lowered the flags at its Canadian operations for one hour for each grave that was discovered. TransAlta’s Executive Leadership Team delivered a National Day for Truth and Reconciliation Town Hall online event.

Stakeholder Relationships
Fostering positive relationships with our stakeholders is important to TransAlta. Driven by our core values, we see stakeholder transparency as an integral part of our relationships. We take a proactive approach to building relationships and understanding the impacts our business and operations may have on local stakeholders.

TransAlta Stakeholders
To act in the best interests of the Company and to optimize the balance between financial, environmental and social values for both our stakeholders and TransAlta, we seek to:
▪Build relationships through regular engagement with stakeholders regarding 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 establishing stakeholder relationships 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.

Our principal stakeholder groups are listed in the following table.

TransAlta Stakeholders
Non-governmental organizations (NGOs)Community associations and organizationsConnecting transmission facility operators
RegulatorsIndustry organizationsCommunities
Charitable organizations/Non-profitStandards organizationsRetirees
All levels of governmentMediaResidents/Landowners
SuppliersBusiness partnersInvestor organizations
ContractorsUnions/Labour organizationsFinancial institutions
Government agenciesForest associations/IndustryMineral rights owners
System operatorsOil & gas associations/IndustryRailroad owners
CustomersThink tanks Utility owners
MunicipalitiesAcademicsEmployees






TRANSALTA CORPORATION M89

Management’s Discussion and Analysis
Stakeholder Engagement
In order to run our business successfully, we maintain open communication channels with our stakeholders. We commit to timely and professional resolution in our dialogue with stakeholders. Our stakeholder engagement practices are guided by regulatory requirements, industry best practices, international standards and corporate policies. We work internally and with each stakeholder to identify and to mitigate further issues.

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

Information & CommunicationDialogue & ConsultationRelationship Building
Open houses, town halls and public information sessionsIn-person meetings with local groups and communitiesCommunity advisory bodies
Newsletters, telephone conversations, emails and lettersMeetings with individual stakeholders (e.g., landowners and residents) Capacity agreements
WebsitesTargeted audience sessionsSponsorships and donations
Social media postingsTours of our facilities and sitesHosting and attending events

A key focus of our work is to support business growth through proactive engagement with stakeholders in our geographic operating areas in Canada, the US and Australia to develop and maintain relationships, assess needs and fit and seek out collaborative and sustainable 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 construction and maintain engaged communication throughout operations to decommissioning. Examples of stakeholder engagement in 2021 include: the WaterCharger Battery Energy Storage Project; the closure of the Highvale mine; the suspension of the Sundance Unit 5 Repowering Project; the coal-to-gas transition at our Alberta plants; and noise and aircraft lighting detection systems at the Antrim Wind Energy facility in New Hampshire.

Customers
TransAlta serves industrial and commercial customers with power and energy services across its fleet in Canada, the US and Australia. We are focused on customer-centred renewables growth to bring high levels of service quality and reliability for our customers in a low carbon future. As one of the largest electricity generators in Canada, our team serves businesses with:
▪Sustainable solutions starting from the design phase;
▪Energy consumption and cost management solutions;
▪Market price risk and volume exposure mitigation; 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.

Across our business in Canada, the US and Australia, 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.

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. Production from renewable electricity in 2021 resulted in the avoidance of approximately 2.6 million tonnes of CO2e for our costumers.

Examples of renewable energy projects in 2021 include our Garden Plain wind project in Alberta, which has a 130 MW capacity and is subject to a PPA with Pembina, our White Rock Wind Projects in Oklahoma with a 300 MW capacity, which is subject to a PPA with a single offtaker, and our Northern Goldfields Solar Project with a battery energy storage system in Western Australia, which has a 48 MW capacity and is subject to a PPA with BHP.

For further details on how we support our customers' sustainability objectives, please refer to Applied Technologies in the Technology Adoption and Innovation Focus section of this MD&A.





TRANSALTA CORPORATION M90

Management’s Discussion and Analysis
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 renewable energy facilities, battery energy storage systems and hybrid solutions, or long-term offtake agreements from its existing and future renewable and gas-fired 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.

Community Investments
In 2021, TransAlta increased its community investments by 36 per cent and contributed approximately $3.0 million in donations and sponsorships (2020 - $2.2 million), with a continued focus in three priority areas: youth and education, environmental leadership, and community health and wellness.

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 Company raised over $1.1 million for the United Way. TransAlta has been supporting the United Way for over 30 years and has contributed more than $20 million over that time. In 2021, TransAlta made a number of other significant investments. Key highlights for the year included:

▪Calgary Health Foundation - In 2021, TransAlta partnered with the Calgary Health Foundation to support the Newborn Needs campaign in support of the development of a new Foothills Medical Centre Neonatal Intensive Care Unit (“NICU”), serving all of southern Alberta. TransAlta provided an initial $1 million of support in 2021, as part of a $2 million total commitment over a five-year term. The NICU will be a Centre of Excellence for Calgary, Alberta, Canada and the world.
▪The Calgary Stampede Foundation – 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.
▪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.
▪Calgary Reads – TransAlta was proud to continue to support this organization in 2021, which is dedicated to supporting the improvement of literacy skills for children in Calgary.




TRANSALTA CORPORATION M91

Management’s Discussion and Analysis
▪International Women’s Day – As part of TransAlta’s International Women’s Day Celebration, the company provided donations to five organizations that support women in the jurisdictions where we operate:
◦Rise Kira House (Perth, Western Australia) – the Rise Kira House is a 24-hour service supporting young women (aged 14-18) leaving family and domestic violence.
◦Women’s Interval Home of Sarnia-Lambton (Sarnia, Ontario) – The Women’s Interval Home provides emergency shelter and counselling services to abused women and their children. This includes 24-hour emergency and short-term shelter, support, individual and group counselling, transitional services and child-witness counselling services.
◦Elizabeth Fry Society of Northern Alberta (Edmonton, Alberta) – The Elizabeth Fry Society of Northern Alberta partners with communities from Red Deer to Fort McMurray (including rural and Indigenous communities) to address the unique access to justice needs and gaps in services that affect vulnerable individuals.
◦Women United (Lewis County, Washington) - Women United’s mission is to positively impact the lives of women and children living in poverty in Lewis County by encouraging self-sufficiency and empowerment. Women United gathers local women who seek to understand the issues facing the community and then roll up their sleeves to help. They operate as an affinity group of the United Way of Lewis County and as such, work within its mission to lift 30 per cent of Lewis County families out of poverty by 2030.
◦The Women’s Centre of Calgary (Calgary, Alberta) – The Women’s Centre provides a safe and supportive space accessed by thousands of women in Calgary. Supports include: poverty and hunger, family breakdown, parenting, homelessness, unemployment, health and education, immigration and settlement, domestic violence, isolation and loneliness, life transitions and discrimination. Forty-one per cent of the women who access the services and volunteer their time are living in poverty.
▪Calgary Pride – As part of TransAlta’s Pride Celebration in 2021, the company was happy to sponsor the 2021 Calgary Pride Festival and Parade. Calgary Pride aims to create spaces that ensure LGBTQ2+ belonging and celebration. The Calgary Pride Festival and Parade takes place each Labour Day long weekend, with thousands gathering in celebration of gender and sexual diversity.
▪Leinster Community School – Funding was provided for an upgrade to the kindergarten playground area to create a new play-based learning environment, focused on sustainability.
▪Heart Kids – Support was provided for the annual 2021 charity walk for Heart Kids, Australia’s only not-for-profit organization solely focused on supporting and advocating for people impacted by childhood heart disease.
▪Energy Transition Support – On July 30, 2015, we announced a US$55 million community investment over 10 years to support energy efficiency, economic and community development and education and retraining initiatives in Washington State. The US$55 million community investment is part of the TransAlta Energy Transition Bill passed in 2011. This bill was a 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 US$55 million: the Weatherization Board (US$10 million), the Economic & Community Development Board (US$20 million) and the Energy Technology Board (US$25 million). To date, the Weatherization Board has invested US$8 million, the Economic & Community Development Board US$15 million and the Energy Technology Board US$10 million. Specific projects that the boards funded in 2021 include financial support to learning centres (the United Learning Center project, a Boys & Girls Club and the Discover Children’s Museum), a project to install the first renewable energy project in Washington state that generates electricity by harvesting excess pressure from municipal water pipeline, and the installation of a shore power connection point at the Bell Street Cruise Terminal at Pier 66 in Seattle, Washington. The shore power connection will allow vessels with shore power technology to plug into the local electrical grid, which reduces GHG emissions and the burden of diesel exposure to people who live, work and visit along the Seattle waterfront.





TRANSALTA CORPORATION M92

Management’s Discussion and Analysis
Supply Chain and Sustainable Sourcing
We continue to seek solutions to advance supply chain sustainability. 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 2021, the Board approved our revised 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.

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 Company 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 Company’s toll-free telephone or online Ethic Helpline (please refer to Risk Controls — Whistleblower System in the Governance and Risk Management section of this MD&A for more details). Shareholders are also invited to communicate directly with the Board under the Company’s Shareholder Engagement Policy, which outlines the Company’s approach to proactive director-shareholder engagement at and between the Company’s annual shareholders meetings. Under the Shareholder Engagement Policy, shareholders can submit questions or inquiries to the Board, to which the Company will respond. Our Shareholder Engagement Policy is available in the Governance section of the Investor Centre on our website. 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 Company’s approach to executive compensation (i.e., say-on-pay).

The Company 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 2021, representatives of the Board engaged extensively with the Company's significant shareholders. Specifically, since Jan. 1, 2021, independent members of the Board have met with 12 shareholders representing approximately 39 per cent of the Company’s total issued and outstanding common shares. In addition, independent members of the Board engaged with Proxy Advisory firms to discuss a number of topics of relevance to the Company and its stakeholders, including the Company's strategic direction, executive compensation, ESG practices and Board composition and diversity.

Public Health and Safety
We are committed to protecting the public and our assets, as well as the physical, psychological and social well being of our people.

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 the protection of people, property, information and reputation.






TRANSALTA CORPORATION M93

Management’s Discussion and Analysis
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 and 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 the Company 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.

The Company continues to operate under its business continuity plan in response to the global pandemic declared in March 2020. For more information, please refer to COVID-19 in the Significant and Subsequent Events section of this MD&A.

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.





TRANSALTA CORPORATION M94

Management’s Discussion and Analysis
Building a Diverse and Inclusive Workforce
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. In 2021, we improved our ESG performance through our efforts to promote an equitable, diverse and inclusive workforce. This section covers sustainability factors of human capital as per guidance from the International Integrated Reporting Framework.

Equity, Diversity and Inclusion
TransAlta’s commitment and focus on excellence in ED&I is found in our workplace, among 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 2021, TransAlta’s ED&I Council developed our five-year ED&I strategy to achieve the goals and set out a course to attaining the aspirations set out in our ED&I Pledge. Our five-year ED&I strategy was approved by the Board and sets out key milestones for the annual plans from 2021 to 2025. The first phase of this strategy focuses on raising awareness to build a foundation and common understanding upon which our co-workers can have meaningful conversations to learn about one another. The second phase centres around reinforcing and embedding inclusive behaviours.

We continued to expand our ED&I platform in 2021 by offering employees a variety of training, education and awareness on ED&I such as webinars, employee engagement sessions, articles, videos and blogs. After completing our inaugural 2020 ED&I Census, which was delivered by a third party and was sent to all employees to understand our demographics and our experiences in the workplace, we put actions into place to address pain points in 2021. This included celebrating International Women's week and Pride month with several activities, hosting a number of guest speakers on a variety of topics and implementing partnerships for mentorship and Employee Resource Groups opportunities.

Our 2021 ED&I Census results were benchmarked to those of other companies in our industry and within Canada. The results demonstrated a marked improvement of our workforce feeling a greater sense of inclusion and belonging. In addition, our ED&I Census inclusion results were above the energy industry average meeting the inclusion scores of leading ED&I corporations in Canada. In our ED&I Census we received an above industry average response rate of 58 per cent. Of the respondents that completed the ED&I Census, we understand that 30 per cent of the workforce identifies as female, 24 per cent of the workforce identifies with a racial or ethnic minority group, two per cent of the workforce identifies as members of LGBTQ2+ community and 10 per cent of the workforce are people with disabilities.

In 2021, we received market recognition for our ED&I efforts and were certified by a third party for our commitment to measuring, tracking and improving ED&I. We have been recognized for our efforts to measure and set targets to increase diversity, while regularly collecting data on our co-workers’ experiences to identify bias and barriers faced by underrepresented groups and implementing programs and policies designed to unlock specific challenges while tracking results. We have incorporated diversity metrics into TransAlta's 2021 short-term incentive plan for our employees.

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, 2021, women made up 38 per cent of our executive officer team and 42 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 22 per cent and the average percentage of women on executive teams is 18 per cent.

To further support female advancement, we have set targets to: (i) maintain equal pay for women in equivalent roles, (ii) achieve 50 per cent representation of women on our Board by 2030 and (iii) 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 24 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 2021, the Company received the Globe and Mail's Women Lead Here award, which evaluates publicly traded Canadian companies' ratio of female-identifying to male-identifying executives in the top three tiers of executive leadership.




TRANSALTA CORPORATION M95

Management’s Discussion and Analysis

In 2021, in celebration of International Women’s Day 2021 theme #ChooseToChallenge, TransAlta delivered a week-long campaign to highlight the contributions of women in the workplace with live events in recognition of this momentous day as well as training, challenges and a webinar with one of our female Board members. During these celebrations, we launched our Women in Trades Scholarship with 13 different educational institutions for eligible students enrolled in post-secondary trade programs. We are committed to investing in our communities through meaningful impact and the opportunity to enhance the quality of life wherever we operate. The Women in Trades Scholarship is intended to assist women in obtaining an education in trades by showcasing and rewarding successful female role models.

We also pioneered a female apprenticeship program in our Generation business to strategically target the recruitment of high potential female students and train them to gain valuable experiential learning in the trades. The female apprenticeship program has created a pipeline of future female talent for the Company and has resulted in us being able to creatively target, recruit, hire and retain the first-ever female wind technicians, as well as the first females in the roles of instrumentation technician, electrical technician and power plant operator in our gas fleet in Alberta.

Workforce 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 Company.

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 2021, we continued to progress our safety culture transformation despite an unprecedented and extraordinary challenge due to COVID-19. To reinforce behavioural safety, several training and capability-building initiatives were delivered. TransAlta conducted 90 one-hour leadership peer board sessions with participation by Generation leaders from across the fleet. We also implemented and rolled-out our fleet-wide app for Occupation Hazard Assessment. This app supports hazard recognition by identifying hazards and associated controls for tasks related to specific occupations.

Our Total Recordable Injury Frequency ("TRIF") result for 2021 was 0.82 compared to 0.81 in 2020. TRIF tracks the number of more serious injuries, and excludes minor first aids, relative to exposure hours worked. Our TRIF performance year over year has remained relatively unchanged. In 2021, we established an ambitious target of 0.61 and while we did not meet this target, we will continue to work to achieve our goal in the future. In 2021, substantial progress was made on initiatives related to our three key targets: mature our safety culture, assess and address risk tolerance, and standardize safety information and technology. In 2022, we are expanding behavioural safety training to all employees in order to provide them with tools to take control of their behaviours, and consequently, improve our safety results. This training reinforces our journey to create a psychologically safe environment in our workplace as it encourages personal accountability towards safety.

Safety at TransAlta (employees and contractors)202120202019
Lost-time injuries355
Medical aids997
Restricted work injuries523
Exposure hours4,134,0003,948,000 4,108,000 
Total Recordable Injury Frequency (TRIF)0.820.810.73





TRANSALTA CORPORATION M96

Management’s Discussion and Analysis
In addition to TRIF, we have also introduced Total Safety Report Frequency as a key safety metric in our 2021 annual incentive compensation. 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. In 2021, we recorded 7.35 reports per worker, which is above our target of 5.50.

As a demonstration to TransAlta’s commitment to safety, SunHills Mining LP was awarded the Safety Excellence Award from the Alberta Mine Safety Association in June 2021. This award is for best safety performance of all Alberta mines under one million workforce hours based on 2020 performance.

Organizational Culture and Structure
Our employees are central to value creation. Our corporate culture has evolved and adapted throughout our more than 110-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.

As of Dec. 31, 2021, we had 1,282 (2020 — 1,476) active employees. This number has decreased by 13 per cent from 2020 levels, following a reduction in positions in our coal fleet as part of our conversions to gas and ceasing mining operations. With approximately 33 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.

Our organizational structure changed in 2021 to help facilitate effective pace and decision-making in our organization. Our business operates four generating segments, with Gas, Wind and Solar, Hydro and Energy Transition. The Energy Transition is a new segment as described in the Segmented Disclosures under the Segmented Financial Performance and Operating Results section of this MD&A. 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 Company 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 Company. 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.

Employee Retention and Recognition
ESG-Linked Compensation
At TransAlta we have linked our ESG performance to our employees’ compensation, including our executive leadership team. 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., pay for performance). The targets and remuneration framework are reviewed and approved annually by our Board. In 2021, 20 per cent of our corporate annual incentive plan was linked to achieving specific ESG objectives: 10 per cent related to the completion of CO2 reduction projects at existing facilities and diversity and inclusion and organizational health performance, and 10 per cent was linked to workers’ safety. A further 20 per cent of our corporate annual incentive plan was tied to growth, which is focused on expanding TransAlta’s portfolio of renewable generation and will help reduce the Company’s overall GHG emissions intensity. Our long-term incentive plans include strategic goals related to our focus on clean electricity and strong renewables growth.

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.






TRANSALTA CORPORATION M97

Management’s Discussion and Analysis
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 Company, its domestic subsidiaries and specific named employees working internationally. These plans have defined benefit (“DB”) and defined contribution ("DC") options. 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 Company in accordance with governing regulations and actuarial valuations.

We also offer some optional plans for Canadian employees to enhance their financial wellness and retirement savings, with group RRSP and TFSA plans.

In Canada there is an additional non-registered supplemental pension plan (“SPP”) for executive officers whose annual earnings exceed the Canadian income tax limit. The DB SPP was closed as of Dec. 31, 2015, and only current executive officers were grandfathered in the plan. A new DC SPP commenced for executive members hired after Jan. 1, 2016.

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.

On an annual basis, TransAlta recognizes our top achievements through the President’s Awards. In 2021, we added an ED&I award. This award recognizes employees who significantly contributed towards TransAlta’s target of a 40 per cent female workforce by 2030 and TransAlta’s ED&I objective of creating a workplace where all employees feel they belong.

In 2021, TransAlta launched Wellness Wednesdays. This provides employees with weekly awareness, tips and tools on “wellness” topics. TransAlta’s focus on organizational health remained in 2021 through the implementation of nine priority practices into all facets of the organization.

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 2021, we expanded the content and topics in our Professional Development Library, which was launched in 2020. This includes adding a second library for ED&I articles and resources. This library has had over 3,000 hits and over 300 unique users. Important dates and definitions are explained here as well as tips on ED&I best practices such as land acknowledgments and empathetic thinking.

To increase cross-functional internal development opportunities, we created our Opportunity Board. On this Opportunity Board, leaders post opportunities for employees to work on projects within other parts of the organization. Employees then have the opportunity to apply for these projects in order to develop their knowledge and gain experience in a different areas of the business. Eight opportunities were posted, and nine employees were successfully matched to an opportunity during our pilot launch of the board.

Throughout 2021, a Speaker Series of subject matter experts was organized to assist with leadership development and our ED&I journey. Presentation topics included prioritization, constructive conflict, unconscious bias, belonging, allyship, the LGBTQ2+ community and empathy.

Employees and leaders were also offered the opportunity to participate in training focused on working within a remote environment. This training provided leaders and employees with valuable tools to effectively communicate, work productively in a “home” environment and maintain collaboration and connectivity with colleagues across the organization.

Additional internal training is held annually for both leaders and employees. Elevate, a self-directed development program focused on creating a leadership mindset, and Execution Engine, a two-day program that focuses on how to prepare projects, prioritize tasks, improve our communication skills and ensure we are sustaining the work completed by living our health practices. Since launching in 2017, hundreds of employees have participated in these programs.





TRANSALTA CORPORATION M98

Management’s Discussion and Analysis
During 2021, we launched leadership training with Blue Ocean Brain. Partnering with Blue Ocean Brain, a micro-learning consultancy, TransAlta leaders were provided with weekly email drips on best practices relevant to TransAlta’s current interests. In addition, Blue Ocean Brain was also engaged to provide 200 leaders with access to their learning library which contains articles, videos, knowledge checks and leadership briefs.

In addition, we extended our partnership with BetterUp, a consultancy providing professional coaching, to provide 1:1 coaching for over 50 leaders. 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. Since our partnership with BetterUp began in October 2019, our leaders have participated in over 640 coaching sessions over 390 hours.

In 2021, 89 corporate managers and supervisors were enrolled into Sentis’ Zero Incident Process ("ZIP") training. ZIP training reinforces our journey to create a psychologically safe environment in our workplace as it encourages personal accountability for ourselves and our work, improves decision-making processes, improves safety attitudes and creates a common language to have constructive conversations. In 2022, Corporate employees will be offered ZIP training.

Customer Relationship Training was designed in 2021 by entering a partnership with Vanry Inc. and tailoring the content with input from our managers in Commercial and Customer Relations. This 20-week series of workshops is currently being built and will be completed by 19 customer-facing leaders and employees in 2022. Topics include connecting with customers, listening for what matters, managing requests and building trust.

In 2021, we commenced the design of two leadership development programs – the Manager Development Program and Executive Development Program. These programs are designed to provide leaders with the skills and knowledge to lead in a changing world and the evolving nature with regards to the future of work. Both programs will be launched in 2022. We also launched leadership training on psychological safety, building and maintaining trust and cultural leadership in 2021. This training will be offered to all employees in 2022.

During 2021, TransAlta has had 28 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. Over $150,000 in wage subsidies were received in 2021.

In addition, TransAlta continued to participate in the Canada Alberta Job Grant, which reimburses employers two-thirds of the cost of approved external training. TransAlta is currently approved to receive over $44,000 to cover training costs from 2021.

Advancing Other Sustainability Factors
In the following sections we outline our progress across other material sustainability factors. The sections cover natural, manufactured, intellectual, and social and relationship capital management as per guidance from the International Integrated Reporting Framework.





TRANSALTA CORPORATION M99

Management’s Discussion and Analysis
Progressive Environmental Stewardship
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. Adjusted EBITDA from renewable energy generation in 2021 was $584 million (2020 — $353 million). Our revenue in 2021 from environmental attribute sales was $40 million (2020 — $25 million). In addition, in 2021 the sale of coal byproducts and waste-related recycling generated financial value in the range of $15 million to $20 million, which was the same as our range in 2020.

The following are key trends in our natural capital:

Year ended Dec. 31202120202019
Renewable energy adjusted EBITDA584353341
Environmental attribute sales revenue402528
GHG emissions (million tonnes CO2e)
12.516.420.6

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 during our clean electricity transition. Our environmental management processes support our corporate strategy of ceasing GHG-intensive coal operations. In 2026, our generation mix will be made up of natural gas and renewable energy only, with a goal of 70 per cent of EBITDA from renewables.

Environmental Policy
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. 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.

Environmental Management System
At TransAlta, we operate our facilities in line with best practices related to environmental management standards. Our environmental management processes are verified annually to ensure we continuously improve our environmental performance. Our knowledge of environmental management systems ("EMS") has matured since we aligned our processes in accordance with the internationally recognized ISO 14001 EMS standard. 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 practices include land use, water use and waste management.

In addition to our environmental management practices, 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 Company’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 Company. 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 Northern Development, Mines, Natural Resources and Forestry in Ontario; Ministry of Forests, Natural Resource Operations and Rural Development in British Columbia; 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; the Department of Agriculture, Water and the Environment in Australia; and the Clean Energy Regulator in Australia.






TRANSALTA CORPORATION M100

Management’s Discussion and Analysis
Environmental Performance
Our performance on managing environmental aspects, reducing our environmental impact and capitalizing on environmental initiatives includes the following:

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 we were an early adopter of wind energy and today operate over 1,900 MW of wind power, including battery storage. 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. In 2021, we agreed to provide renewable solar electricity supported with a battery energy storage system to BHP in Western Australia. For more information, please refer to Applied Technologies in the Technology Adoption and Innovation Focus 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 wholesale markets. TransAlta is a significant operator of natural gas electricity in Canada and Australia. In 2021, our thermal facilities in Alberta have been fully transitioned to 100 per cent natural gas operation, which generates nearly 50 per cent fewer CO2 emissions fueled compared to coal. In aggregate, TransAlta has retired 4,064 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to natural gas.

Coal Transition
As a result of our coal retirements and conversions to gas 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. 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 2021, we ceased coal-fired power generation in Canada. Our Centralia coal facility in the US will be retired by the end of 2025. Coal will be entirely eliminated from our operations by the end of 2025.

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.

The following table captures our energy use (millions of gigajoules). Energy use declined by 31 per cent in 2021 over 2020, primarily as a result of reduced coal use. Some values do not sum to the indicated total due to rounding. Zeros (0) indicate truncated values:

Year ended Dec. 31202120202019
Hydro000
Wind & Solar000
Gas118138162
Energy Transition74141184
Corporate and Energy Marketing000
Total energy use (million gigajoules)191279346





TRANSALTA CORPORATION M101

Management’s Discussion and Analysis
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 (completed in 2021) and Washington State (planned completion by the end of 2025). 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 90 per cent and NOx by 77 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 planned 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, and they all have been converted to gas in 2021. 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, Fort Saskatchewan and Ada gas facilities are our only facilities with air emissions within 49 kilometres of dense or urban environments.

Our total air emissions in 2021 decreased compared with 2020 levels. Specifically, NOx was reduced 29 per cent, particulate matter was reduced 80 per cent and SO2 was reduced 42 per cent over 2020 levels. Mercury emissions also decreased by 33 per cent over 2020 levels. Reductions in emissions were primarily due to shutdowns during coal-to-gas conversions and coal unit retirements.

The following table represents our material air emissions. Figures have been rounded to the nearest one thousand with the exception of particulate matter (rounded to the nearest one hundred) and mercury (rounded to the nearest ten):

Year ended Dec. 31202120202019
SO2 (tonnes)
7,00012,00016,000
NOx (tonnes)
15,00021,000 26,000 
Particulate matter (tonnes)7904,000 8,000
Mercury (kilograms)406060

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 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 2021, we withdrew approximately 240 million m3 (2020 - 230 million m3) and returned approximately 210 million m3 (2020 — 200 million m3) or 87 per cent. Overall, water consumption was approximately 30 million m3 (2020 — 40 million m3). Water consumption was lower in 2021 primarily due to shutdowns during coal-to-gas conversions and coal unit retirements.
Our water consumption reduction target is 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 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.





TRANSALTA CORPORATION M102

Management’s Discussion and Analysis
The following represents our total water consumption (million m3) over the last three years. Some values do not sum to the indicated total due to rounding. Figures below have been rounded to the nearest 10 million m3:

Year ended Dec. 31202120202019
Water withdrawal240230260
Water discharge210 200220
Total water consumption (million m3)
30 4040

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.

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 2021, we renewed for another five years our previous 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.

Our waste reduction target is 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 SDGs, specifically, "Goal 12: Responsible Consumption and Production."

In 2021, our operations generated approximately 515,000 tonnes equivalent of waste (2020 — 1.1 million tonnes). Of the total waste generated, 95 per cent was non-hazardous waste and 5 per cent was hazardous waste. In 2021, only 0.2 per cent of total waste generated was directed to landfill. Our 2020 waste data was revised in 2021 after we received final waste manifests as part of the reclamation project at our Mississauga facility. As a result, approximately 23,000 tonnes equivalent were added to Mississauga in multiple waste categories in 2020.






TRANSALTA CORPORATION M103

Management’s Discussion and Analysis
The following represents our total waste production over the last three years. Figures have been rounded to the nearest one thousand:

Year ended Dec. 31202120202019
Total waste generation (tonnes equivalent)515,000 1,135,000 1,533,000 
Waste to landfill (tonne eq.)1,000 11,000 1,000 
Waste recycled (tonne eq.)31,000 31,000 6,000 
Waste reuse (tonne eq.)176,000 533,000 746,000 
% of total waste to landfill0.2 1 0.07 
% of total waste: hazardous5 2 1 
% hazardous waste to landfill0.9 0.4 0.6 

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 ceased producing fly ash waste in Canada at the end of 2021 and will no longer produce it past the end of 2025 in the US. The Company 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.
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.

Overseeing biodiversity-related issues
TransAlta's GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of environmental regulations, public policy changes and the development of strategies, policies and practices for the environment. For further information, please refer to the Sustainability Governance section of this MD&A.

Assessing biodiversity impacts of our value chain
We consider the biodiversity impact at all of our existing operations (a greater focus has been 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 health. Details on how we asses biodiversity impacts of our value chain are presented in the sections below.

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 strategies 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 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.





TRANSALTA CORPORATION M104

Management’s Discussion and Analysis
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 operations, in 2021 we continued with our 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 with facility approvals. We continue to work toward 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 verification 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.

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.

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. Reclamation work continued on the Centralia mine in 2021, including the planting of 23,330 trees.

Our Highvale mine in Alberta ceased operations on Dec. 31, 2021, as part of our target to discontinue coal-fired power generation in Canada at the end of 2021. The mine reclamation has been progressively executed as part of our regulatory approvals, and our target is to have it fully reclaimed by 2046. Approximately 26,000 trees were planted in 2021 at our Highvale mine. In 2021, our reclamation team obtained regulatory approval for our interim reclamation plans, until submission of final reclamation plan in 2022. The updated plans align with community priorities for the reclaimed land. 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. 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.





TRANSALTA CORPORATION M105

Management’s Discussion and Analysis
Environmental Incidents and Spills
Minimizing our impact on the environment supports healthy ecosystems and mitigates our environmental compliance risk and reputational risk. We maintain corporate incident management procedures, as part of our Total Safety Management System, for appropriate initial response, investigation and lessons learned to minimize environmental incidents. 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 2021, we recorded two regulatory non-compliance environmental incidents (2020 – two incidents). One incident occurred at our Sarnia cogeneration facility and was a wastewater discharge exceedance from our neutralization sump during water treatment. The second incident was related to regulatory compliance at our Centralia facility that resulted in an environmental permit exceedance when a worker opened the incorrect fan breaker. Both incidents had negligible environmental impacts, but the Centralia incident resulted in one enforcement action and a US$3,100 fine from the regulator.

Regulatory non-compliance environmental incidents follow:
Year ended Dec. 31202120202019
Regulatory non-compliance environmental incidents226

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 immediate response to all environmental spills to ensure assessment, containment and recovery of spilled materials result in minimal impact to the environment.

The estimated volume of spills in 2021 was 6 m3 (2020 — 4 m3). Spill volumes in 2021 were higher due to one environmental incident recorded at our Centralia facility. The incident involved the release of mineral oil due to the failure of a phase generator step-up transformer. Spill response and control efforts were initiated immediately following the incident and environmental impacts were negligible and minimized due to the efficient response.

Significant environmental incidents follow:
Year ended Dec. 31202120202019
Significant environmental incidents063

There is a potential that ash ponds associated with our remaining 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.

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.





TRANSALTA CORPORATION M106

Management’s Discussion and Analysis
Our generation facilities and their operations are exposed to potential damage and partial or complete loss resulting from environmental disasters (e.g., floods, strong winds, wildfires, earthquakes, tornados and cyclones), 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. 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.

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

Please refer to the Governance and Risk Management section of this MD&A for further discussion on weather-related risks.

Reliable, Low-Cost and Sustainable Energy Production
TransAlta’s goal is to be a leading customer-centred clean electricity company, one that is committed to a sustainable future. Our strategy is focused on meeting our customers' need for clean, low-cost and reliable electricity, operational excellence and continual improvement in everything that we do, which is a core ethos of our company. This section covers manufactured, intellectual, and social and relationship capital management as per guidance from the International Integrated Reporting Framework.

Brand Recognition
Our business resilience is enhanced by a purpose-based, long-term and sustainable business strategy: growth in renewable electricity, optimization of our existing natural gas generation, and a commitment to sustainability. TransAlta has operated power-generation assets for over 110 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.

Diversified Knowledge
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 experience and acumen of our employees enhances our value creation. Our experience in developing and operating power-generation technologies extends to over 110 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 TypeOperating Experience (years)
Hydro110
Natural Gas71
Coal71
Wind19
Solar6

For further details, please refer to Customers in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A.






TRANSALTA CORPORATION M107

Management’s Discussion and Analysis
Grid Resiliency
As a large electricity generator, TransAlta works diligently to ensure the power we provide our customers is reliable, affordable and has low environmental impact. We provide decentralized and customized power solutions to industrial customers. In 2021, TransAlta agreed to build the Northern Goldfields Solar Project in Western Australia to provide renewable solar electricity supported with a battery energy storage system to the Goldfields-based operations of BHP. We also supply power to centralized power systems and own and operate transmission grid infrastructure in Alberta that addresses system reliability needs.

In all jurisdictions where we operate, we work closely with the system operators to ensure overall supply adequacy and reliability of the grid. 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. We are also committed to ensuring strong compliance with North American Electric Reliability Corporation standards and Alberta Reliability Standards for the power plant and transmission infrastructure that we own and operate.

As a Company, we are keenly focused on deploying clean power generation and new technology solutions to meet the emerging and future needs of the electric system that we operate in. For example, in Alberta, we brought online the first battery storage project, called WindCharger, in 2020 that is co-located with our Summerview II wind facility to create an emissions-free, peaking resource. This resource is participating in the AESO’s pilot fast frequency response initiative to support intertie operations. Beyond the fast frequency response initiative, WindCharger introduces a resource with a response time that is unmatched by existing generation technologies and can be operated with a high level of reliability to support the growing need for inertial response and resiliency to support a decarbonized grid with a supply mix made up of intermittent renewable resources.

For more information on technologies to support grid resiliency, please refer to Applied Technologies in the Technology Adoption and Innovation Focus section of this MD&A. For more guidance on cyberattacks, please refer to Public Health and Safety in the Engaging with Our Stakeholders to Create Positive Relationships section of this MD&A. For more information on extreme weather events and natural disasters, please refer to Weather in the Progressive Environmental Stewardship section of this MD&A.





TRANSALTA CORPORATION M108

Management’s Discussion and Analysis
Technology Adoption and Innovation Focus
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.

Idea Generation and Project Management
Our Greenlight program continues to be a driving force behind the strong culture of idea generation and problem solving at TransAlta. Led by our Transformation Office, the program emphasizes bottom-up innovation, which means business improvement ideas are generated by employees. These ideas are developed and advanced into business cases, adhering to best practices of project management, to ensure successful implementation of the improvement opportunity. From the initial ideation, to development and delivery, this process is driven entirely by employees, with support from management and the Transformation Office.

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 2021, we delivered seven sessions on topics such as artificial intelligence, behaviours for achieving success, frontline and corporate worker apps, hydrogen, mobile robots, robotic inspections for boiler and piping systems, and strategic foresight. For further details on how we invest in our workforce, please refer to Talent and Employee Development in the Building a Diverse and Inclusive Workforce section of this MD&A.

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. In 2021, our Sundance Unit 5 facility was retired, and Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 were converted to natural gas. This means TransAlta’s thermal facilities in Alberta have been fully transitioned to 100 per cent natural gas operation. In aggregate, the Company has retired 4,064 MW of coal-fired generation capacity since 2018 while converting 1,659 MW to cleaner-burning natural gas. Overall, the converted units generate nearly 50 per cent fewer CO2 emissions fueled by natural gas compared to coal. Repurposing the facilities rather than decommissioning them supports the concept of reuse and aligns with the UN SDGs, specifically "Goal 9: Industry, Innovation and Infrastructure." The completed conversions and the closure of the Highvale coal mine also contribute to the goals of the Powering Past Coal Alliance, which TransAlta joined at COP26.

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. As we balance growth with decarbonization, we continue to seek solutions to innovate and create value for investors, society and the environment.

In early 2021, TransAlta entered into a long-term PPA with Pembina for the offtake of 100 MW from our proposed 130 MW Garden Plain wind project, to be located in Alberta. The project began in 2021, with a target commercial operation date in the second half of 2022. In late 2021, TransAlta entered into two long-term PPAs for the offtake of 100 per cent of the generation from its 300 MW White Rock Wind Projects located in Oklahoma. Contracting the renewable electricity and environmental attributes to an outstanding new customer with an AA credit rating from S&P Global Ratings enables TransAlta to move into the construction phase expected to begin in late 2022 with a target commercial operation date in the second half of 2023. The delivery of low-cost, reliable and clean energy from Garden Plain and White Rock supports our customers' sustainability goals and represents another step towards executing our growth plan of delivering 2 GW of capacity by 2025, which was announced in September 2021.

TransAlta is actively advancing its development pipeline, which currently consists of 800 MW in the US, up to 2 GW in Canada and 270 MW in Australia. In 2021, TransAlta acquired a 122 MW portfolio of operating solar sites located in North Carolina, which will represent a significant expansion of our solar generation. We intend to further expand our solar generation by actively pursuing solar opportunities in the US and Australian markets. The Company is also focused on pursuing hybrid integrated power solutions with customers.





TRANSALTA CORPORATION M109

Management’s Discussion and Analysis
We continue to invest in battery storage. In 2021, TransAlta agreed to provide renewable solar electricity supported with a battery energy storage system to the Goldfields-based operations of BHP through the construction of the Northern Goldfields Solar Project in Western Australia. The project consists of the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm and 10 MW/5 MWh Leinster Battery Energy Storage System and interconnecting transmission infrastructure, all of which will be integrated into TransAlta’s 169 MW Southern Cross Energy North remote network. The network and new generation will support BHP to meet its emissions reduction targets and to deliver lower carbon, sustainable nickel to its customers. The Northern Goldfields Solar Project is expected to reduce BHP’s scope 2 electricity GHG emissions from its Leinster and Mount Keith operations by 540,000 tonnes of CO2e over the first 10 years of operation. Construction of the project commenced in early 2022 and commercial operations are targeted in late 2022.

Our teams continuously explore the use of applied or new technologies such as hydrogen and CCUS to find solutions and to expand or adapt our fleet. This helps protect our shareholder value and maintain delivery of reliable and affordable electricity to our costumers. 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.

Asset Analytics and Optimization
TransAlta's Asset Analytics and Optimization (“AAO”) team, formerly the Operations Diagnostic Centre, was founded in 2008. This team monitors coal-fired steam, gas-fired steam, simple-cycle, combined-cycle/cogeneration and wind-generating assets across Canada, the US and Australia. A centralized team of engineers and operations specialists remotely monitors our power facilities for emerging equipment reliability and performance issues.

AAO staff are trained in the development and use of specialized equipment monitoring and performance assessment software and they apply their experience to power facility operations. If an issue is detected, the AAO will initially assess and then notify facility operations of their findings to support investigation and remedy of the issue before there is an impact to operations. This support is critical for reliability and performance of our operations. By way of example, if a wind turbine starts to show very early signs of equipment change 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 AAO are focused on early identification of equipment issues based on longer-term trend analysis and complements day-to-day facility operations.

The AAO team also performs production reporting functions for the coal-fired steam, gas-fired steam, simple-cycle, combined-cycle/cogeneration and wind-generating assets, and are actively engaged in projects to improve this reporting.

Data and Innovation
TransAlta created the Data and Innovation team in 2019 to modernize its data infrastructure to take advantage of new opportunities in analytics and data science. The Data and 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 2021, the Data and Innovation team worked with partners across the business to create new decision support tools and processes that improve our financial position and return capacity to our people. A few of the highlights from this work include:

▪GenOS is a digital platform that provides near real-time performance awareness and operational decision support for our Generation fleet. By packaging the analytics and data science models of our operational data into a central platform, we are able to intuitively deliver insights to the Operations teams that drive real revenue increases and a reduction in costs. Built in-house, we have focused on onboarding our Wind and Solar fleet and have begun work with the Gas and Hydro teams.
▪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. The 2021 cohort worked on 11 data science use cases including building an energy market peak prediction model for our Trading team and a river flow forecasting model for our Hydro operations.





TRANSALTA CORPORATION M110

Management’s Discussion and Analysis
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 GSSC of the Board. The GSSC assists the Board in fulfilling its oversight responsibilities with respect to the Company’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environment, health and safety, and social well-being, including human rights, working conditions and responsible sourcing.

The following policies help govern sustainability at TransAlta, and are publicly available in the Governance section of the Investor Centre on our website:
▪Corporate Code of Conduct
▪Supplier Code of Conduct
▪Whistleblower Policy
▪Total Safety Management Policy
▪Human Rights and Discrimination Policy
▪Indigenous Relations Policy
▪Board and Workforce Diversity Policy, and Diversity and Inclusion Pledge

Our sustainability memberships include key sustainability organizations and working groups such as the EXCEL Partnership, the Canadian Business for Social Responsibility and the Canadian Electricity Association Sustainable Electricity Steering Committee, which all provide validation and support of our sustainability strategy and practices.

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

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 Company; and
▪Energy Trading Code of Conduct, which applies to all of our employees engaged in energy marketing.
 




TRANSALTA CORPORATION M111

Management’s Discussion and Analysis
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 Company and ensures that the Company 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 Company’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 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 ERM reporting.

The GSSC is responsible for developing and recommending to the Board a set of corporate governance principles applicable to the Company 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 Company’s monitoring of climate change, environmental, health and safety regulations, public policy changes and the development of strategies, policies and practices for climate change, environmental, health and safety, and social well-being, including human rights, working conditions and responsible sourcing. The GSSC also receives an annual report on the annual codes of conduct certification process. For further information on the Board's oversight of climate-related factors, please refer to the Climate Change Governance in Environmental, Social and Governance ("ESG") section of this MD&A.
 
In regards to overseeing and seeking to ensure that the Company consistently achieves strong environment, health and safety (“EH&S”) performance, the GSSC undertakes a number of actions that include: i) receiving regular reports from management regarding environmental compliance, trends and TransAlta’s responses; ii) 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; iii) assessing the impact of the GHG policies implementation and other legislative initiatives on the Company’s business; iv) reviewing with management the EH&S policies of the Company; v) reviewing with management the health and safety practices implemented within the Company, as well as the evaluation and training processes put in place to address problem areas; vi) discussing with management ways to improve the EH&S processes and practices; and vii) reviewing the effectiveness of our response to EH&S issues and any new initiatives put in place to further improve the Company’s EH&S culture.
 
The HRC is empowered by the Board to review and approve key compensation and human resources policies of the Company that are intended to attract, recruit, retain and motivate employees of the Company. 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.





TRANSALTA CORPORATION M112

Management’s Discussion and Analysis
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 Company's strategic plans. The IPC provides assistance to the Board in fulfilling its oversight responsibilities with respect to broadly reviewing and monitoring project management and control processes, financial profile, capital costs, procurement practices, and project schedules in a more in-depth manner than time permits during regularly scheduled Board meetings.

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 a Management committee chaired by our Senior Vice President, M&A, Strategy and Treasurer and is also comprised of the CEO, Executive Vice-President, Finance & Trading and Chief Financial Officer, Chief Operating 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 reviewing the operating, maintenance, safety and environmental aspects of TransAlta's Alberta Hydro Assets and, following that review, providing expert advice and recommendations to TransAlta’s hydro operational team. The Hydro Operating 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: i) Multilateral Instrument 52-109 — Certification of Disclosure in Issuers’ Annual and Interim Filings; ii) National Instrument 52-110 — Audit Committees; iii) National Policy 58-201 — Corporate Governance Guidelines; and iv) 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.

Global Pandemic
We have adopted a number of risk mitigation measures in response to the COVID-19 pandemic. The Board and management is monitoring the development of the outbreak and are continually assessing its impact on the Company's operations, supply chains and customers, as well as, more generally, to the business and affairs of the Company. Potential impacts of the pandemic on the business and affairs of the Company 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.





TRANSALTA CORPORATION M113

Management’s Discussion and Analysis
To manage the risks resulting from COVID-19, we continue to take a number of steps in furtherance of the Company's business continuity efforts:

Management Responses
▪Regularly communicated with the Board and employees in regard to the Company's response to COVID-19;
▪Maintained and updated COVID-19 safety protocols, including a back-to-office and site strategy, and a remote work strategy that will remain in place until the pandemic becomes an endemic; and
▪Developed leadership plans, including contingent authorities.

Policy Changes
▪We continue to align all non-essential travel and quarantine requirements with local jurisdictional guidance for all TransAlta employees and contractors for all jurisdictions in which we operate.

Employee Changes
▪Provided continued assurances to employees that their employment with TransAlta would not be impacted by the COVID-19 pandemic;
▪Implemented and have maintained health screening procedures, including questionnaires and temperature tests, enhanced cleaning measures and strict work protocols at the Company’s offices and facilities in accordance with our back-to-office and site strategy to ensure that employees remain safe;
▪Maintained 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 epidemiologists.

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.
 




TRANSALTA CORPORATION M114

Management’s Discussion and Analysis
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 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, 2021, associated with our proprietary commodity risk management activities was $2 million (2020 — $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. Further information on the Company's risk factors can be found in the Risk Factors section of the AIF, which risk factors are hereby incorporated by reference. and 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 Company means such an effect on the Company 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 2021. 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.
 




TRANSALTA CORPORATION M115

Management’s Discussion and Analysis
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:
FactorIncrease or
decrease (%)		Approximate impact
on net earnings
Availability/production1 $12 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 Company. 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 production 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.
 
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.






TRANSALTA CORPORATION M116

Management’s Discussion and Analysis
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 2021, we had approximately 78 per cent (2020 – 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 2021, 70 per cent (2020 – 89 per cent) of our gas consumption used in generating electricity was contractually fixed or passed through to our customers and 80 per cent (2020 – 78 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.

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 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: 
▪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 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;
▪Monitoring the financial viability of Centralia suppliers; and
▪Hedging diesel exposure in mining and transportation costs.
 





TRANSALTA CORPORATION M117

Management’s Discussion and Analysis
Natural Gas Supply and Price Risk
Having sufficient natural gas and natural gas transportation services available at our Gas facilities is essential to maintaining the reliability and availability of those facilities. Ensuring adequate pipeline transportation service and natural gas supply for our Gas 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; and
▪Monitoring pipeline maintenance schedules and transportation availability.

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, Australia 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 abatement 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 environmental health and safety management system audits to assess conformance to our Total Safety Management System, which is designed to continuously improve performance;
▪Committing significant experienced resources to work with regulators in Canada, Australia 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 carbon emissions reduction offsets or credits;
▪Investing in renewable energy projects, such as wind, solar and hydro generation, and storage technologies; 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.





TRANSALTA CORPORATION M118

Management’s Discussion and Analysis
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 fulfill 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.
 
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, 2020. We had no material counterparty losses in 2021. 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, 2021:
Investment grade
 (%)
Non-investment grade
 (%)
Total
 (%)
Total
amount
Trade and other receivables(1,2)
89 11 100 651 
Long-term finance lease receivables100 — 100 185 
Risk management assets(1)
86 14 100 707 
Total   1,543 
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. 
(2) Includes loan receivable where 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 $37 million (2020 – $22 million).

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.





TRANSALTA CORPORATION M119

Management’s Discussion and Analysis
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, cash flows 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 senior 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 and Australian exposure, net of debt service and sustaining capital expenditures are managed with 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:
FactorIncrease or decreaseApproximate impact
on net earnings
Exchange rate$0.03$12 million
 
Liquidity Risk
 Liquidity risk relates to our ability to access capital to be used to fund capital projects, refinance debt and pay liabilities, engage in trading and hedging activities 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. 
 
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, 2021, we have liquidity of $2.2 billion comprised of amounts not drawn under our committed credit facilities and cash on hand that is available to draw on for projects in 2022.
 
We manage liquidity risk by:
▪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;
▪Maintaining sufficient undrawn committed credit lines to support potential liquidity requirements; and
▪Monitoring trading positions.
 
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;
▪Monitoring the mixture of floating and fixed rate debt and adjusting to ensure efficiency; and
▪Opportunistically hedging for known debt issuances.
 




TRANSALTA CORPORATION M120

Management’s Discussion and Analysis
At Dec. 31, 2021, approximately 3 per cent (2020 – 7 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:
FactorIncrease or
decrease (%)		Approximate impact
on net earnings
Interest rate30 bpsless than $1 million before tax
 
IBOR reform could impact interest rate risk with respect to the Company'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.

Outstanding US dollar forward starting interest rate swaps should not be affected as the three-month USD LIBOR will continue to be published until June 30, 2023. These are expected to to settle in 2022.

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 2021, 33 per cent (2020 – 46 per cent) of our labour force was covered by 11 (2020 – 10) collective bargaining agreements. The increase in the number of collective agreements is the result of splitting one collective agreement into two collective agreements. The decrease in the percentage of our unionized workforce is the result of the coal-to-gas transition and subsequent retirement of Keephills Unit 1. In 2021, one (2020 – 2) agreement was renegotiated. We anticipate the successful negotiation of seven collective agreements in 2022.




TRANSALTA CORPORATION M121

Management’s Discussion and Analysis
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. 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.
 




TRANSALTA CORPORATION M122

Management’s Discussion and Analysis
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 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;
▪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.

Growth Risk
Our business plan includes growth through identifying suitable acquisitions or contracted new build opportunities. There can be no assurance that we will be able to identify attractive growth opportunities in the future, that we will be able to complete growth opportunities that increase the amount of cash available for distribution, or that growth opportunities will be successfully integrated into our existing operations. The successful execution of the growth strategy requires careful timing and business judgment, as well as the resources to complete the due diligence and evaluation of such opportunities and to acquire and successfully integrate those assets into our business.
 





TRANSALTA CORPORATION M123

Management’s Discussion and Analysis
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 constantly evolving. Our tax filings are subject to audit by taxation authorities. Management believes that it has adequately provided for income taxes as required by the Income Tax Act and IFRS, based on all information currently available.
 
The Company 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 Company.

The sensitivity of changes in income tax rates upon our net earnings is shown below:
FactorIncrease or
decrease (%)		Approximate impact
on net earnings
Tax rate1 
$6 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. During renewal of the insurance policies on Dec. 31, 2021, a coverage restriction was added for losses resulting from a foundation failure at the Kent Hills 1 and 2 wind facilities only. There were no other significant changes to our insurance coverage during renewal of the insurance policies on Dec. 31, 2021. 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.





TRANSALTA CORPORATION M124

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, 2021, 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 Company’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.

In accordance with the provisions of NI 52-109 and consistent with U.S. Securities and Exchange Commission guidance, the scope of the evaluation did not include internal controls over financial reporting of North Carolina Solar, which the Company acquired on Nov. 5, 2021. North Carolina Solar was excluded from management's evaluation of the effectiveness of the Company's internal control over financial reporting as at Dec. 31, 2021, due to the proximity of the acquisition to year-end. Further details related to the acquisition are disclosed in Note 4 to the Company's Consolidated Financial Statements for the year ended Dec. 31, 2021. Included in the 2021 Consolidated Financial Statements of TransAlta for North Carolina Solar is 2 per cent and 5 per cent of the Company's total and net assets, respectively, as at Dec. 31, 2021.

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, 2021, the end of the period covered by this MD&A, our ICFR and DC&P were effective.





TRANSALTA CORPORATION M125
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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 ("TransAlta") 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 fulfils 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.
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John KousiniorisTodd Stack
President and Chief Executive OfficerExecutive Vice President, Finance and
Chief Financial Officer
February 23, 2022




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.
In accordance with the provisions of NI 52-109 and consistent with U.S. Securities and Exchange Commission guidance, the scope of the evaluation did not include internal controls over financial reporting of North Carolina Solar, which the Company acquired on Nov. 5, 2021. North Carolina Solar was excluded from management's evaluation of the effectiveness of the Company's internal control over financial reporting as at Dec. 31, 2021, due to the proximity of the acquisition to year-end. Further details related to the acquisition are disclosed in Note 4 to the Company's Consolidated Financial Statements for the year ended Dec. 31, 2021. Included in the 2021 Consolidated Financial Statements of TransAlta for North Carolina Solar is 2 per cent and 5 per cent of the Company's total and net assets, respectively, as at Dec. 31, 2021.

TransAlta proportionately consolidates the joint operations of the Sheerness Generating Station and equity accounts for our investment in SP Skookumchuck Investment, 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 2021 Consolidated Financial Statements of TransAlta for joint operations and equity accounted investments are 4 per cent and 10 per cent of the Company's total and net assets, respectively, as of Dec. 31, 2021, and 8 per cent of the Company's revenues for the year then ended.

TRANSALTA CORPORATION F2

Consolidated Financial Statements

Changes in Internal Controls over Financial Reporting
The Company's internal controls over financial reporting commencing Nov. 5, 2021, include controls designed to result in complete and accurate consolidation of North Carolina Solar's results. Other than the North Carolina Solar acquisition, there has been no change in the Company's internal control over financial reporting that occurred during the year covered by this Annual Report that has materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Management has assessed the effectiveness of TransAlta’s internal control over financial reporting, as at Dec. 31, 2021, 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, 2021, 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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John KousiniorisTodd Stack
President and Chief Executive OfficerExecutive Vice President, Finance and
Chief Financial Officer
February 23, 2022
TRANSALTA CORPORATION F3

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of 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, 2021, 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 (the “Company”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, 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 of the Sheerness Generating Station and equity accounted joint venture of SP Skookumchuck Investment, LLC which are included in the 2021 consolidated financial statements of the Company and constituted 4% and 10% of total and net assets, respectively, as of December 31, 2021, and 8% of revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of the joint operations of the Sheerness Generating Station and equity accounted joint venture of SP Skookumchuck Investment, LLC.

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 North Carolina Solar, which is included in the 2021 consolidated financial statements of the Company and constituted 2% and 5% of total and net assets, respectively, as of December 31, 2021. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of North Carolina Solar.

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, 2021 and 2020, and the related consolidated statements of earnings (loss), comprehensive earnings (loss), changes in equity and cash flows for each of the three years in the period ended December 31, 2021, and the related notes and our report dated February 23, 2022 expressed an unqualified opinion thereon.

Basis for Opinion
The Company’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 the Company’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 the Company in accordance with the U.S. 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.

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 company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the consolidated 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
February 23, 2022
TRANSALTA CORPORATION F4

Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of TransAlta Corporation

Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated statements of financial position of TransAlta Corporation (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of earnings (loss), comprehensive earnings (loss), changes in equity and cash flows, for each of the three years in the period ended December 31, 2021, 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 the Company at December 31, 2021 and 2020, and the financial performance and its cash flows for each of the three years in the period ended December 31, 2021, 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”), the Company’s internal control over financial reporting as of December 31, 2021, 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 February 23, 2022 expressed an unqualified opinion thereon.

Basis for Opinion
These consolidated financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘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 the Company in accordance with the U.S. 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.
Valuation of Long-Lived Assets related to certain cash generating units (“CGU”s) within the Wind and Solar segment and Goodwill related to the Wind and Solar segment
Description of the Matter
As disclosed in notes 2(G), 2(H), 2(P)(I), 7, 18 and 21 of the consolidated financial statements, the Company owns significant Wind and Solar generation assets and has recognized goodwill from historical acquisitions which must be tested for impairment at least annually or when indicators are present. The carrying value of Goodwill related to the Wind and Solar segment was $175 million and the carrying value of long-lived assets in the Wind and Solar segment consisted of property, plant & equipment of $2,304 million, right-of-use assets of $64 million and intangible assets of $147 million as at December 31, 2021.

Determining the recoverable amounts for the Wind and Solar segment for the purposes of the goodwill impairment test and of certain CGUs in the Wind and Solar segment with indicators of impairment (“Wind and Solar CGUs”) for the asset impairment test was identified as a critical audit matter due to the significant estimation uncertainty and judgment 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 generation profiles, commodity prices, cost estimates, and determining the appropriate discount rate.




TRANSALTA CORPORATION F5

Consolidated Financial Statements

How We Addressed the Matter in Our Audit
We obtained an understanding of management’s process for estimating the recoverable amount of the Wind and Solar segment and the Wind and Solar CGUs. We evaluated the design and tested the operating effectiveness of controls over the Company’s processes to determine the recoverable amount. Our audit procedures to test the Company’s recoverable amount of the Wind and Solar segment and the Wind and Solar CGUs with indicators of impairment 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 amount. We evaluated the Company’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(P)(IV), 15 and 25 of the consolidated financial statements, the Company 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, 2021 the fair value of the Company’s derivative financial instruments classified as level III was $159 million net risk management assets.

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 Company’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
February 23, 2022





TRANSALTA CORPORATION F6

Consolidated Financial Statements


Consolidated Statements of Earnings (Loss)
 
Year ended Dec. 31 (in millions of Canadian dollars except where noted)
202120202019
Revenues (Note 5)2,721 2,101 2,347 
Fuel and purchased power (Note 6)1,054 805 881 
Carbon compliance178 163 205 
Gross margin1,489 1,133 1,261 
Operations, maintenance and administration (Note 6)511 472 475 
Depreciation and amortization529 654 590 
Asset impairment charge (Note 7)648 84 25 
Gain on termination of Keephills 3 coal rights contract (Note 18)— — (88)
Taxes, other than income taxes32 33 29 
Termination of Sundance B and C PPAs — — (56)
Net other operating loss (income) (Note 9)8 (11)(49)
Operating income (loss)(239)(99)335 
Equity income (Note 10)
9 1 — 
Finance lease income25 7 6 
Net interest expense (Note 11)(245)(238)(179)
Foreign exchange gain (loss)16 17 (15)
Gain on sale of assets and other (Note 4 and 18)54 9 46 
Earnings (loss) before income taxes(380)(303)193 
Income tax expense (recovery) (Note 12)45 (50)17 
Net earnings (loss)(425)(253)176 
Net earnings (loss) attributable to:   
TransAlta shareholders(537)(287)82 
Non-controlling interests (Note 13)112 34 94 
 (425)(253)176 
Net earnings (loss) attributable to TransAlta shareholders(537)(287)82 
Preferred share dividends (Note 28)39 49 30 
Net earnings (loss) attributable to common shareholders(576)(336)52 
Weighted average number of common shares outstanding in the year (millions)
271 275 283 
Net earnings (loss) per share attributable to common shareholders, basic and diluted
   (Note 27)
(2.13)(1.22)0.18 
 
See accompanying notes.
 





TRANSALTA CORPORATION F7

Consolidated Financial Statements

Consolidated Statements of Comprehensive Earnings (Loss)
 
Year ended Dec. 31 (in millions of Canadian dollars)
202120202019
Net earnings (loss)(425)(253)176 
Other comprehensive loss   
Net actuarial gains (loss) on defined benefit plans, net of tax(1)
37 (11)(26)
 Losses on derivatives designated as cash flow hedges, net of tax— (1)— 
Total items that will not be reclassified subsequently to net earnings37 (12)(26)
Losses on translating net assets of foreign operations, net of tax(14)(11)(59)
Gains on financial instruments designated as hedges of foreign operations,
  net of tax		— 11 21 
Gains (losses) on derivatives designated as cash flow hedges, net of tax(2)
(200)20 61 
Reclassification of gains on derivatives designated as cash flow hedges to net earnings,
  net of tax(3)
(8)(110)(42)
Total items that will be reclassified subsequently to net earnings(222)(90)(19)
Other comprehensive loss(185)(102)(45)
Total comprehensive earnings (loss)(610)(355)131 
Total comprehensive earnings (loss) attributable to:   
TransAlta shareholders(693)(439)54 
Non-controlling interests (Note 13)83 84 77 
 (610)(355)131 
 (1) Net of income tax expense of $11 million for the year ended Dec. 31, 2021 (2020 — $3 million recovery, 2019 — $7 million recovery).
(2) Net of income tax recovery of $55 million for the year ended Dec. 31, 2021 (2020 —$8 million expense, 2019 — $16 million expense).
(3) Net of reclassification of income tax recovery of $2 million for the year ended Dec. 31, 2021 (2020 —$31 million recovery,  2019 — $10 million recovery).

See accompanying notes.





TRANSALTA CORPORATION F8

Consolidated Financial Statements


Consolidated Statements of Financial Position

As at Dec. 31 (in millions of Canadian dollars)
20212020
Cash and cash equivalents947 703 
Restricted cash (Note 24)70 71 
Trade and other receivables (Note 14)651 583 
Prepaid expenses29 31 
Risk management assets (Note 15 and 16)308 171 
Inventory (Note 17)167 238 
Assets held for sale (Note 4 and 18)25 105 
 2,197 1,902 
Investments (Note 10)
105 100 
Long-term portion of finance lease receivables (Note 8)185 228 
Risk management assets (Note 15 and 16)399 521 
Property, plant and equipment (Note 18)
Cost13,389 13,398 
Accumulated depreciation(8,069)(7,576)
 5,320 5,822 
Right-of-use assets (Note 19)95 141 
Intangible assets (Note 20)256 313 
Goodwill (Note 21)463 463 
Deferred income tax assets (Note 12)64 51 
Other assets (Note 22)142 206 
Total assets9,226 9,747 
Accounts payable and accrued liabilities689 599 
Current portion of decommissioning and other provisions (Note 23)48 59 
Risk management liabilities (Note 15 and 16)261 94 
Current portion of contract liabilities (Note 5)19 1 
Income taxes payable8 18 
Dividends payable (Note 27 and 28)62 59 
Current portion of long-term debt and lease liabilities (Note 24)844 105 
1,931 935 
Credit facilities, long-term debt and lease liabilities (Note 24)2,423 3,256 
Exchangeable securities (Note 25)
735 730 
Decommissioning and other provisions (Note 23)779 614 
Deferred income tax liabilities (Note 12)354 396 
Risk management liabilities (Note 15 and 16)145 68 
Contract liabilities (Note 5)13 14 
Defined benefit obligation and other long-term liabilities (Note 26)253 298 
Equity  
Common shares (Note 27)2,901 2,896 
Preferred shares (Note 28)942 942 
Contributed surplus46 38 
Deficit(2,453)(1,826)
Accumulated other comprehensive income (Note 29)146 302 
Equity attributable to shareholders1,582 2,352 
Non-controlling interests (Note 13)1,011 1,084 
Total equity2,593 3,436 
Total liabilities and equity9,226 9,747 
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, 20192,97894242(1,455)4542,9611,1014,062
Net earnings (loss)— — — (287)— (287)34 (253)
Other comprehensive earnings (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 earnings (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 (Note 13)
— — — 5 — 5 15 20 
Effect of share-based payment
  plans		(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 
Net earnings (loss)— — — (537)— (537)112 (425)
Other comprehensive earnings (loss):       
Net losses on translating net
  assets of foreign operations,
  net of hedges and tax		— — — — (14)(14)— (14)
Net gains (losses) on derivatives
  designated as cash flow hedges,
  net of tax		— — — — (208)(208)— (208)
Net actuarial gains on defined
   benefits plans, net of tax		— — — — 37 37 — 37 
Intercompany FVOCI investments— — — — 29 29 (29)— 
Total comprehensive earnings (loss)   (537)(156)(693)83 (610)
Common share dividends— — — (51)— (51)— (51)
Preferred share dividends— — — (39)— (39)— (39)
Effect of share-based payment
  plans (Note 30)
5 — 8 — — 13 — 13 
Distributions paid, and payable, to
  non-controlling interests		— — — — — — (156)(156)
Balance, Dec. 31, 2021
2,901 942 46 (2,453)146 1,582 1,011 2,593 
(1) Refer to Note 29 for details on components of, and changes in, accumulated other comprehensive earnings (loss).
 See accompanying notes.







TRANSALTA CORPORATION F10

Consolidated Financial Statements

Consolidated Statements of Cash Flows

Year ended Dec. 31 (in millions of Canadian dollars)
202120202019
Operating activities   
Net earnings (loss)(425)(253)176 
Depreciation and amortization (Note 18 and 37)719 798 709 
Net gain on sale of assets(54)(9)(45)
Accretion of provisions (Note 23)32 30 23 
Decommissioning and restoration costs settled (Note 23)(18)(18)(34)
Deferred income tax recovery (Note 12)(11)(85)(18)
Unrealized (gain) loss from risk management activities(34)42 (32)
Unrealized foreign exchange (gain) loss(24)1 13 
Provisions(41)9 13 
Asset impairment (Note 7)648 84 25 
Equity income, net of distributions from investments (Note 10)(5)(1)— 
Other non-cash items40 15 (102)
Cash flow from operations before changes in working capital827 613 728 
Change in non-cash operating working capital balances (Note 33)174 89 121 
Cash flow from operating activities1,001 702 849 
Investing activities   
Additions to property, plant and equipment (Note 18 and 37)(480)(486)(417)
Additions to intangible assets (Note 20 and 37)(9)(14)(14)
Restricted cash (Note 24)(1)(39)34 
Loan receivable (Note 22)(3)(5)(10)
Acquisitions, net of cash acquired (Note 4)(120)(32)(117)
Acquisition of investments (Note 10)— (102)— 
Investment in the Pioneer Pipeline— — (83)
Proceeds on sale of Pioneer Pipeline (Note 4)128 — — 
Proceeds on sale of property, plant and equipment39 6 13 
Realized gains (losses) on financial instruments(6)2 3 
Decrease in finance lease receivable41 17 24 
Other(16)(12)23 
Change in non-cash investing working capital balances(45)(22)32 
Cash flow used in investing activities(472)(687)(512)
Financing activities   
Net decrease in borrowings under credit facilities (Note 24 and 33)(114)(106)(119)
Repayment of long-term debt (Note 24 and 33)(92)(489)(96)
Issuance of long-term debt (Note 24)173 753 166 
Issuance of exchangeable securities (Note 25)— 400 350 
Dividends paid on common shares (Note 27)(48)(47)(45)
Dividends paid on preferred shares (Note 28)(39)(39)(40)
Repurchase of common shares under NCIB (Note 27)(4)(57)(68)
Proceeds on issuance of common shares8 — — 
Realized gains on financial instruments3 3 — 
Distributions paid to subsidiaries' non-controlling interests (Note 13)(156)(97)(106)
Decrease in lease liabilities (Note 24 and 33)(8)(25)(21)
Financing fees and other(4)(11)(35)
Change in non-cash financing working capital balances(1)(13)— 
Cash flow from (used in) financing activities(282)272 (14)
Cash flow from operating, investing, and financing activities247 287 323 
Effect of translation on foreign currency cash(3)5 (1)
Increase in cash and cash equivalents244 292 322 
Cash and cash equivalents, beginning of year703 411 89 
Cash and cash equivalents, end of year947 703 411 
Cash taxes paid57 36 35 
Cash interest paid220 201 185 
See accompanying notes.




TRANSALTA CORPORATION F11
Notes to Consolidated Financial Statements
 
(Tabular amounts in millions of Canadian dollars, except as otherwise noted)         

1. Corporate Information
A. Description of the Business
TransAlta Corporation (“TransAlta” or the “Company”) was incorporated under the Canada Business Corporations Act in March 1985. The Company became a public company in December 1992. Its head office is located in Calgary, Alberta.

I. Generation Segments
During the fourth quarter of 2021, the Company realigned its current operating segments to better reflect a change in how TransAlta’s President and Chief Executive Officer (the chief operating decision maker) ("CODM") reviews financial information in order to allocate resources and assess performance. The primary changes are the elimination of the Alberta Thermal and the Centralia segments, and the reorganization of the North American Gas and Australia Gas segments into a new "Gas" segment. The Alberta Thermal facilities that have been converted to gas have been included in the Gas segment. The remaining assets previously included in Alberta Thermal, including the mining assets and those facilities not converted to gas and the remaining Centralia unit, are included in a new "Energy Transition" segment. No changes were made to the Hydro and Wind and Solar segments. This change better aligns with the Company's long-term strategy and reflects its Clean Electricity Growth Plan.

The four generation segments of the Company are as follows: Hydro, Wind and Solar, Gas, and Energy Transition. Previously, the six generation segments were as follows: Hydro, Wind and Solar, North American Gas, Australian Gas, Alberta Thermal, and Centralia. The Company 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.

Comparative segmented results for 2020 and 2019 have been restated to align with the 2021 operating segments.

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. No change was made to the Energy Marketing segment.

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 Company’s central finance, legal, administrative, corporate development and investor relations functions. Activities and charges directly or reasonably attributable to other segments are allocated thereto. Since 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, 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 Feb. 23, 2022.

C. Basis of Consolidation 
The consolidated financial statements include the accounts of the Company and the subsidiaries that it controls. Control exists when the Company 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.





TRANSALTA CORPORATION F12
Notes to Consolidated Financial Statements
2. Material Accounting Policies
The Company has reviewed the accounting policies disclosed in accordance with the amendments to IAS 1 to disclose the material accounting policy information rather than significant accounting policies. The definition of material that management has used to judgmentally determine disclosure is that information is material if omitting it or misstating it could influence decisions users make on the basis of financial information.

A.Revenue Recognition 
I. Revenue from Contracts with Customers
The majority of the Company’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 Company 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 Company’s performance to date. The Company excludes amounts collected on behalf of third parties from revenue.

Performance Obligations
Each promised good or service is accounted for separately as a performance obligation if it is distinct. The Company’s contracts may contain more than one performance obligation.

Transaction Price
The Company 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 Company'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 Company expects to be entitled to in exchange for transferring the good or service. The Company 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.





TRANSALTA CORPORATION F13
Notes to Consolidated Financial Statements
Recognition
The nature, timing of recognition of satisfied performance obligations and payment terms for the Company’s goods and services are described below:

Good or serviceDescription
CapacityCapacity 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 the 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 powerThe 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 energyThermal 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 attributesEnvironmental 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 byproductsGeneration byproducts refers to the sale of byproducts from the use of coal in the Company’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 Company receives consideration before the performance obligations have been satisfied. A contract asset is recorded when the Company has rights to consideration for the completion of a performance obligation before it has invoiced the customer. The Company 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.

II. Revenue from Other Sources
Merchant Revenue
Revenues from non-contracted capacity (i.e., merchant) are comprised of energy payments, at market price, for each MWh produced and are recognized upon delivery.

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 Company 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. The Company also enters into contracts for differences and virtual Power Purchase Agreements ("PPA"). Contracts for differences is a financial contract whereby the Company receives a fixed price per MWh and pays the prevailing real-time energy market price per MWh. A virtual PPA is where the Company receives the difference between the fixed contract price per MWh and the settled market price. These arrangements are option-based derivatives and judgment is applied to determine if the contract meets the 'own use' exemption or if derivative treatment is required.





TRANSALTA CORPORATION F14
Notes to Consolidated Financial Statements
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 Company 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.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 Company’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 Company 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 Company 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 effective interest method to tax equity financings, the Company has made an accounting policy choice to recognize the impacts of the tax attributes in net interest expense.

The Company 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 Company 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.





TRANSALTA CORPORATION F15
Notes to Consolidated Financial Statements
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 Company 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 Company 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 Company 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 Company’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.

The Company 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 Company 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 other comprehensive earnings ("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 accumulated other comprehensive earnings ("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.




TRANSALTA CORPORATION F16
Notes to Consolidated Financial Statements
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.

C. Cash and Cash Equivalents
Cash and cash equivalents are comprised of cash and highly liquid investments with original maturities of three months or less.

D. Inventory
I. Fuel
The Company’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.

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 Company 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 Company 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 Company 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.

E. Property, Plant and Equipment
The Company’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.




TRANSALTA CORPORATION F17
Notes to Consolidated Financial Statements
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.

Estimated remaining useful lives of the components of depreciable assets, categorized by asset class, are as follows:
Hydro generation
2-51 years
Wind generation
2-30 years
Gas generation
2-36 years
Energy Transition
2-16 years
Capital spares and other
2-51 years

TransAlta capitalizes borrowing costs on capital invested in projects under construction. 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.

F. 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 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. 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, software and intangibles under development. Estimated remaining useful lives of intangible assets are as follows:
Software
2-7 years
Power sale contracts
1-19 years

G. Impairment of Tangible and Intangible Assets Excluding Goodwill
At the end of each reporting period, the Company 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 Company’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 Company 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.





TRANSALTA CORPORATION F18
Notes to Consolidated Financial Statements
The Company’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 cash-generating unit (“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 Company. 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.

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. 

H. 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 Company’s CGUs or groups of CGUs that are expected to benefit from the synergies of the business combination in which the goodwill arose. Accordingly, the Company performs its test for impairment, where the recoverable amount of the CGUs or groups of CGUs to which the goodwill relates is compared to its carrying amount for each operating segment. 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.

I. Income Taxes
The Company 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 Company 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. 

Cash taxes paid disclosed on the Consolidated Statements of Cash Flows includes income taxes and taxes paid related to the Part VI.1 tax in Canada for the period.





TRANSALTA CORPORATION F19
Notes to Consolidated Financial Statements
J. Employee Future Benefits
The Company 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.

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 Company’s defined benefit pension plans give rise to recording an additional liability, letters of credit provided by the Company 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.

K. Provisions
Provisions are recognized when the Company has a present obligation (legal or constructive) as a result of a past event, it is probable that the Company 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 Company 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 Company 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 Company determines the present value of the provision using the current discount rates that reflect the time value of money and associated risks. The Company 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(E)) 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 Company 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.

L. Leases 
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.




TRANSALTA CORPORATION F20
Notes to Consolidated Financial Statements
Lessee
The Company 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 Company is the lessee, and which are not exempt as short-term or low-value leases, the Company:
▪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 Company 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 Company'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 Company’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 Company is reasonably certain to exercise that option and periods covered by an option to terminate if the Company 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 Company expects to exercise the purchase option, the related right-of-use asset is depreciated over the useful life of the underlying asset.

The Company 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
PPAs and other long-term contracts may contain, or may be considered, leases where the fulfillment 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 Company 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 Company determines that the contractual provisions of a contract contain, or are, a lease and result in the Company 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 Company 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.




TRANSALTA CORPORATION F21
Notes to Consolidated Financial Statements
M. Non-Controlling Interests 
Non-controlling interests arise from business combinations in which the Company 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 Company determines on a transaction-by-transaction basis for which the measurement method is used. Non-controlling interests also arise from other contractual arrangements between the Company and other parties, whereby the other party has acquired an equity interest in a subsidiary, and the Company 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 earnings is attributed to the non-controlling interests even if this results in the non-controlling interests having a negative balance.

N. 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 Company'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 Company 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 Company 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 Company’s share of the joint venture’s net earnings or loss after the date of acquisition. The impact of transactions between the Company and joint ventures is eliminated based on the Company’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. 

O. 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.

The optional fair value concentration test is 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 Company may elect to treat the acquisition as an asset acquisition and not as a business combination.

P. 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 Company’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 Company’s financial position or performance. The key judgments and sources of estimation uncertainty are described below:




TRANSALTA CORPORATION F22
Notes to Consolidated Financial Statements
I. 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 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 Company evaluates the market design, transmission constraints and the contractual profile of each facility, as well as the Company’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 Company 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 2019 to 2021 is found in Notes 7, 18 and 21.

II. Leases
In determining whether the Company’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 Company 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 Company, to appropriately account for the agreement as either a finance or operating lease. These judgments can be significant and impact how the Company 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.





TRANSALTA CORPORATION F23
Notes to Consolidated Financial Statements
III. 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 Company 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 Company’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 Company’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 Company’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 Company’s tax policies.

IV. Financial Instruments and Derivatives
The Company’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 Company’s fair values are included in Level III because they are not traded on an active exchange or have terms that 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 Company’s estimates of pricing and production to allow the future transaction to be fulfiled.

When the Company enters into contracts to buy or sell non-financial items, such as certain commodities, and the contracts can be settled net in cash, the Company 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 Company'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 Company 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. The Company also enters into PPAs and contracts for differences and judgment is applied to determine if the contract meets the 'own use' exemption or if derivative treatment is required.

V. Project Development Costs
Project development 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 the Company, 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 or when there is uncertainty of timing of when the projects will proceed are charged to net earnings. 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 Company, in determining the amount to be capitalized. Information on the write-off of project development costs is disclosed in Note 7.

VI. Provisions for Decommissioning and Restoration Activities
TransAlta recognizes provisions for decommissioning and restoration obligations as outlined in Note 2(K) and Note 23. Initial decommissioning provisions, and subsequent changes thereto, are determined using the Company’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 2021 in respect of decommissioning and restoration provisions can be found in Notes 7 and 23.





TRANSALTA CORPORATION F24
Notes to Consolidated Financial Statements
VII. 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 18.

VIII. Employee Future Benefits
The Company 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.

IX. Other Provisions
Where necessary, the Company 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 Company’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 9 and 23 with respect to other provisions.

X. 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 Company also considers the historical production levels and operating conditions for its variable generating assets. The Company’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 Company 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.





TRANSALTA CORPORATION F25
Notes to Consolidated Financial Statements
XI. Classification of Joint Arrangements
Upon entering into a joint arrangement, the Company 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 Company 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.

XII. Significant Influence
Upon entering into an investment, the Company must classify it as either an investment as an associate or an investment under IFRS 9. In making this classification, the Company exercises judgment in evaluating whether the Company 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 Company 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 Company and investee, interchange of managerial personnel or providing essential technical information are considered when assessing if the Company has significant influence over an investee.

XIII. Change in Estimates
During the year ended Dec. 31, 2021, there were changes in estimates relating to defined benefit obligations and decommissioning and other provisions. Refer to Note 23 and 26 for further details. During the year ended Dec. 31, 2020, there were changes in estimates relating to the useful life of PP&E. Refer to Note 18 for further details.

3. Accounting Changes
A. Current Accounting Changes

I. Amendments to IAS 1 Presentation of Financial Statements: Material Accounting Policies
Effective for the 2021 annual financial statements, the Company early adopted amendments to IAS 1 Presentation of Financial Statements in advance of its mandatory effective date of Jan. 1, 2023, which requires entities to disclose their material accounting policy information rather than their significant accounting policies. The Company has updated the accounting policies disclosed in Note 2 based on its assessment of the amended standard.

II. Amendments to IAS 16 Property, Plant and Equipment: Proceeds before Intended Use
Effective Jan. 1, 2021, the Company early adopted amendments to IAS 16 Property, plant and equipment (“IAS 16 Amendments”) in advance of its mandatory effective date of Jan. 1, 2022. The Company adopted the IAS 16 Amendments retroactively. No cumulative effect of initially applying the guidance arose. The IAS 16 Amendments prohibit deducting from the cost of an item of property, plant and equipment any proceeds from selling items produced while bringing that asset to the location and condition necessary for it to be capable of operating in a manner intended by management. Instead, an entity recognizes the proceeds from selling such items, and the cost of producing those items, in profit or loss. No adjustments resulted from early adopting the amendments.

III. IFRS 7 Financial Instruments: Disclosures — Interest Rate Benchmark Reform
The transition of the London Interbank Offered Rates ("LIBOR") has begun with the cessation of the publication of one-week and two-month USD LIBOR occurring on Dec. 31, 2021. The remaining overnight, one-, three-, six-, and 12-month USD LIBOR will continue to be published until their cessation date on June 30, 2023. Existing financial instruments may continue to use USD LIBOR while they are published until they mature, however, new financial instruments will not be using USD LIBOR if entered into after Dec. 31, 2021. 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 were effective Jan. 1, 2021, and were adopted by the Company on Jan. 1, 2021. There was no financial impact upon adoption.

The Company's credit facilities references USD LIBOR for US-dollar drawings and the Canadian Dollar Offered Rate for Canadian drawings, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. For the year ended Dec. 31, 2021, there were no drawings under the credit facilities. The Company has interest rate swap agreements in place with a notional amount of US$150 million referencing three-month LIBOR, expected to settle in the third quarter of 2022.




TRANSALTA CORPORATION F26
Notes to Consolidated Financial Statements
B. Future Accounting Changes
I.Amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets
On May 14, 2020, the IASB issued Onerous Contracts — Cost of Fulfilling a Contract and amendments to IAS 37 Provisions, Contingent Liabilities and Contingent Assets to specify which costs to include when assessing whether a contract will be loss-making. The amendments are effective for annual periods beginning on or after Jan. 1, 2022, and will be adopted by the Company in 2022. The amendments are effective for contracts for which an entity has not yet fulfilled all its obligations on or after the effective date. No financial impact is expected upon adoption.

II. Amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction
On May 7, 2021, the IASB issued amendments to IAS 12 Deferred Tax Related to Assets and Liabilities Arising from a Single Transaction. The amendments clarify that the initial recognition exemption under IAS 12 does not apply to transactions such as leases and decommissioning obligations. These transactions give rise to equal and offsetting temporary differences in which deferred tax should be recognized.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, with early application permitted. The Company's current position aligns with the amendment and no financial impact is therefore expected upon adoption on the effective date.

III. Amendments  to  IAS  1  Classification  of  Liabilities  as  Current  or  Non‐Current 
In January 2020, the IASB issued amendments to IAS 1 Presentation of Financial Statements, to provide a more general approach to the presentation of liabilities as current or non‐current based on contractual arrangements in place at the reporting date. These amendments specify that the rights and conditions existing at the end of the reporting period are relevant in determining whether the Company has a right to defer settlement of a liability by at least 12 months, provide that management's expectations are not a relevant consideration as to whether the Company will exercise its rights to defer settlement of a liability and clarify when a liability is considered settled.

The amendments are effective for annual periods beginning on or after Jan. 1, 2023, and are to be applied  retrospectively. The Company has not yet determined the impact of these amendments on its consolidated financial statements. 

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.





TRANSALTA CORPORATION F27
Notes to Consolidated Financial Statements
4. Business Acquisitions and Divestitures
In accordance with IFRS 3 Business Combinations, the substance of the transactions described below constituted a business combination for TransAlta. The fair values of the identifiable assets and liabilities of the acquired entity in the business combinations as at the date of acquisition were:
North Carolina Solar (A)
Nov. 5, 2021		Ada facility (B)
May 19, 2020
Assets
Cash and cash equivalents4 1 
Accounts receivable4 3 
Property, plant and equipment146 1 
    Intangible assets(1)
— 37 
Right of use assets13 — 
    Inventory— 1 
    Prepaid expenses— 1 
Liabilities
Accounts payable and accrued liabilities(4)— 
Lease liabilities(13)— 
Tax equity liability(20)— 
Deferred taxes(3)— 
    Risk management liabilities (current and long-term)— (5)
Decommissioning provisions(4)(1)
Net assets acquired123 38 
Cash consideration120 32 
Working capital consideration3 6 
Total purchase consideration transferred123 38 
1) This relates to the power sales contract acquired and is being amortized over six years.

A. Acquisition of North Carolina Solar
On Nov. 5, 2021, the Company closed the acquisition of a 100 per cent membership interest in CI-II Mitchell Holding LLC, owner of a 122 MW portfolio of operating solar sites located in North Carolina (collectively, “North Carolina Solar”), for cash consideration of US$99 million (including working capital adjustments) and the assumption of existing tax equity obligations. The acquisition was funded using existing liquidity. The North Carolina Solar facility consists of 20 solar photovoltaic sites across North Carolina. The sites were commissioned between November 2019 and May 2021 and are all operational. The facility is secured by long-term PPAs with Duke Energy, which have an average remaining term of 12 years. Under the PPAs, Duke Energy receives the renewable electricity, capacity and environmental attributes from each facility.

Certain assets and liabilities have been measured on a provisional basis. If new facts and circumstances are obtained within one year from the date of acquisition that existed at the date of acquisition, any identified adjustments to the above amounts or additional provisions that existed at the date of acquisition, may result in a revision to the accounting for the acquisition.

Had North Carolina Solar been acquired at the beginning of the year, the assets would have contributed an estimated $16 million to revenues and $9 million to net earnings before taxes.

At the closing of the acquisition, TransAlta Renewables Inc. ("TransAlta Renewables"), a subsidiary of the Company, acquired a 100 per cent economic interest in North Carolina Solar from a wholly owned subsidiary of the Company through a tracking preferred share structure for aggregate consideration of approximately US$102 million.

B. Acquisition of the Ada Facility
On May 19, 2020, the Company closed the 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 in Michigan that is contracted under a PPA and a steam sale agreement for approximately 6 years with Consumers Energy and Amway.





TRANSALTA CORPORATION F28
Notes to Consolidated Financial Statements
C. Sale of Pioneer Pipeline
On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO Gas and Pipelines Ltd. ("ATCO") for the aggregate sale price of $255 million. The net cash proceeds to TransAlta from the sale of its 50 per cent interest was approximately $128 million, subject to certain adjustments.

As a result of this sale, the Company has derecognized the related Pioneer Pipeline assets that were classified as assets held for sale of $97 million and recognized a gain on sale of $31 million on the statement of earnings. In addition, as part of the transaction, the natural gas transportation agreement with the Pioneer Pipeline Limited Partnership was terminated, which resulted in the derecognition of the right-of-use asset of $41 million and a lease liability of $43 million related to the pipeline, resulting in a gain of $2 million.

5. Revenue
A. Disaggregation of Revenue
The majority of the Company'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 Company disaggregates into the following groups for the purpose of determining how economic factors affect the recognition of revenue.
Year ended Dec. 31, 2021HydroWind and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		Corporate and OtherTotal
Revenues from contracts with customers
  Power and other(3)
28 207 395 24 — — 654 
  Environmental attributes— 28 — — — — 28 
Revenue from contracts with customers28 235 395 24 — — 682 
Revenue from leases(4)
— — 19 — — — 19 
Revenue from derivatives and other
   trading activities		— (25)(118)138 211 4 210 
Merchant revenue and other(3)(5)
355 95 813 547 — — 1,810 
Total revenue383 305 1,109 709 211 4 2,721 
Revenues from contracts with customers
Timing of revenue recognition
   At a point in time— 28 2 23 — — 53 
   Over time28 207 393 1 — — 629 
Total revenue from contracts with customers28 235 395 24 — — 682 
(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.
(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details.
(3) The Alberta PPAs for certain facilities included in the Hydro, Gas and Energy Transition segments with the Balancing Pool expired at Dec. 31, 2020. These facilities began operating on a merchant basis in the Alberta market on Jan. 1, 2021.
(4) Total rental income, including contingent rent related to certain PPAs and other long-term contracts that meet the criteria of operating leases.
(5) Includes merchant revenue, government incentives and other miscellaneous.




TRANSALTA CORPORATION F29
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2020HydroWind and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		Corporate and OtherTotal
Revenues from contracts with customers
  Power and other141 238 465 156 — — 1,000 
  Environmental attributes— 23 — — — — 23 
Revenue from contracts with customers141 261 465 156 — — 1,023 
Revenue from leases(3)
— — 123 — — — 123 
Revenue from derivatives and
   other trading activities		— (2)(8)283 122 12 407 
Merchant revenue and other(4)
11 70 207 265 — (5)548 
Total revenue152 329 787 704 122 7 2,101 
Revenues from contracts with customers
Timing of revenue recognition
   At a point in time— 25 7 26 — — 58 
   Over time141 236 458 130 — — 965 
Total revenue from contracts with customers141 261 465 156 — — 1,023 
(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.
(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details.
(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, government incentives and other miscellaneous.
Year ended Dec. 31, 2019HydroWind and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		Corporate and OtherTotal
Revenues from contracts with customers
  Power and other142 221 497 185 — — 1,045 
  Environmental attributes— 23 — — — — 23 
Revenue from contracts with customers142 244 497 185 — — 1,068 
Revenue from leases(3)
— — 130 — — — 130 
Revenue from derivatives and
   other trading activities		— 18 (15)160 129 4 296 
Merchant revenue and other(4)
14 50 239 560 — (10)853 
Total revenue156 312 851 905 129 (6)2,347 
Revenues from contracts with customers
Timing of revenue recognition
   At a point in time— 27 5 46 — — 78 
   Over time142 217 492 139 — — 990 
Total revenue from contracts with customers142 244 497 185 — — 1,068 
(1) This segment includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal. Refer to Note 1 for further details.
(2) This segment includes the segment previously known as Centralia and the facilities not converted to gas previously in the Alberta Thermal. Refer to Note 1 for further details.
(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, government incentives and other miscellaneous.





TRANSALTA CORPORATION F30
Notes to Consolidated Financial Statements
B. Contract Liabilities
The Company has recognized the following revenue-related contract liabilities:
Contract liabilities20212020
Balance, beginning of the year15 15 
Amounts transferred to revenue included in opening balance(1)(1)
Consideration received8 1 
Increases due to amounts billed to customers— 2 
Changes in transaction price11 — 
Performance obligations satisfied(1)(2)
Balance, end of year32 15 
Current portion19 1 
Long-term portion13 14 

The contract liabilities outstanding at Dec. 31, 2021, and Dec. 31, 2020, primarily relate to prepayments relating to the Company's New Richmond and Bone Creek facilities where the Company still has to fulfil its performance obligations. In addition, the Company recognized a provision for liquidated damages due to the Sarnia outages that occurred in the second quarter of 2021.

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 invoice practical expedient and contracts with an original expected duration of less than 12 months.

Additionally, in many of the Company’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 Company’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.

Contracts with customers that are accounted for as derivatives are excluded from these disclosures. Refer to Note 15 for further details. Contracts that have been executed for development projects are excluded until commercial operations have been achieved.

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 Company from its contractual portfolio.

Hydro
At Dec. 31, 2020, the Company's PPA with the Balancing Pool to provide the capacity of 12 hydro facilities throughout the province of Alberta concluded. Commencing Jan. 1, 2021, production has been sold into the Alberta merchant market.

The Company has contracts for services at specific hydro facilities, which will conclude at the end of 2030. The Company also has a contract with the Government of Alberta to manage water for flood and drought mitigation purposes, which concludes in 2026. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $46 million.





TRANSALTA CORPORATION F31
Notes to Consolidated Financial Statements
Wind and Solar
At Dec. 31, 2021, the Company 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 Company expects to recognize such amounts as revenue as it delivers electricity over the remaining terms of the contracts, until 2024, 2034 and 2033, respectively. The variable revenues under the contracts are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures.

The Company 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 2022 through 2024. Estimated future revenues related to the remaining performance obligations for these contracts as of Dec. 31, 2021, are approximately $9 million.

Gas
At Dec. 31, 2020, the Company's PPAs with the Balancing Pool for capacity and electricity from the Keephills Unit 2 and Sheerness Units 1 and 2 legacy coal facilities concluded. Future production has been sold into the merchant market.

At Dec. 31, 2021, the Company 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 Company to stand ready to deliver electricity and steam. On May 12, 2021, the Company executed an Amended and Restated Energy Supply Agreement with one of its large industrial customers at the Sarnia cogeneration facility that provides for the supply of electricity and steam. This agreement will extend the term of the original agreement from Dec. 31, 2022 to Dec. 31, 2032. However, if TransAlta is unable to enter into a new contract with the Ontario Independent Electricity System Operator or enter into agreements with its other industrial customers at the Sarnia cogeneration facility that extend past Dec. 31, 2025, then the Company has the option to provide notice of termination in 2022 that would terminate the Amended and Restated Energy Supply Agreement four years following such notice. The Company currently expects to recognize revenue as it delivers electricity and steam to the other industrial customers at the Sarnia cogeneration facility until the completion of the contracts in late 2025, or 2032, if the contract is extended.

At the same gas facility, the Company 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 Company’s control and are considered to be fully constrained. Accordingly, these revenues are excluded from these disclosures. The Company 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, 2021, the Company had contracts with customers to deliver steam, hot water and chilled water from one of its other gas facilities in Ontario, extending through 2023 and 2033. Prices under these contracts include fixed annual fees, variable thermal energy charges based on gas prices, and fixed base amounts per gigajoule, subject to escalation annually for both gas prices and inflation. One contract includes minimum annual take-or-pay volumes. Estimated future revenues related to the remaining performance obligations for this contract as of Dec. 31, 2021, are approximately $31 million.

The Company has a contract with its customer for provision of steam and electricity output at its Alberta cogeneration facility extending through to Dec. 31, 2029. The contract 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 are variable in nature and considered to be fully constrained and are these revenues are excluded from these disclosures.

The Company has a contract, commencing in late 2023, for the sale of capacity and electricity, exercisable at the option of the customer in Canada, under which the Company 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, 2021, are approximately $336 million, of which the Company 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.





TRANSALTA CORPORATION F32
Notes to Consolidated Financial Statements
At Dec. 31, 2021, the Company 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. The variable revenues under the contracts are considered to be fully constrained and are excluded from these disclosures. Another one of the Company's PPA 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 and are excluded from these disclosures. The Company also earns revenues from providing operation and maintenance services for the facility for a fixed monthly fee. Estimated future revenues related to the remaining performance obligations for these contracts as at Dec. 31, 2021, are approximately $2.5 billion, of which the Company expects to recognize approximately $285 million in total over the next two fiscal years and on average, between approximately $85 million to $145 million annually thereafter for the duration of the remaining contract.

Energy Transition
At Dec. 31, 2020, the Company's PPAs with the Balancing Pool for capacity and electricity from the Keephills Unit 1 coal facility concluded. Commencing Jan. 1, 2021, production has been sold into the merchant market.

6. Expenses by Nature
Fuel and purchased power and operations, maintenance and administrative ("OM&A") expenses classified by nature are
as follows:
Year ended Dec. 31202120202019
 Fuel and
purchased
power		OM&AFuel and
purchased
power		OM&AFuel and
purchased
power		OM&A
Gas fuel costs(1)
306 — 159 — 133 — 
Coal fuel costs(1)(2)
164 — 269 — 310 — 
Royalty, land lease, other direct costs19 — 20 — 21 — 
Purchased power339 — 163 — 246 — 
Mine depreciation(3)
190 — 144 — 119 — 
Salaries and benefits36 234 50 235 52 228 
Other operating expenses(4)
— 277 — 237 — 247 
Total1,054 511 805 472 881 475 
(1) During 2021, fuel costs have been split to show natural gas and coal fuel costs separately within the above table and carbon compliance costs have been reclassified from fuel and purchased power to a separate line called carbon compliance costs on the Consolidated Statements of Earnings (Loss). Prior periods have been adjusted to reflect these reclassifications.
(2) Included in coal fuel costs for 2021 was $17 million related to the impairment of coal inventory recorded during 2021 (2020 — $15 million). Refer to Note 17 for further details.
(3) Included in mine depreciation for 2021 was $48 million related to the mine depreciation that was initially recorded in the standard cost of coal inventory and then subsequently impaired during 2021 (2020 — $22 million) . Refer to Note 17 for further details.
(4) Included in OM&A costs for 2021 was $28 million related to the write-down of parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities. Refer to Note 17 for further details.






TRANSALTA CORPORATION F33

Notes to Consolidated Financial Statements
7. Asset Impairment
As part of the Company’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 Company 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 Company 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 Company’s long-range forecasts. The valuations used are subject to measurement uncertainty based on assumptions and inputs to the Company’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 2072.
202120202019
PP&E Impairments:
Energy Transition facilities and projects (reversals)345 79 (151)
Energy Transition - Centralia mine decommissioning and restoration provision— 3 141 
Changes in decommissioning and restoration provisions for retired assets(1)
32 — 2 
Highvale mine195 — — 
Kaybob Cogeneration Project27 — — 
Wind12 — — 
Hydro5 2 — 
Gas5 — — 
Intangible asset impairment - coal rights(2)
17 — — 
Assets held for sale(3)
— — 15 
Project development costs(4)
10 — 18 
Asset impairment648 84 25 
(1) Changes related to changes in discount rates on retired assets.
(2) Impaired to nil as no future coal will be extracted from this area of the mine.
(3) 2019 amounts relate to trucks and associated inventory to be sold within the Energy Transition segment and accordingly, these items were impaired to net realizable value.
(4) During 2021, the Company recorded an impairment of $9 million in the Hydro segment for the balance of project development costs at one of our hydro facilities as there is uncertainty on timing of when the project will proceed and $1 million related to projects that are no longer proceeding. During 2020, the Company wrote off nil (2019 — $18 million) in project development costs related to projects that are no longer proceeding within the Corporate segment.

A.Energy Transition Asset Impairments
During 2021, the Company recognized asset impairment charges in the Energy Transition segment as a result of the decision to suspend the Sundance Unit 5 repowering project ($191 million) and planned retirements of Keephills Unit 1, effective Dec. 31, 2021 ($94 million), Sundance Unit 4, effective April 1, 2022 ($56 million) Keephills Unit 1 and Sundance Unit 4 impairment assessments were based on the estimated salvage values of these units which were in excess of the expected economic benefits from these units. For the Sundance Unit 5 repowering project, the recoverable amount was determined based on estimated fair value less costs of disposal of selling the equipment for assets under construction and estimated salvage value for the balance of the costs. The fair value measurement for assets under construction is categorized as a Level III fair value measurement. The total remaining estimated recoverable amount and salvage values for Sundance Unit 5 repowering project was $33 million, of which $25 million was related to assets held for sale. Discounting did not have a material impact to these asset impairments. The asset retirement and project suspension decisions were based on the Company's assessment of future market conditions, the age and condition of in-service units, as well as TransAlta's strategic focus toward renewable energy solutions.

During 2020, the Company recognized an impairment on Sundance Unit 3 in the amount of $70 million due to the Company's decision to retire the unit. 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 salvage value of the scrap materials. In addition, the Company recognized an impairment of $9 million (US$7 million) due to a decrease in the fair value of land for the Centralia mine determined through a third-party appraiser.

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 recoverability test in 2019. The updated fair value included sustained changes in the market power price and cost of coal due to contract renegotiation. As a result of the recoverability test, an impairment reversal of $151 million was recorded in the Centralia segment.




TRANSALTA CORPORATION F34
Notes to Consolidated Financial Statements

B.Highvale Mine
During 2021, with the expected closure of the Highvale mine at the end of 2021, it was determined that the estimated salvage value exceeded the economic benefit to the Alberta Merchant CGU. The asset has been removed from the Alberta Merchant CGU for impairment purposes and was assessed for impairment as an individual asset which resulted in the recognized impairment charge of $195 million in the Energy Transition segment, with the asset being written down to salvage value.

C.Kaybob Cogeneration Project
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 South No. 3 sour gas processing plant. The facility was expected to receive its final regulatory approvals in the second half of 2020 and begin construction in December 2020. On Sept. 25, 2020, the Alberta Utilities Commission ("AUC") released a decision in which it approved the construction and operation of the facility, but denied the application for the Industrial System Designation. TransAlta will not be proceeding with the Kaybob cogeneration facility as a result of ET Canada's purported termination of the agreements to develop, construct and operate the 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing plant. As a result, the Company recorded an impairment of $27 million in the Corporate segment as this facility was not yet operational. The recoverable amount was based on estimated fair value less costs of disposal of reselling the equipment purchased to date. TransAlta has commenced an arbitration seeking compensation for ET Canada's wrongful termination of the agreements. Refer to Note 36 for further details.

D.Wind Facilities
During the third quarter of 2021, the Company recorded an impairment of $10 million for a wind asset as result of an increase in estimated decommissioning costs after the review of a recent engineering study on the decommissioning costs of the wind sites. Refer to Note 23 for more details for changes in decommissioning and restoration provisions. The resulting fair value measurement less cost of disposal is categorized as a Level III fair value measurement and the Company has adjusted the expected value down to $65 million using discount rates of 5.0 per cent (Dec. 31, 2020 — 5.3 per cent). The key assumptions impacting the determination of fair value are electricity production, sales prices and cost inputs, which are subject to measurement uncertainty.

During 2021, the Company recognized an impairment of $2 million related to the Kent Hills Wind LP tower failure. The Company's subsidiary, Kent Hills Wind LP, experienced a single tower failure at its 167 MW Kent Hills wind facility in Kent Hills, New Brunswick. The failure involved a collapsed tower located within the Kent Hills 2 site. Refer to Note 24 for further details.

E.Impairment on Decommissioning and Restoration Provision on Retired Assets
During 2019, the Company adjusted the Centralia mine decommissioning and restoration provision as management no longer believed that the fine coal recovery and reclamation work will occur as originally proposed. At the end of 2019, the Company'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 charges to net earnings.





TRANSALTA CORPORATION F35

Notes to Consolidated Financial Statements
8. Finance Lease Receivables
Amounts receivable under the Company’s finance leases associated with the Poplar Creek cogeneration facility and the Southern Cross Energy facilities are as follows:
As at Dec. 3120212020
 Minimum
lease
receipts		Present value of
minimum lease
receipts		Minimum
lease
receipts		Present value of
minimum lease
receipts
Within one year58 54 63 56 
Second to fifth years inclusive127 105 169 126 
More than five years80 66 100 82 
 265 225 332 264 
Less: unearned finance lease income40 — 68 — 
Total finance lease receivables225 225 264 264 
Included in the Consolidated Statements of Financial Position as:    
Current portion of finance lease receivables (Note 14)40  36  
 Long-term portion of finance lease receivables185  228  
Total finance lease receivables225  264  

On Oct. 22, 2020, Southern Cross Energy ("SCE"), a subsidiary of the Company, replaced and extended its current long- term PPA with BHP Billiton Nickel West Pty Ltd. ("BHP"). 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. 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, in 2020, the Company derecognized net assets of $77 million, which included balances for PP&E, intangible assets, deferred credits and prepaid expenses. In addition, the Company recognized a finance lease receivable of $89 million and a gain on asset disposition of $12 million. Subsequent to the transaction, the Company incurred additional major maintenance costs in relation to these assets which was recorded as a reduction to the gain on asset disposition.

9. Net Other Operating Expense (Income)
Net other operating income includes the following:
Year ended Dec. 31202120202019
Alberta Off-Coal Agreement(40)(40)(40)
Supplier settlements34 — — 
Onerous contract provisions14 29 — 
Insurance recoveries and other(1)
— — (9)
Net other operating expense (income)8 (11)(49)
(1) There were no insurance recoveries in 2021 or 2020. In 2019, the Company received $10 million in insurance recoveries related to insurance proceeds for tower fires at Wyoming and Summerview.

A. Alberta Off-Coal Agreement ("OCA")
The Company receives payments from the Government of Alberta for the cessation of coal-fired emissions on or before Dec. 31, 2030. Under the terms of the agreement, the Company receives annual cash payments on or before July 31 of approximately $40 million ($37 million, net of the non-controlling interest related to Sheerness), which commenced Jan. 1, 2017, and will terminate at the end of 2030. The Company 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 which has been achieved effective Dec. 31, 2021. 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 Company obtained financing against the OCA payments. Refer to Note 24 for further details.




TRANSALTA CORPORATION F36
Notes to Consolidated Financial Statements
B. Supplier Settlements
During 2021, $34 million was expensed relating to decisions to no longer proceed with the Sundance Unit 5 repowering project and to retire Keephills Unit 1, including a deferred asset of $10 million (US$8 million) for which the Company is unlikely to incur sufficient capital or operating expenditures to utilize the remaining credit.

C. Onerous Contract Provisions
During 2021, an onerous contract provision for future royalty payments of $14 million was recognized with the shutdown of the Highvale mine.

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

10. Investments
The Company’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:
SkookumchuckEMGTotal
Balance, Dec. 31, 2019— — — 
Contributions86 16 102 
Equity income 1 — 1 
Change in foreign exchange rates(2)(1)(3)
Balance, Dec. 31, 202085 15 100 
Equity income 12 (3)9 
Distributions received(4)— (4)
Balance, Dec. 31, 202193 12 105 

A.Skookumchuck Wind Project
On Nov. 25, 2020, TransAlta completed the purchase of a 49 per cent interest in SP Skookumchuck Investments, LLC from Southern Power for cash consideration of $86 million (US$66 million). 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 has a 20-year PPA with Puget Sound Energy.

B.EMG International Acquisition
On Nov. 30, 2020, TransAlta acquired a 30 per cent equity interest in EMG. 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. The investment provides an opportunity for TransAlta to leverage its expertise in on-site generation to support further advancements by EMG in the waste-to-energy space and will advance the Company's Clean Electricity Growth plan in the US market .

Summarized financial information on the results of operations relating to the Company’s pro-rata interests in Skookumchuck and EMG is as follows:
Year ended Dec. 3120212020
Results of operations
Revenues19 3 
Expenses(10)(2)
Proportionate share of net earnings9 1 





TRANSALTA CORPORATION F37

Notes to Consolidated Financial Statements
11. Net Interest Expense
The components of net interest expense are as follows:
Year ended Dec. 31202120202019
Interest on debt163 158 161 
Interest on exchangeable debentures (Note 25)29 29 20 
Interest on exchangeable preferred shares (Note 25)
28 5 — 
Interest income(11)(10)(13)
Capitalized interest (Note 18)
(14)(8)(6)
Interest on lease liabilities7 8 4 
Credit facility fees, bank charges and other interest18 18 15 
Tax shield on tax equity financing (Note 24)(1)
(9)1 (35)
Interest on line loss rule proceeding (Note 36(H)(I))— 5 — 
Other(2)
2 2 10 
Accretion of provisions (Note 23)32 30 23 
Net interest expense245 238 179 
(1) Credit in 2021 primarily relates to the tax benefit associated with investment tax credits claimed in 2021 on the North Carolina Solar projects that was assigned to the tax equity investor. Credit in 2019 primarily 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 investments are treated as debt under IFRS and the monetization of the tax attributes is considered a non-cash reduction of the debt balance and is reflected as a reduction in interest expense.
(2) In 2021, other interest expense included approximately nil (2020 — nil , 2019 — $5 million) for the significant financing component required under IFRS 15.

12. Income Taxes
A. Consolidated Statements of Earnings
I. Rate Reconciliations
Year ended Dec. 31202120202019
Earnings (loss) before income taxes(380)(303)193 
Net earnings (loss) attributable to non-controlling interests not subject to tax(33)2 (26)
Adjusted earnings (loss) before income taxes(413)(301)167 
Statutory Canadian federal and provincial income tax rate (%)23.6 %24.5 %26.5 %
Expected income tax expense (recovery)(98)(74)44 
Increase (decrease) in income taxes resulting from:   
Differences in effective foreign tax rates4 3 5 
Deferred income tax expense related to temporary difference on investment in
  subsidiaries		— 9 — 
Write-down (reversal of write-down) of unrecognized deferred income tax assets134 8 (9)
Statutory and other rate differences4 (7)(31)
Other1 11 8 
Income tax expense (recovery)45 (50)17 
Effective tax rate (%)(11 %)17 %10 %





TRANSALTA CORPORATION F38
Notes to Consolidated Financial Statements
II. Components of Income Tax Expense
The components of income tax expense are as follows:
Year ended Dec. 31202120202019
Current income tax expense56 35 35 
Deferred income tax expense (recovery) related to the origination and reversal of
   temporary differences
(145)(95)22 
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— (7)(31)
Deferred income tax expense (recovery) arising from the unrecognized deferred income tax assets(1)
134 8 (9)
Income tax expense (recovery)45 (50)17 
Year ended Dec. 31202120202019
Current income tax expense56 35 35 
Deferred income tax recovery(11)(85)(18)
Income tax expense (recovery)45 (50)17 
(1) During the year ended Dec. 31, 2021, the Company recorded a write-down of deferred tax assets of $134 million (2020 —$8 million write-down, 2019 —  $9 million write-down reversal). 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 Company’s directly owned US operations and Canadian operations. The Company evaluates at each period end, whether it is probable that sufficient future taxable income would be available from the Company’s directly owned US operations to utilize the underlying tax losses.

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. 31202120202019
Income tax expense (recovery) related to:   
Net impact related to cash flow hedges(57)(23)6 
Net actuarial gains (losses)11 (3)(7)
Income tax recovery reported in equity(46)(26)(1)

C. Consolidated Statements of Financial Position
Significant components of the Company’s deferred income tax assets (liabilities) are as follows:
As at Dec. 3120212020
Net operating loss carryforwards(1)
530 469 
Future decommissioning and restoration costs183 140 
Property, plant and equipment(651)(717)
Risk management assets and liabilities, net(53)(107)
Employee future benefits and compensation plans53 62 
Interest deductible in future periods17 22 
Foreign exchange differences on US-denominated debt16 31 
Other deductible temporary differences(5)2 
Net deferred income tax liability, before write-down of deferred income tax assets90 (98)
Unrecognized deferred income tax assets(380)(247)
Net deferred income tax liability, after write-down of deferred income tax assets(290)(345)
(1) Net operating losses expire between 2031 and 2040.

The net deferred income tax liability is presented in the Consolidated Statements of Financial Position as follows:
As at Dec. 3120212020
Deferred income tax assets(1)
64 51 
Deferred income tax liabilities(354)(396)
Net deferred income tax liability(290)(345)
 
(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 Company’s long-range forecasts.




TRANSALTA CORPORATION F39

Notes to Consolidated Financial Statements
 D. Contingencies
As of Dec. 31, 2021, the Company had recognized a net liability of nil (2020 — nil) related to uncertain tax positions.

Ongoing CRA Audit
The Company is subject to routine audits of its tax filing positions by the Canada Revenue Agency ("CRA") on an ongoing basis. The CRA is currently examining the Company's tax filings for the 2015 taxation year and, in connection with such audit, is reviewing the internal reorganization completed in 2015. To date, the CRA has not proposed any reassessment of the Company's tax liability as a consequence of such audit and management believes that any reassessment would be without merit. The Company strongly believes that the Company's tax filing positions are appropriate, and accordingly no amounts have been accrued in the consolidated financial statements in respect of any such potential reassessment. If a notice of reassessment were issued, the Company would expect to vigorously oppose any such reassessment. If the CRA were to issue such a reassessment, the Company would be required to pay, on a provisional basis, up to 50 per cent of the amounts assessed, estimated to be between nil and $57 million. Any payment made by the Company in this context would be held by CRA until the final resolution of the dispute. The Company firmly believes it will be able to successfully defend its original filing position so that, ultimately, no increased income tax payable will result from the CRA's audit and any amounts paid to the CRA by the Company would be refunded.

13. Non-Controlling Interests
The Company’s subsidiaries and operations that have non-controlling interests are as follows:
Subsidiary/Operation
Non-controlling interest as at Dec. 31, 2021
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 Company.
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.
Year ended Dec. 31202120202019
Revenues470 436 446 
Net earnings139 97 183 
Total comprehensive earnings66 223 138 
Amounts attributable to the non-controlling interests:  
Net earnings50 40 73 
Total comprehensive earnings21 90 56 
Distributions paid to non-controlling interests100 80 69 
As at Dec. 3120212020
Current assets430 743 
Long-term assets3,319 2,913 
Current liabilities(593)(364)
Long-term liabilities(1,033)(987)
Total equity(2,123)(2,305)
Equity attributable to non-controlling interests(869)(948)
Non-controlling interests’ share (per cent)39.939.9




TRANSALTA CORPORATION F40
Notes to Consolidated Financial Statements
In 2020, the Company's ownership per cent decreased from 60.4 per cent in 2019 to 60.1 per cent due to TransAlta Renewables issuing approximately 1 million common shares under their Dividend Reinvestment Plan ("DRIP"). The Company did not participate in this plan. In the fourth quarter of 2020, TransAlta Renewables suspended the DRIP in respect of any future declared dividends.

B. TA Cogen
Year ended Dec. 31202120202019
Results of operations   
Revenues265 146 181 
Net earnings (loss)103 (13)43 
Total comprehensive earnings (loss)103 (13)43 
Amounts attributable to the non-controlling interest:   
Net earnings (loss)62 (6)21 
Total comprehensive earnings (loss)62 (6)21 
Distributions paid to Canadian Power Holdings Inc.56 17 37 

As at Dec. 3120212020
Current assets66 69 
Long-term assets312 323 
Current liabilities(52)(78)
Long-term liabilities(36)(37)
Total equity(290)(277)
Equity attributable to Canadian Power Holdings Inc.(142)(136)
Non-controlling interest share (per cent)49.9949.99

In 2020, the Balancing Pool PPA concluded and the Sheerness facility became a merchant facility in 2021. This resulted in new protocols under the amended contractual agreement whereby the revenue and cost of sales for the facility are allocated based on dispatch activities. Capital and operating expenses continue to be allocated based on ownership interest.

14. Trade and Other Receivables
As at Dec. 3120212020
Trade accounts receivable499 488 
Collateral paid (Note 16)55 49 
Current portion of finance lease receivables (Note 8)40 36 
Loan receivable (Note 22)55 — 
Income taxes receivable2 10 
Trade and other receivables651 583 






TRANSALTA CORPORATION F41

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, 2021
 Derivatives
used for
hedging		Derivatives
held for
trading (FVTPL)		Amortized costTotal
Financial assets    
Cash and cash equivalents(1)
— — 947 947 
Restricted cash— — 70 70 
Trade and other receivables— — 651 651 
Long-term portion of finance lease receivable— — 185 185 
Risk management assets    
Current36 272 — 308 
Long-term252 147 — 399 
Financial liabilities    
Accounts payable and accrued liabilities— — 689 689 
Dividends payable— — 62 62 
Risk management liabilities    
Current— 261 — 261 
Long-term— 145 — 145 
Credit facilities, long-term debt and lease liabilities(2)
— — 3,267 3,267 
Exchangeable securities (Note 25)
— — 735 735 
(1) Includes cash equivalents of nil.
(2) Includes current portion.

Carrying value as at Dec. 31, 2020
 Derivatives
used for
hedging		Derivatives
held for
trading (FVTPL)		Amortized costTotal
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 receivables— — 228 228 
Risk management assets
Current102 69 — 171 
Long-term471 50 — 521 
Other assets (Note 22)
— — 52 52 
Financial liabilities
Accounts payable and accrued liabilities— — 599 599 
Dividends payable— — 59 59 
Risk management liabilities
Current10 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.





TRANSALTA CORPORATION F42
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 Company has access. In the absence of an active market, the Company 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 Company looks primarily to external readily observable market inputs. However, if not available, the Company 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 Company 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 Company has the ability to access at the measurement date. In determining Level I fair values, the Company 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 Company’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 Company 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 Company 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 Company 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 volatility and correlations between products derived from historical price relationships.

The Company 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.




TRANSALTA CORPORATION F43

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, 2021, are as follows: Level I — $12 million net asset (Dec. 31, 2020 — $13 million net liability), Level II — $122 million net asset (Dec. 31, 2020 — $27 million net liability) and Level III — $159 million net asset (Dec. 31, 2020 — $582 million net asset).

Significant changes in commodity net risk management assets (liabilities) during the year ended Dec. 31, 2021, are primarily attributable to volatility in market prices on both existing contracts and new contracts as well as contract settlements.

The following tables summarize the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the years ended Dec. 31, 2021 and 2020, respectively:
Year ended Dec. 31, 2021Year ended Dec. 31, 2020
HedgeNon-hedgeTotalHedgeNon-hedgeTotal
Opening balance573 9 582 678 8 686 
Changes attributable to:
Market price changes on existing contracts(181)4 (177)(18)3 (15)
Market price changes on new contracts— (134)(134)— 7 7 
Contracts settled(107)(5)(112)(71)(10)(81)
Change in foreign exchange rates— — — (16)1 (15)
Net risk management assets (liabilities) at end of period285 (126)159 573 9 582 
Additional Level III information:
Losses recognized in other comprehensive earnings(181)— (181)(34)— (34)
Total gains (losses) included in earnings before income
  taxes		107 (130)(23)71 11 82 
Unrealized gains (losses) included in earnings before
  income taxes relating to net assets held at period end		— (135)(135)— 1 1 
The Company 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 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. 
The Company's risk management department determines methodologies and procedures regarding commodity risk management Level III fair value measurements. Level III fair values are primarily calculated within the Company’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.
As at Dec. 31, 2021, the total Level III risk management asset balance was $305 million (2020 — $615 million) and Level III risk management liability balance was $146 million (2020 — $33 million). The 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. These include the effects on fair value of discounting, liquidity and credit value adjustments; however, the potential offsetting effects of Level II positions are not considered. 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, volatility in commodity prices and correlations, delivery volumes, escalation rates and cost of supply. During 2021, the sensitivities include the effects of liquidity and credit value adjustments.





TRANSALTA CORPORATION F44
Notes to Consolidated Financial Statements
As atDec. 31, 2021
DescriptionSensitivityValuation techniqueUnobservable inputReasonable possible change
Long-term power
   sale – US
+22
Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of US$3 or price increase of US$20
-145
Coal
  transportation –
  US
+3
Numerical derivative valuationIlliquid future power prices (per MWh)
Price decrease of US$3 or price increase of US$20
Volatility
80% to 120%
-18
Rail rate escalation
zero to 4%
Full requirements
   – Eastern US
+9
Historical bootstrapVolume
95% to 105%
-9
Cost of supply
(+/-) US$1 per MWh
Long-term wind
  energy sale –
  Eastern US
+17
Long-term price forecastIlliquid future power prices (per MWh)
Price increase or decrease of US$6
-16
Illiquid future REC prices (per unit)
Price decrease of US$3 or increase of US$2
Long-term wind
  energy sale –
  Canada		+21Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of C$24 or increase of C$5
-11 Wind discounts
 5% decrease or 5% increase
Long-term wind
  energy sale -
  Central US		+27 Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of US$2 or increase of US$3
-15 Wind discounts
3% decrease or 3% increase
Others
+6
-6
As atDec. 31, 2020
DescriptionSensitivityValuation techniqueUnobservable inputReasonable possible change
Long-term power
   sale – US
+35
Long-term price forecastIlliquid future power prices (per MWh)
Price decrease of US$3 or a price increase of US$5
-59
Coal
  transportation –
   US
+3
Numerical derivative valuationIlliquid future power prices (per MWh)
Price decrease of US$3 or a price increase of US$5
Volatility
80% to 120%
-5
Rail rate escalation
zero to 4%
Full
  requirements –
  Eastern US
+3
Historical bootstrapVolume
95% to 105%
-3
Cost of supply
(+/-) US$1 per MWh
Long-term wind
  energy sale –
  Eastern US
+22
Long-term price forecastIlliquid future power prices (per MWh)
Price increase or decrease of US$6
-22
Illiquid future REC prices (per unit)
Price increase or decrease of US$1
Others
+5
-5

i. Long-Term Power Sale – US
The Company 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 2023, 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).
The contract is denominated in US dollars. The US dollar relative to the Canadian dollar remained consistent from Dec. 31, 2020, to Dec. 31, 2021, resulting in the sensitivity values remaining consistent. The balance for this contract at Dec. 31, 2021 decreased mainly due to higher forward power prices compared to previously estimated prices.




TRANSALTA CORPORATION F45

Notes to Consolidated Financial Statements
ii. Coal Transportation - US
The Company has a coal rail transport agreement that includes an upside sharing mechanism, with a contract start date of Jan. 1, 2021, that extends 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 2023, 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 judgment.

iii. Full Requirements – Eastern US
The Company has a portfolio of full requirement service contracts, whereby the Company agrees to supply specific utility customer needs for a range of products that may include electrical energy, capacity, transmission, ancillary services, renewable energy credits ("RECs") 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.

iv. Long-Term Wind Energy Sale – Eastern US
In relation to the Big Level wind facility, the Company has a long-term contract for differences whereby the Company 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 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. 
v. Long-Term Wind Energy Sale – Canada
In relation to the Garden Plain wind project, the Company has entered into a virtual PPA whereby the Company receives the difference between the fixed contract price per MWh and the Alberta Electric System Operator ("AESO") settled pool price per MWh. The contract commences on commercial operation of the facility, which is expected by the end of 2022, and extending for 18 years past that date. The energy component of the contract is accounted for at fair value through profit or loss.

In addition to the virtual PPA contract, the Company has entered into a "bridge contract" that runs 16 months from Sept. 1, 2021 through Dec. 31, 2022, with the potential for extension at the virtual PPA price, depending on the commencement of commercial operations.

Under a separate agreement, Pembina has the option to purchase a 37.7 per cent interest in the project (49 per cent of the PPA). The option must be exercised no later than 30 days after commercial operational date.

The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly wind discounts.

vi. Long-Term Wind Energy Sale – Central US
On Dec. 22, 2021, TransAlta executed two long-term virtual PPAs for the off take of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects (collectively, the "White Rock Wind Projects") to be located in Caddo County, Oklahoma. The Company receives the difference between the fixed contract price per MWh and the settled pool price per MWh. The contracts commence on commercial operation of the facilities, which is expected within the second half of 2023, and extend for 15 years past that date. The energy component of the contracts is accounted for at fair value through profit or loss.

The key unobservable inputs used in the valuation of the contracts are the non-liquid forward prices for power and monthly wind discounts.




TRANSALTA CORPORATION F46
Notes to Consolidated Financial Statements
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 asset fair value of $8 million as at Dec. 31, 2021 (Dec. 31, 2020 – $12 million net liability) 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, 2021, are primarily attributable to favourable 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 value(1)
 Level ILevel IILevel IIITotal
Exchangeable securities — Dec. 31, 2021— 770 — 770 735 
Long-term debt — Dec. 31, 2021— 3,272 — 3,272 3,167 
Exchangeable securities — Dec. 31, 2020— 769 — 769 730 
Long-term debt — Dec. 31, 2020— 3,480 — 3,480 3,227 
(1) Includes current portion.
The fair values of the Company’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 Company 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. 31202120202019
Unamortized net gain (loss) at beginning of year(33)9 49 
New inception gain (loss)(1)
(50)(13)3 
Amortization recorded in net earnings during the year(19)(29)(43)
Unamortized net gain (loss) at end of year(2)
(102)(33)9 
(1) During 2021, the Company entered into PPAs for the White Rock Wind Projects that resulted in a new inception loss due to the difference between the fixed PPA price and future estimated market prices. There are other key factors, such as project economics and incentives, that influence the long-term power price for renewable projects outside of the power price curve, which is not liquid for the majority of the duration of the power agreement contract period. During 2020, the Company 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 one forward price curve at inception of the contract.





TRANSALTA CORPORATION F47

Notes to Consolidated Financial Statements
16. Risk Management Activities
A. Risk Management Strategy
The Company is exposed to market risk from changes in commodity prices, foreign exchange rates, interest rates, credit risk and liquidity risk. These risks affect the Company’s earnings and the value of associated financial instruments that the Company holds. In certain cases, the Company seeks to minimize the effects of these risks by using derivatives to hedge its risk exposures. The Company’s risk management strategy, policies and controls are designed to ensure that the risks it assumes comply with the Company’s internal objectives and its risk tolerance.

The Company 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 Company 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 Company may apply hedge accounting to those hedging commodity price risk, interest rate risk and foreign currency risk.

The use of financial derivatives is governed by the Company’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 Company 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 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 Company 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 Company 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 Company 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 Company 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 Company adjusts the hedge ratio of the hedging relationship so that it continues to meet the qualifying criteria.





TRANSALTA CORPORATION F48
Notes to Consolidated Financial Statements
B. Net Risk Management Assets and Liabilities
 
Aggregate net risk management assets (liabilities) are as follows:
As at Dec. 31, 2021
 Cash flow
hedges		Not
designated
as a hedge		Total
Commodity risk management   
Current33 12 45 
Long-term252 (4)248 
Net commodity risk management assets285 8 293 
Other   
Current3 (1)2 
Long-term— 6 6 
Net other risk management assets3 5 8 
Total net risk management assets288 13 301 

As at Dec. 31, 2020
 Cash flow
hedges		Not
designated
as a hedge		Total
Commodity risk management   
Current101 (11)90 
Long-term471 (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 

I. Netting Arrangements
Information about the Company’s financial assets and liabilities that are subject to enforceable master netting arrangements or similar agreements is as follows:
As at Dec. 3120212020
 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 recognized394 330 (306)(122)120 69 (132)(104)
Gross amounts set-off(137)(53)138 54 (69)(10)69 10 
Net amounts as included in the
  Consolidated Statements of
  Financial Position		257 277 (168)(68)51 59 (63)(94)





TRANSALTA CORPORATION F49

Notes to Consolidated Financial Statements
C. Nature and Extent of Risks Arising from Financial Instruments
 
I. Market Risk
 
a. Commodity Price Risk Management
 
The Company 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 Company’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 Company’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 Company’s proprietary trading business and commodity derivatives used in hedging relationships associated with the Company’s electricity generating activities.

To mitigate the risk of adverse commodity price changes, the Company 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 Company 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 Company’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 Company’s exposure to market risks or the manner in which these risks are managed or measured.

i. Commodity Price Risk Management – Proprietary Trading
 
The Company’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 Company’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.
Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at Dec. 31, 2021, associated with the Company’s proprietary trading activities was $2 million (2020 — $1 million, 2019 — $1 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 Company’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 Company’s reported net earnings.




TRANSALTA CORPORATION F50
Notes to Consolidated Financial Statements
VaR at Dec. 31, 2021, associated with the Company’s commodity derivative instruments used in generation hedging activities was $33 million (2020 — $12 million, 2019 — $25 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, 2021, associated with these transactions was $51 million (2020— $15 million, 2019 — $8 million).
iii. Commodity Price Risk Management – Hedges
The Company’s outstanding commodity derivative instruments designated as hedging instruments are as follows:
As at Dec. 3120212020
Type
(thousands)		Notional
amount
sold		Notional
amount
purchased		Notional
amount
sold		Notional
amount
purchased
Electricity (MWh)(1)
— — 95 — 
(1) Excludes the long-term power sale - US contract. For further details on this contract, refer to Note 15(B)(I)(c)(i).

During 2021, unrealized pre-tax losses of $1 million (2020 — $1 million gains, 2019 — $1 million gains) 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 Company’s outstanding commodity derivative instruments not designated as hedging instruments are as follows:
As at Dec. 3120212020
Type
(thousands)		Notional
amount
sold		Notional
amount
purchased		Notional
amount
sold		Notional
amount
purchased
Electricity (MWh)
46,139 14,951 12,944 8,258 
Natural gas (GJ)7,501 173,898 23,035 177,448 
Transmission (MWh)37 1,097 — 1,578 
Emissions (MWh)445 2,030 1,831 2,112 
Emissions (tonnes)350 350 2,160 2,365 
Coal (tonnes)
— 9,352 — 9,078 

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 Company’s borrowing costs. Changes in the cost of capital may also affect the feasibility of new growth initiatives.
The Company's credit facility and the Poplar Creek non-recourse bond are the only debt instruments subject to floating interest rates, which represent 3 per cent of the Company’s debt as at Dec. 31, 2021 (2020 – 7 per cent). Interest rate risk is managed with the use of derivatives. The Company's outstanding interest rate derivative instruments are as follows:
In 2021, the Company had interest rate swap agreements in place with a notional amount of US$150 million (2020 —US$150 million) whereby the Company 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 (2020 — 0.94 per cent) on the notional amount. The swaps are being used to hedge interest rate exposure on a highly probable future US$400 million fixed rate debt issuance, expected to occur in 2022.
In 2021, the Company had bond lock agreements in place with a total notional amount of US$150 million (2020 — $75 million) whereby on the pricing date, if the difference between the underlying 1.375 per cent US Treasury bond (2020 — 5.75 per cent Government of Canada bond) and the forward bond yield (2020 — $150 million forward yield 1.20 per cent) is positive, the Company receives settlement. If the difference is negative, the Company pays settlement. The bond lock is being used to hedge interest rate exposure on a highly probable future US$400 million (2020 —$150 million) fixed rate debt issuance. The $75 million bond lock outstanding at Dec. 31, 2020, was settled in 2021.

There were no interest rate derivative instruments outstanding in 2019.





TRANSALTA CORPORATION F51

Notes to Consolidated Financial Statements
LIBOR reform could impact interest rate risk with respect to the Company'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, and includes appropriate fallback language to replace these benchmark rates if a benchmark transition event were to occur. Currently there are no drawings on the facility. The non-recourse bond references the three-month CDOR: however, only the six- and 12-month CDOR have been discontinued with no expectation to stop publishing other CDOR rates at this time.

In addition, the Company has interest rate swap agreements in place with a notional amount of US$150 million referencing the three-month LIBOR, expected to settle in the third quarter of 2022. The cessation date for three-month LIBOR is June 30, 2023.

c. Currency Rate Risk 
The Company 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 Company 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 Company'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 Company’s net investment in foreign subsidiaries, the Company 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 Company’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 (2020 — US$370 million).
ii. Cash Flow Hedges
The Company 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.
As at Dec. 3120212020
Notional
amount
sold		Notional
amount
purchased		Fair value
liability		MaturityNotional
amount
sold		Notional
amount
purchased		Fair value liabilityMaturity
Foreign exchange forward contracts - foreign-denominated receipts/expenditures
CAD10 USD8 — 2022 CAD71 USD54 (2)2021 
AUD19 USD14 — 2022 — — — — 

iii. Non-Hedges
The Company also uses foreign currency contracts to manage its expected foreign operating cash flows. Hedge accounting is not applied to these foreign currency contracts.




TRANSALTA CORPORATION F52
Notes to Consolidated Financial Statements
As at Dec. 31 2021 2020
Notional
amount
sold		Notional
amount
purchased		Fair value
asset
(liability)		MaturityNotional
amount
sold		Notional
amount
purchased		Fair value
asset
(liability)		Maturity
Foreign exchange forward contracts – foreign-denominated receipts/expenditures
AUD28 CAD26 (5)2022-2025AUD197 CAD181 (14)2021 - 2024
USD271 CAD357 8 2022-2025USD47 CAD72 9 2021 - 2024
AUD4 USD3 — 2021 
CAD1 EUR1 — 2021 
Foreign exchange forward contracts – foreign-denominated debt
CAD191 USD150 1 2022 CAD191 USD150 2 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 Company’s functional currency, is outlined below. The sensitivity analysis has been prepared using management’s assessment that an average three cent (2020 — three cent, 2019 — three cent) increase or decrease in these currencies relative to the Canadian dollar is a reasonable potential change over the next quarter.
Year ended Dec. 31202120202019
Currency
Net earnings
increase
(decrease)(1)
OCI gain(1)(2)
Net earnings
decrease(1)
OCI gain(1)(2)
Net earnings
decrease(1)
OCI gain(1)(2)
USD(13)1 (8)1 (18)2 
AUD1 — (4)— (6)— 
Total(12)1 (12)1 (24)2 
(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.

II. Credit Risk
Credit risk is the risk that customers or counterparties will cause a financial loss for the Company by failing to discharge their obligations, and the risk to the Company associated with changes in creditworthiness of entities with which commercial exposures exist. The Company 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 Company 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 Company 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 Company 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 Company’s maximum exposure to credit risk without taking into account collateral held, including the distribution of credit ratings, as at Dec. 31, 2021:
 
Investment grade
 (Per cent)
Non-investment grade
 (Per cent)
Total
 (Per cent)
Total
amount
Trade and other receivables(1,2)
89 11 100 651 
Long-term finance lease receivable100 — 100 185 
Risk management assets(1)
86 14 100 707 
Total   1,543 
 
(1) Letters of credit and cash and cash equivalents are the primary types of collateral held as security related to these amounts. 
(2) Includes loan receivable with a counterparty that has no external credit rating. Refer to Note 22 for further details.





TRANSALTA CORPORATION F53

Notes to Consolidated Financial Statements
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 Company did not have significant expected credit losses as at Dec. 31, 2021.

The Company’s maximum exposure to credit risk at Dec. 31, 2021, 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, 2021, was $37 million (2020 — $22 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., offtakers).

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.

III. Liquidity Risk
 
Liquidity risk relates to the Company’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, 2021, TransAlta maintains an investment grade rating from one credit rating agency and below investment grade ratings from two credit rating agencies. Between 2022 and 2024, the Company has approximately $1 billion of debt maturing, comprised of approximately $515 million of recourse debt, with the balance mainly related to scheduled non-recourse debt repayments and the classification of the Kent Hills Wind LP bond as current.
Collateral is posted based on negotiated terms with counterparties, which can include the Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’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 Company does not use derivatives or hedge accounting to manage liquidity risk.





TRANSALTA CORPORATION F54
Notes to Consolidated Financial Statements
A maturity analysis of the Company's financial liabilities is as follows:
 202220232024202520262027 and thereafterTotal
Accounts payable and accrued liabilities689 — — — — — 689 
Long-term debt(1)
Debentures— — — — — 251 251 
Senior Notes511 — — — — 383 894 
Non-recourse — Hydro— 45 — — — — 45 
Non-recourse — Wind & Solar263 49 52 54 51 283 752 
Non-recourse — Gas44 45 47 59 61 855 1,111 
Tax equity financing15 15 14 14 15 68 141 
Other3 1 — — — — 4 
Exchangeable securities(2)
— — — 750 — — 750 
Commodity risk management (assets)
   liabilities		(45)(35)(117)(95)1 (2)(293)
Other risk management (assets) liabilities(2)(3)(3)1 — (1)(8)
Lease liabilities(3)
(6)4 3 3 3 93 100 
Interest on long-term debt and lease
  liabilities(4)
149 120 115 109 104 787 1,384 
Interest on exchangeable securities(2, 4)
53 53 62 — — — 168 
Dividends payable62 — — — — — 62 
Total1,736 294 173 895 235 2,717 6,050 
(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 2022.
(4) Not recognized as a financial liability on the Consolidated Statements of Financial Position.

IV. Equity Price Risk
a. Total Return Swaps 
The Company has certain compensation, deferred and restricted share unit programs, the values of which depend on the common share price of the Company. The Company 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 Company’s common shares at the end of each quarter.
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
202220232024202520262027 and thereafter
Cash flow hedges     
Foreign currency forward contracts
        Notional amount ($ millions)
                 CAD/USD8 — — — — — 
                 AUD/USD14 — — — — — 
        Average Exchange Rate
                 CAD/USD0.7893 — — — — — 
                 AUD/USD0.7352 — — — — — 
Commodity derivative instruments
   Electricity
        Notional amount (thousands MWh)3,329 3,329 3,338 2,628 — — 
        Average price ($ per MWh)71.95 73.76 75.6 77.49 — — 





TRANSALTA CORPORATION F55

Notes to Consolidated Financial Statements
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, 2021
Notional amountCarrying amountLine item in the statement of financial positionChange in fair value used for measuring ineffectiveness
Commodity price risk
Cash flow hedges
Physical power sales
13 MMWh
285 Risk management assets(181)
Interest rate risk
Cash flow hedges
Interest rate swap
USD300
3 Risk management assets3 
Foreign currency risk
Cash flow hedges
Foreign-denominated expenditures
USD8
— Risk management assets— 
Foreign-denominated expenditures
USD14
— Risk management assets— 
Net investment hedges
Foreign-denominated debt
USD370
CAD473
Credit facilities, long-term debt and lease liabilities— 

As at Dec. 31, 2020
Notional amountCarrying amountLine item in the statement of financial positionChange 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 liabilities3 
Interest rate swap
CAD75
(4)Risk management liabilities4 
Foreign currency risk
Net investment hedges
Foreign-denominated debt
USD370
CAD472
Credit facilities, long-term debt and lease liabilities11 




TRANSALTA CORPORATION F56
Notes to Consolidated Financial Statements
The impact of the hedged items on the statement of financial position is as follows:
As at Dec. 3120212020
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		(181)226 (33)417 
Interest rate risk
Cash flow hedges
Interest expense on long-term
   debt		32719
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		— (35)11 (21)
(1) Included in AOCI.

The hedging loss 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, 2021
  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(268)Revenue(13)Revenue— 
Foreign exchange forwards on
  project hedges		— Property, plant
  and equipment		1 Foreign exchange
  (gain) loss		— 
Forward starting interest rate
  swaps		13 Interest expense4 Interest expense— 
OCI impact(255)OCI impact(8)Net earnings impact— 
Over the next 12 months, the Company estimates that approximately $25 million of after-tax gain 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, 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 contracts41 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 impact28 OCI impact(141)Net earnings impact— 





TRANSALTA CORPORATION F57

Notes to Consolidated Financial Statements
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 contracts77 Revenue(59)Revenue— 
Forward starting interest rate
  swaps		— Interest expense6 Interest expense— 
OCI impact77 OCI impact(53)Net earnings impact— 

II. Effect of Non-Hedges
For the year ended Dec. 31, 2021, the Company recognized a net unrealized gain of $97 million (2020 — gain of $43 million, 2019 — gain of $33 million) related to commodity derivatives.

For the year ended Dec. 31, 2021, a gain of $6 million (2020 — gain of $11 million, 2019 —gain of $24 million) related to foreign exchange and other derivatives was recognized, which consists of net unrealized gains of $4 million (2020 — loss of $2 million, 2019 — gain of $6 million) and net realized gains of $2 million (2020 — gains of $13 million, 2019 — gains of $18 million), respectively.

F. Collateral
 
I. Financial Assets Provided as Collateral
 
At Dec. 31, 2021, the Company provided $55 million (2020 – $49 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, 2021, the Company held $18 million (2020 – nil) in cash collateral associated with counterparty obligations. Under the terms of the contracts, the Company 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 Company’s senior unsecured credit rating as determined by certain major credit rating agencies. Certain of the Company’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, 2021, the Company had posted collateral of $356 million (2020 – $163 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 Company having to post an additional $120 million (2020 – $85 million) of collateral to its counterparties.





TRANSALTA CORPORATION F58
Notes to Consolidated Financial Statements
17. Inventory
The components of inventory are as follows:
As at Dec. 3120212020
Parts and materials82 107 
Coal27 83 
Deferred stripping costs— 8 
Natural gas3 2 
Purchased emission credits(1)
55 38 
Total167 238 
(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.

No inventory is pledged as security for liabilities.

Carbon compliance costs are regulated costs that the business incurs as a result of greenhouse gas emissions generated from our operating units. TransAlta’s exposure to carbon compliance costs is mitigated through the use of eligible emission credits generated from the Company’s Wind and Solar and Hydro segments, as well as, purchasing emission credits from the market at prices lower than the regulated compliance price of carbon. Emission credits generated from our Alberta business have no recorded book value but are expected to be used to offset emission obligations from our gas facilities located in Canada in the future when the compliance price of carbon is expected to increase, resulting in a reduced cash cost for carbon compliance. At Dec. 31, 2021, the Company currently holds 2,033,752 purchased emission credits (2020 — 1,434,761) recorded at $55 million (2020 — $38 million) and approximately 1,922,973 (2020 — 1,211,230) emission credits with no recorded book value.

The change in inventory is as follows:
20212020
Balance, Jan. 1238 251 
Net additions (use)22 26 
Write-downs, coal (65)(37)
Write-downs, parts and materials(28)— 
Change in foreign exchange rates— (2)
Balance, Dec. 31167 238 

With the decision in 2020 to adjust the useful life of the Highvale mine assets to align with the Company's conversion to gas plans, the standard cost of coal increased during 2021 and 2020 as a result of increased depreciation costs and reduced coal consumption. During the same period, as the cost of the coal was not expected to be recovered based on power pricing, the Company recognized a $65 million (2020 — $37 million) write-down to net realizable value on its internally produced coal inventory for the year ended Dec. 31, 2021, of which $48 million relates to increased depreciation from the accelerated closure of the mine.

In addition, OM&A costs included a write-down of $28 million, for parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities. With the accelerated shutdown of the Highvale mine and full conversion to natural gas completed in 2021. It was determined that a portion of the coal-related parts and materials inventory would not be utilized in the operations of our converted natural gas facilities and therefore the value was adjusted down to the expected net realizable amounts for the end of 2021.





TRANSALTA CORPORATION F59

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:
 LandRenewable
generation
Gas generation(1)
Energy Transition(1)
Assets under
construction
Capital spares
and other(2)
Total
Cost       
As at Dec. 31, 2019, as previously reported91 3,574 1,671 7,342 228 489 13,395 
Adjustments due to re-segmentation— — 2,402 (2,402)— — — 
As at Dec 31, 2019, adjusted91 3,574 4,073 4,940 228 489 13,395 
Additions— — — — 478 8 486 
Acquisitions (Note 4)
— — 1 — — — 1 
Disposals(2)— — (1)— (2)(5)
Impairment (Note 7)(9)(2)— (69)— (1)(81)
Revisions and additions to decommissioning
   and restoration costs (Note 23)
— 8 1 85 — — 94 
Retirement of assets— (7)(47)(3)— (1)(58)
Change in foreign exchange rates(1)(14)45 (39)— 6 (3)
Transfers17 33 (138)(12)(211)(120)(431)
As at Dec. 31, 2020, adjusted96 3,592 3,935 4,901 495 379 13,398 
Additions— — — — 478 2 480 
Acquisitions (Note 4)— 146 — — — — 146 
Disposals(1)— (2)(74)(2)— (79)
Impairment (Note 7)— (15)(2)(468)(91)(13)(589)
Revisions and additions to decommissioning
   and restoration costs (Note 23)
— 129 6 — — — 135 
Retirement of assets— (15)(57)(49)— — (121)
Change in foreign exchange rates— 3 (25)2 — (6)(26)
Transfers1 303 232 201 (696)4 45 
As at Dec. 31, 202196 4,143 4,087 4,513 184 366 13,389 
Accumulated depreciation
As at Dec. 31, 2019, as previously reported— 1,284 900 4,836 — 168 7,188 
Adjustments due to re-segmentation— — 1,137 (1,137)— — — 
As at Dec 31, 2019, adjusted— 1,284 2,037 3,699 — 168 7,188 
Depreciation— 141 258 304 — 14 717 
Retirement of assets— (5)(43)(3)— — (51)
Disposals— — — (1)— (1)(2)
Change in foreign exchange rates— (4)18 (37)— 2 (21)
Transfers— — (212)(29)— (14)(255)
As at Dec. 31, 2020, adjusted— 1,416 2,058 3,933 — 169 7,576 
Depreciation— 154 184 264 — 12 614 
Retirement of assets— (9)(55)(48)— — (112)
Disposals— — (1)(72)— — (73)
Change in foreign exchange rates— — (8)2 — (1)(7)
Transfers— — — 71 — — 71 
As at Dec. 31, 2021— 1,561 2,178 4,150 — 180 8,069 
Carrying amount       
As at Dec. 31, 2019, adjusted91 2,290 2,036 1,241 228 321 6,207 
As at Dec. 31, 2020, adjusted96 2,176 1,877 968 495 210 5,822 
As at Dec. 31, 202196 2,582 1,909 363 184 186 5,320 
(1) The gas generation and energy transition includes the previously disclosed coal generation and mining property and equipment categories.
(2) Includes major spare parts and stand-by equipment available, but not in service and spare parts used for routine, preventive or planned maintenance.






TRANSALTA CORPORATION F60
Notes to Consolidated Financial Statements
A. Renewable Generation
During 2021, the Company acquired North Carolina Solar (Refer to Note 4 for further details).

During the third quarter of 2021, Kent Hills 2 had a tower collapse resulting in an impairment of $2 million. Following extensive independent engineering assessments and root cause failure analysis, the Company announced on Jan. 11, 2022, that all 50 turbine foundations at the Kent Hills 1 and Kent Hills 2 sites require a full foundation replacement. As the turbines will not be returning to service until the foundations are replaced, the foundations were written off, resulting in an increase in depreciation of $12 million.

Transfers from assets under construction in 2021 are related to the Windrise wind facility of $255 million, Kent Hills wind rehabilitation project of $7 million and the balance is related to other wind and hydro facilities. Transfers between the classifications of PP&E in 2020 relate to the WindCharger project and planned major maintenance.

B. Gas Generation
During 2021, the Company completed the full conversion of Keephills Unit 2, Keephills Unit 3 and Sundance Unit 6 from thermal coal to natural gas. Transfers from assets under construction of $200 million relates to the planned coal to gas conversions and the balance is related to the Australian and US gas facilities.

During 2019, 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.

Transfers out of PP&E in 2020 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. Transfers between the classifications of PP&E in 2020 relate to the Sundance Unit 6 conversion to gas.

C. Energy Transition Generation
Keephills Unit 1, Sundance Unit 5 and Sundance Unit 3 were retired from service effective Dec. 31, 2021, Nov. 1, 2021, and July 31, 2020, respectively. Sundance Unit 4 will be retired effective April 1, 2022. During 2021, the Company sold equipment related to coal generation that resulted in a gain of sale of $23 million. Centralia Unit 1 was retired from service effective Dec. 31, 2020, as originally planned.

Transfers from assets under construction in 2021 are mainly related to Keephills Unit 1 of $20 million, Sundance Unit 5 of $78 million and the mining property and equipment related to SunHills and Centralia of $100 million. The Company transferred certain generation assets from the Energy Transition segment to assets held for sale as a result of its assessment under IFRS 5 — Non-current Assets Held for Sale and Discontinued Operations. As part of this review there were no impairment charges recognized against the carrying value of $25 million. Transfers between the classifications of PP&E in 2020 relate to the Centralia land purchase.

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 Company'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.

D. Assets Under Construction
Initial construction activities on the Garden Plain wind project started in the third quarter of 2021. In addition, the Company commenced construction in the fourth quarter of 2021 on the Northern Goldfields Solar Project. The Northern Goldfields Solar Project comprises the 27 MW Mount Keith Solar Farm, 11 MW Leinster Solar Farm, 10MW/5MWh Leinster battery energy storage system and interconnecting transmission infrastructure, all of which will be integrated into our existing 169 MW Southern Cross Energy North remote network in Western Australia. Upon completion of construction, these will be transferred to finance lease receivables.

Additions in 2021 are related to the Windrise wind project of $96 million (2020 — $156 million), White Rock Wind Projects of $32 million (2020 — nil), Garden Plain wind project of $38 million (2020 — nil), the Kaybob cogeneration project of $14 million (2020 — $31 million), coal to gas conversions of $91 million (2020 — $93 million) and planned major maintenance expenditures. In 2020, the additions included the WindCharger battery storage project of $6 million and Centralia mine land of $17 million.

Transfers out to assets held for sale include $25 million related to salvage values for Sundance Unit 5 repowering project.

In 2021, the Company capitalized $14 million (2020 — $8 million) of interest to PP&E in at a weighted average rate of 6.0 per cent (2020 — 6.0 per cent).




TRANSALTA CORPORATION F61

Notes to Consolidated Financial Statements

19. Right-of-Use Assets
The Company 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:
LandBuildingsVehiclesEquipmentPipelineTotal
As at Dec. 31, 201958 16 2 25 45 146 
Additions3 13 — — — 16 
Depreciation(3)(5)(1)(9)(3)(21)
As at Dec. 31, 202058 24 1 16 42 141 
Additions— 1 — — — 1 
Acquisitions (Note 4)13 — — — — 13 
Depreciation(3)(5)— (2)(1)(11)
Disposal of assets (Note 4)— — — — (41)(41)
Transfers— — — (8)— (8)
As at Dec. 31, 202168 20 1 6 — 95 

On June 30, 2021, the Company closed the sale of the Pioneer Pipeline to ATCO. As part of the transaction, the natural gas transportation agreement with the Pioneer Pipeline Limited Partnership was terminated, which resulted in the derecognition of the right-of-use asset of $41 million and lease liability of $43 million related to the pipeline, resulting in a gain of $2 million.

For the year ended Dec. 31, 2021, TransAlta paid $15 million (2020 — $33 million) related to recognized lease liabilities, consisting of $7 million in interest (2020 — $8 million) and $8 million (2020 — $25 million) in principal repayments.

Short-term leases (term of less than 12 months) and leases with total lease payments below the Company's capitalization threshold do not require recognition as lease liabilities and right-of-use assets.

Some of the Company'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, 2021, the Company expensed $6 million (2020 — $7 million) in variable land lease payments for these leases. For further information regarding leases refer to Note 5, 11, 24 and 36.





TRANSALTA CORPORATION F62
Notes to Consolidated Financial Statements
20. Intangible Assets
A reconciliation of the changes in the carrying amount of intangible assets is as follows:
 Power
sale
contracts		Software
and other		Intangibles
under
development		Coal rightsTotal
Cost     
As at Dec. 31, 2019250 378 11 149 788 
Additions— — 14 — 14 
Acquisition (Note 4)37 — — — 37 
Disposals— (1)— — (1)
Change in foreign exchange rates(2)— — — (2)
Transfers(16)35 (22)— (3)
As at Dec. 31, 2020269 412 3 149 833 
Additions— — 9 — 9 
Impairment (Note 7)— — — (17)(17)
Change in foreign exchange rates— (2)— — (2)
Transfers— 12 (8)— 4 
As at Dec. 31, 2021269 422 4 132 827 
Accumulated amortization     
As at Dec. 31, 2019107 246 — 117 470 
Amortization15 28 — 8 51 
Disposals— (1)— — (1)
Transfers1 (1)— — — 
As at Dec. 31, 2020123 272 — 125 520 
Amortization17 27 — 7 51 
As at Dec. 31, 2021140 299 — 132 571 
Carrying amount     
As at Dec. 31, 2019143 132 11 32 318 
As at Dec. 31, 2020146 140 3 24 313 
As at Dec. 31, 2021129 123 4 — 256 

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. 3120212020
Hydro258 258 
Wind and Solar175 175 
Energy Marketing30 30 
Total goodwill463 463 

For the purposes of the 2021 goodwill impairment review, the Company 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 Company's long-range forecasts for the period extending to the last planned asset retirement in 2052. The resulting fair value measurement is categorized within Level III of the fair value hierarchy. In 2021, the Company relied on the recoverable amounts determined in 2019 for the Hydro and Energy Marketing segments in performing the 2021 goodwill impairment review. No impairment of goodwill arose for any segment.





TRANSALTA CORPORATION F63

Notes to Consolidated Financial Statements
The key assumptions impacting the determination of fair value for the Wind and Solar and Hydro segments are the following:
▪Discount rates used for the goodwill impairment calculation in 2021 for the Wind and Solar segment ranged from 5.0 per cent to 6.4 per cent (2020 – 4.8 per cent to 6.3 per cent).
▪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 2021 models ranged between $17 to $136 per MWh during the forecast period (2020 – $6 to $160 per MWh).

22. Other Assets
The components of other assets are as follows:
As at Dec. 3120212020
South Hedland prepaid transmission access and distribution costs65 70 
Project development costs29 25 
Long-term prepaids and other assets48 59 
Loan receivable55 52 
Total other assets197 206 
Included in the Consolidated Statements of Financial Position as:
Total current other assets (Note 14)55 — 
Total long-term other assets142 206 
Total other assets197 206 

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.

Project development costs primarily include the project costs for US wind and Australian development projects. Some project costs were written off in 2021 due to the uncertainty on timing of when the projects will proceed (see Note 7).

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 Company's subsidiary, Kent Hills Wind LP, of $55 million (2020 – $52 million) which is net of the Kent Hills Wind bond financing proceeds to its 17 per cent partner. The unsecured loan bears interest at 4.55 per cent, with interest payable quarterly, commencing on Dec. 31, 2017 and matures in October 2022; as such, it was moved to current assets (Note 14).




TRANSALTA CORPORATION F64
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 provisionsTotal
Balance, Dec. 31, 2019501 45 546 
Liabilities incurred1 34 35 
Liabilities settled(18)(19)(37)
Accretion30 — 30 
Acquisition of liabilities1 — 1 
Revisions in estimated cash flows61 11 72 
Revisions in discount rates(1)
36 — 36 
Reversals— (6)(6)
Change in foreign exchange rates(4)— (4)
Balance, Dec. 31, 2020608 65 673 
Liabilities incurred8 22 30 
Liabilities settled (Note 36)(18)(62)(80)
Accretion32 — 32 
Acquisition of liabilities2 — 2 
Revisions in estimated cash flows167 12 179 
Revisions in discount rates(6)— (6)
Reversals— (3)(3)
Balance, Dec. 31, 2021793 34 827 
(1) 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		OtherTotal
Balance, Dec. 31, 2020608 65 673 
Current portion21 38 59 
Non-current portion587 27 614 
Balance, Dec. 31, 2021793 34 827 
Current portion35 13 48 
Non-current portion758 21 779 

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 $1.6 billion, which will be incurred between 2022 and 2072. The majority of the costs will be incurred between 2025 and 2050.
In 2021, the Company adjusted the wind assets decommissioning and restoration provision as estimates were updated after the review of a recent engineering study on the decommissioning costs of the wind sites. The Company's current best estimate of the decommissioning and restoration provision increased by $120 million. The change in estimate is unrelated to the tower failure identified in the fourth quarter of 2021. The Company also increased the decommissioning and restoration provision by approximately $47 million for the Sundance and Keephills Units included in the Gas and Energy Transition segments to reflect the change in the timing of the expected reclamation work resulting from asset retirements and change in useful lives. These changes resulted in an increase in the related assets in PP&E.
At Dec. 31, 2021, the Company had provided a surety bond in the amount of US$147 million (2020 – US$147 million) in support of future decommissioning obligations at the Centralia coal mine. At Dec. 31, 2021, the Company had provided letters of credit in the amount of $188 million (2020 – $131 million) in support of future decommissioning obligations at the Highvale mine.




TRANSALTA CORPORATION F65

Notes to Consolidated Financial Statements
In the fourth quarter of 2020, the Company adjusted the Sarnia decommissioning and restoration provision to reflect an updated engineering study. The Company'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 Company 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 Company'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.

B. Other Provisions
 
Other provisions also include provisions arising from ongoing business activities and include amounts related to commercial disputes between the Company 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 Company’s ability to settle the provisions in the most favourable manner.
During the third quarter of 2021, an onerous contract provision for future royalty payments of $14 million was recognized as a result of a decision to accelerate the plans to shut down the Highvale mine, with the effect that any remaining future royalty payments related to the extraction of coal has no future economic benefit. Payments required under the royalty contract will continue through 2023. At Dec. 31, 2021, the remaining balance of the provision was $14 million.
During the fourth quarter of 2020, an onerous contract provision of $29 million was recognized as a result of a decision to accelerate plans to eliminate coal as a fuel source at the Sheerness facility by the end of 2021. The last coal shipment was received during the first quarter of 2021, while payments required under the contract will continue until 2025. At Dec. 31, 2021, the remaining balance of the provision was $14 million.




TRANSALTA CORPORATION F66
Notes to Consolidated Financial Statements
24. Credit Facilities, Long-Term Debt and Lease Liabilities
A. Amounts Outstanding
 
The amounts outstanding are as follows:
As at Dec. 3120212020
 SegmentMaturityCurrencyCarrying
value		Face
value
Interest(1)
Carrying
value		Face
value		Interest
Credit facilities
Committed syndicated
   bank facility(2)
Corporate2025CAD— — — %114 114 2.7 %
Debentures
7.3% Medium term notes
Corporate2029CAD110 110 7.3 %109 110 7.3 %
6.9% Medium term notes
Corporate2030CAD141 141 6.9 %140 141 6.9 %
Senior notes(3)
6.5% Senior notes
Corporate2040USD378 383 6.5 %380 383 6.5 %
4.5% Senior notes
Corporate2022USD510 511 4.5 %506 511 4.5 %
Non-recourse
Melancthon Wolfe Wind LP
   bond		Wind & Solar2028CAD235 237 3.8 %268 270 3.8 %
New Richmond Wind LP
  bond		Wind & Solar2032CAD120 121 4.0 %127 128 4.0 %
Kent Hills Wind LP bond(4)
Wind & Solar2033CAD221 221 4.5 %230 233 4.5 %
Windrise Wind LP bondWind & Solar2041CAD171 173 3.4 %— — — %
Pingston bondHydro2023CAD45 45 3.0 %45 45 3.0 %
TAPC Holdings LP bond
  (Poplar Creek)
Gas2030CAD102 104 4.4 %111 113 4.5 %
TEC Hedland PTY Ltd bond(5)
Gas2042AUD732 742 4.1 %772 782 4.1 %
TransAlta OCP LP bondGas2030CAD263 265 4.5 %284 287 4.5 %
Tax equity financing
Big Level & Antrim(6)
Wind & Solar2029USD106 112 6.6 %112 119 6.6 %
Lakeswind(7)
Wind & Solar2029USD18 18 10.5 %22 22 10.5 %
North Carolina Solar(8)
Wind & Solar2028USD11 11 7.3 %— — — 
OtherCorporate2023CAD4 4 5.9 %7 6 5.9 %
Total long-term debt3,167 3,198  3,227 3,264  
Lease liabilities100   134   
 3,267   3,361   
Less: current portion of long-term debt(837)  (97)  
Less: current portion of lease liabilities(7)  (8)  
Total current long-term debt and lease liabilities(844)  (105)  
Total credit facilities, long-term debt and lease liabilities2,423   3,256   
(1) Interest is 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, 2021 — US$700 million (Dec. 31, 2020 — US$700 million).
(4) Kent Hills Wind LP bond is classified as a current liability. Refer to section B - Restrictions Related to Non-Recourse Debt and Other Debt, for more information.
(5) AU face value at Dec. 31, 2021 — AU$800 million related to the TEC offering (2020 — AU$800 million).
(6) US face value at Dec. 31, 2021 — US$88 million (2020 — US$94 million).
(7) US face value at Dec. 31, 2021 — US$14 million (2020 — US$16 million).
(8) US face value at Dec. 31, 2021 — US$9 million (2020 — nil).







TRANSALTA CORPORATION F67

Notes to Consolidated Financial Statements
The Company's credit facilities are summarized in the table below:
As at Dec. 31, 2021Facility
size		UtilizedAvailable
capacity		Maturity
date
Outstanding letters of credit(1)
Actual drawings
TransAlta Corporation
Committed syndicated bank facility(2)
1,250 618 — 632 Q2 2025
Canadian committed bilateral credit facilities240 186 — 54 Q2 2023
TransAlta Renewables
Committed credit facility(2)
700 98 — 602 Q2 2025
Total2,190 902 — 1,288 
(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, 2021, TransAlta provided cash collateral of $55 million.
(2) Includes letters of credit issued under the demand facilities for TransAlta and TransAlta Renewables.

The Company has $2 billion (2020 — $2 billion) of committed syndicated bank facilities and $0.2 billion of committed bilateral credit facilities, of which $1.3 billion was available as at Dec. 31, 2021 (2020 — $1.5 billion) and including the undrawn letters of credit are the primary source for short-term liquidity after the cash flow generated from the Company's business. This includes a $1.3 billion credit facility that was converted into a facility with a Sustainability Linked Loan ("SLL") and that was extended to June 30, 2025. The facility's financing terms will align the cost of borrowing to TransAlta's greenhouse gas emission reductions and gender diversity targets, which are part of the Company's overall plan for environment, social and governance. The SLL will have a cumulative pricing adjustment to the borrowing costs on the facilities and a corresponding adjustment to the standby fee (the "Sustainability Adjustment"). Depending on performance against interim targets that have been set for each year of the credit facility term, the Sustainability Adjustment is structured as a two-way mechanism and could move either up, down or remain unchanged for each sustainability performance target based on performance. In addition, the Company's committed bilateral credit facilities were also extended to June 30, 2023. Interest rates on the credit facilities vary depending on the option selected – Canadian prime, bankers' acceptances, USD LIBOR or US base rate – in accordance with a pricing grid that is standard for such facilities.
The Company is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $1.3 billion available under the credit facilities, the Company also has $947 million of available cash and cash equivalents and $17 million ($17 million principal portion) in cash restricted for repayment of the OCP bonds (refer to section E below).
TransAlta has letters of credit of $157 million issued from uncommitted demand facilities; these obligations are backstopped and reduce the available capacity on the committed credit facilities.

Debentures
On Nov. 25, 2020, the Company redeemed $400 million of its then due 5.0 per cent medium term notes.

Senior notes
A total of US$370 million (2020 — US$370 million) of the senior notes has been designated as a hedge of the Company’s net investment in US foreign operations.

Non-recourse debt
On Dec. 6, 2021, TransAlta completed a secured green bond offering by way of private placement for approximately $173 million (the "Offering"). The Offering is secured by a first ranking charge over all assets of the issuer, Windrise Wind LP, and the bonds amortize and bear interest from their date of issue at a rate of 3.41 per cent per annum and mature on Sept. 30, 2041. Payments on the bonds will be interest-only to and including Dec. 31, 2022, with quarterly blended payments of principal and interest commencing on March 31, 2023. TransAlta intends to use proceeds of the Offering to finance or refinance eligible green projects, including renewable energy facilities and to fund a construction reserve account.






TRANSALTA CORPORATION F68
Notes to Consolidated Financial Statements
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 to repay indebtedness on the credit facility and to fund future growth opportunities within TransAlta Renewables. The TEC Offering has a rating of BBB by Kroll Bond Rating Agency.

Tax Equity
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 and North Carolina Solar acquired tax equity which were initially recognized at their fair values. Tax equity financing balances are reduced by the value of tax benefits (production tax credits, tax depreciation and investment tax credits) allocated to the investor and by cash distributions paid to the investor for their share of net earnings and cash flow generated at each project. Tax equity financing balances are increased by interest recognized at the implicit interest rate. 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 Company anticipates the maturity dates of the tax equity financings will be: Big Level and Antrim - on March 31, 2030, 10 years from commercial operation of the projects; Lakeswind - March 31, 2029, and North Carolina Solar on Dec. 31, 2028.

Other
Other debt 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.

TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at Dec. 31, 2021, the Company was in compliance with all debt covenants except the Kent Hills non-recourse bond as discussed below.
B. Restrictions Related to Non-Recourse Debt and Other Debt
 
The Melancthon Wolfe Wind LP, Pingston, TAPC Holdings LP, New Richmond Wind LP, Kent Hills Wind LP, TEC Hedland Pty Ltd notes, Windrise Wind LP and TransAlta OCP LP non-recourse bonds with a carrying value of $1.9 billion as at Dec. 31, 2021 (Dec. 31, 2020 — $1.8 billion) are subject to customary financing conditions and covenants that may restrict the Company’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 fourth quarter of 2021, except the Kent Hills non-recourse bond as discussed below. However, funds in these entities that have accumulated since the fourth quarter test will remain there until the next debt service coverage ratio can be calculated in the first quarter of 2022. At Dec. 31, 2021, $67 million (Dec. 31, 2020 —$73 million) of cash was subject to these financial restrictions. At Dec. 31, 2021, Kent Hills cash in the amount of $6 million is not able to be distributed or accessed by other corporate entities, as discussed below.

Proceeds received from the TEC Notes in the amount of $3 million (AU$4 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.

As a result of the determination that all 50 foundations require replacement, as well as certain resulting amendments to applicable insurance policies, the Company has provided notice to BNY Trust Company of Canada, as trustee (the “Trustee”), for the approximately $221 million outstanding non-recourse project bonds (the “KH Bonds”) secured by, among other things, the Kent Hills 1, 2 and 3 wind sites, that events of default may have occurred under the trust indenture governing the terms of the KH Bonds. Upon the occurrence of any event of default, holders of more than 50 per cent of the outstanding principal amount of the KH Bonds have the right to direct the Trustee to declare the principal and interest on the KH Bonds and all other amounts due, together with any make-whole amount (Dec. 31, 2021 — $39 million), to be immediately due and payable and to direct the Trustee to exercise rights against certain collateral. The Company is in discussions with the Trustee and holders of the Kent Hills bonds to negotiate required waivers and amendments while the Company works to remedy the matters described in the notice. Although the Company expects that it will reach agreement with the Trustee and holders of the KH Bonds with respect to terms of an acceptable waiver and amendment, there can be no assurance that the Company will receive such waivers and amendments. Accordingly, the Company has classified the entire carrying value of the KH Bonds as a current liability as at Dec. 31, 2021.




TRANSALTA CORPORATION F69

Notes to Consolidated Financial Statements
C. Security
Non-recourse debts totalling $1.5 billion as at Dec. 31, 2021 (Dec. 31, 2020 — $1.4 billion) are each secured by a first ranking charge over all of the respective assets of the Company’s subsidiaries that issued the bonds, which include PP&E with total carrying amounts of $1.5 billion at Dec. 31, 2021 (Dec. 31, 2020 — $1 billion) and intangible assets with total carrying amounts of $78 million (Dec. 31, 2020 — $88 million). At Dec. 31, 2021, a non-recourse bond of approximately $103 million (Dec. 31, 2020 — $111 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 $263 million (Dec. 31, 2020 — $285 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 Company receives annual cash payments on or before July 31 of approximately $40 million (approximately $37 million, net to the Company), commencing on Jan. 1, 2017, and terminating at the end of 2030.

D. Principal Repayments
 
2022(1)
20232024202520262027 and thereafterTotal
Principal repayments(2)
836 155 113 127 127 1,840 3,198 
Lease liabilities(3)
(6)4 3 3 3 93 100 
 
(1) Includes the Kent Hills Wind LP non-recourse bonds. The successful receipt of waivers and amendments would extend principal repayments beyond 2022.
(2) Excludes impact of hedge accounting and derivatives.
(3) Lease liabilities include a lease incentive of $13 million, expected to be received in 2022.

E. Restricted Cash
At Dec. 31, 2021, the Company had nil (Dec. 31, 2020 – $9  million) in restricted cash related to the Big Level tax equity financing that is held in a construction reserve account. The proceeds were released from the construction reserve account in 2021.

The Company had $17 million (Dec. 31, 2020 – $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 2022.

The Company also had $53 million (Dec. 31, 2020 – $45 million) 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 $150 million and $100 million demand letters of credit facilities. Letters of credit issued by TransAlta Renewables are drawn on its uncommitted $150 million demand letter of credit facility.
Letters of credit are issued to counterparties under various contractual arrangements with the Company and certain subsidiaries of the Company. If the Company 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 Company 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, 2021, was $902 million (2020 – $621 million) with no (2020 – nil) amounts exercised by third parties under these arrangements.





TRANSALTA CORPORATION F70
Notes to Consolidated Financial Statements
25. Exchangeable Securities
On March 22, 2019, the Company entered into an Investment Agreement whereby Brookfield Renewable Partners or its affiliates (collectively "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").

Upon entering into the Investment Agreement and as required under the terms of the agreement, the Company 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.

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 atDec. 31, 2021Dec. 31, 2020
Carrying valueFace valueInterestCarrying valueFace valueInterest
Exchangeable debentures – due May 1, 20393353507 %3303507 %
Exchangeable preferred shares(1)
400 4007 %400 400 7 %
Total long-term debt735750730 750 
(1) Exchangeable preferred share dividends are reported as interest expense.

On Dec. 13, 2021, the Company declared a dividend of $7 million in aggregate for Exchangeable Preferred Shares at the fixed rate of 1.764 per cent, per share payable on Feb. 28, 2022. The Exchangeable Preferred Shares are considered debt for accounting purposes, and as such, dividends are reported as interest expense (Note 11).

B. Option to Exchange
As atDec. 31, 2021Dec. 31, 2020
DescriptionBase fair valueSensitivityBase fair valueSensitivity
Option to exchange – embedded derivative— 
+nil
-32
— 
+nil
-33

The Investment Agreement allows Brookfield the option, after Dec. 31, 2024, to exchange all of the outstanding exchangeable securities into an equity ownership interest of up to a maximum 49 per cent in an entity that has been formed to hold TransAlta’s Alberta Hydro Assets. 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 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 Company’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 per cent equity interest, Brookfield will be entitled to receive the balance of the redemption price in cash.





TRANSALTA CORPORATION F71

Notes to Consolidated Financial Statements
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 Dec. 31, 2021, Brookfield, through its affiliates, held, owned or had control over an aggregate of 35,425,696 common shares, representing approximately 13.1 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.

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. 3120212020
Defined benefit obligation (Note 31)228 282 
Long-term incentive accruals (Note 30)4 4 
Other21 12 
Total253 298 

The liability for pension and post-employment benefits and associated costs included in compensation expenses are impacted by estimates related to changes in key actuarial assumptions, including discount rates. As a result of increases in discount rates in 2021, largely driven by increases in market benchmark rates, the defined benefit obligation has decreased by $54 million to $228 million as at Dec. 31, 2021, from $282 million as at Dec. 31, 2020.

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. 3120212020
 
Common
shares
 (millions)
Amount
Common
shares
(millions)
Amount
Issued and outstanding, beginning of year269.8 2,896 277.0 2,978 
Purchased and cancelled under the NCIB— — (7.3)(79)
Effects of share-based payment plans— (3)— (3)
Stock options exercised1.2 8 0.1 — 
Issued and outstanding, end of year271.0 2,901 269.8 2,896 

B. Normal course issuer bid ("NCIB") Program
Shares purchased by the Company 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.

The following are the effects of the Company's purchase and cancellation of the common shares during the year:
For the year ended Dec. 3120212020
Total shares purchased(1)
— 7,352,600 
Average purchase price per share— $8.33 
Total cost— 61 
Weighted average book value of shares cancelled— 79 
Amount recorded in deficit— 18 
(1) As at Dec. 31, 2021, includes nil (2020 — 456,200) shares that were repurchased but were not cancelled due to timing differences between the transaction date and settlement date.





TRANSALTA CORPORATION F72
Notes to Consolidated Financial Statements
2021
On May 25, 2021, the Toronto Stock Exchange ("TSX") accepted the notice filed by the Company to implement an NCIB for a portion of our common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 common shares, representing approximately 7.16 per cent of its public float of common shares as at May 18, 2021. 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 TransAlta is authorized to make purchases under the NCIB commenced on May 31, 2021 and ends on May 30, 2022, or such earlier date on which the maximum number of common shares are purchased under the NCIB or the NCIB is terminated at the Company’s election. No common shares have been repurchased under the current and previous NCIB in 2021.

2020
On May 26, 2020, the Company announced that the TSX accepted the notice filed by the Company to implement an NCIB for a portion of its common shares. Pursuant to the NCIB, the Company was permitted to purchase up to a maximum of 14,000,000 common shares, representing approximately 7.02 per cent of its issued and common shares as at May 25, 2020.

C. Shareholder Rights Plan 
The Company 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 Company’s shareholders every three years for approval. It was last approved on April 26, 2019, and will need to be approved at the annual meeting of shareholders in 2022. 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 Company’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. 31202120202019
Net earnings (loss) attributable to common shareholders(576)(336)52 
Basic and diluted weighted average number of common shares outstanding (millions)271 275 283 
Net earnings (loss) per share attributable to common shareholders, basic and diluted(2.13)(1.22)0.18 

E. Dividends 
On Dec. 13, 2021, the Company declared a quarterly dividend of $0.05 per common share, payable on April 1, 2022.
There have been no other transactions involving common shares between the reporting date and the date of completion of these consolidated financial statements.





TRANSALTA CORPORATION F73

Notes to 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. 3120212020
Series
Number of shares
 (millions)
Amount
Number of shares
(millions)
Amount
Series A9.6 235 10.2 248 
Series B2.4 58 1.8 45 
Series C11.0 269 11.0 269 
Series E9.0 219 9.0 219 
Series G6.6 161 6.6 161 
Issued and outstanding, end of year38.6 942 38.6 942 

I. Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares Conversion 
On March 18, 2021, the Company announced that 1,417,338 of its 10.2 million Series A Cumulative Fixed Redeemable Rate Reset Preferred Shares ("Series A Shares") and 871,871 of its 1.8 million Series B Cumulative Redeemable Floating Rate Preferred Shares ("Series B Shares") were tendered for conversion, on a one-for-one basis, into Series B Shares and Series A Shares, respectively after having taken into account all election notices. As a result of the conversion, the Company had 9.6 million Series A Shares and 2.4 million Series B Shares issued and outstanding at March 31, 2021.

II. 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 Company, 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 Company 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, 2021, are as follows:
SeriesRate during term
Annual dividend
rate per share ($)
Next
conversion
date
Rate spread
over benchmark
 (per cent)
Convertible to
Series
AFixed0.71924 March 31, 20262.03 B
BFloating0.53866 March 31, 20262.03 A
CFixed1.00676 June 30, 20223.10 D
DFloating— — 3.10 C
EFixed1.29852 Sept. 30, 20223.65 F
FFloating— — 3.65 E
GFixed1.24700 Sept. 30, 20243.80 H
HFloating— — 3.80 G





TRANSALTA CORPORATION F74
Notes to Consolidated Financial Statements
B. Dividends 
The following table summarizes the value of the preferred share dividends declared in 2021 and 2020:
 Total dividends declared
Series
2021(1)
2020
A7 9 
B(2)
1 1 
C11 14 
E12 15 
G8 10 
Total for the year39 49 
(1) No dividends were declared in the first quarter of 2021 as the quarterly dividend related to the period covering the first quarter of 2021 was declared in December 2020.
(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. 13, 2021, the Company declared a quarterly dividend of $0.1798 per share on the Series A preferred shares, $0.1331 per share on the Series B preferred shares, $0.2517 per share on the Series C preferred shares, $0.3246 per share on the Series E preferred shares, and $0.3118 per share on the Series G preferred shares, all payable on March 31, 2022.


29. Accumulated Other Comprehensive Earnings
The components of, and changes in, accumulated other comprehensive earnings are as follows:
 20212020
Currency translation adjustment  
Opening balance, Jan. 1(21)(21)
Losses on translating net assets of foreign operations, net of reclassifications to net earnings,
   net of tax		(14)(11)
Gains on financial instruments designated as hedges of foreign operations, net of
   reclassifications to net earnings, net of tax
— 11 
Balance, Dec. 31(35)(21)
Cash flow hedges  
Opening balance, Jan. 1436 527 
Losses on derivatives designated as cash flow hedges, net of reclassifications to net earnings and
   to non-financial assets, net of tax(1)
(208)(91)
Balance, Dec. 31228 436 
Employee future benefits  
Opening balance, Jan. 1(66)(55)
Net actuarial gains (losses) on defined benefit plans, net of tax(2)
37 (11)
Balance, Dec. 31(29)(66)
Other  
Opening balance, Jan. 1(47)3 
Intercompany investments at FVOCI29 (50)
Balance, Dec. 31(18)(47)
Accumulated other comprehensive earnings146 302 
(1) Net of income tax of $57 million for the year ended Dec. 31, 2021 (2020 — $23 million).
(2) Net of income tax of $11 million for the year ended Dec. 31, 2021 (2020 — $3 million).





TRANSALTA CORPORATION F75

Notes to Consolidated Financial Statements
30. Share-Based Payment Plans
The Company 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 Company’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 Company’s share price over the three-year period and accrue dividends as additional units at the same rate as dividends paid on the Company’s common shares.
The pre-tax compensation expense related to PSUs and RSUs in 2021 was $14 million (2020 — $15 million, 2019 — $19 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 Company and fluctuates based on the changes in the value of the Company’s common shares in the marketplace. DSUs accrue dividends as additional DSUs at the same rate as dividends are paid on the Company’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 Company.
The Company 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 $3 million in 2021 (2020 — $1 million, 2019 — $2 million).
C. Stock Option Plans 
On May 4, 2021, the Company approved amendments to the Stock Option Plan to reduce the total aggregate number of common shares held in reserve for issuance under this program. The amendments reduce the aggregate total number of shares reserved for issuance to 14.5 million common shares as at March 31, 2021 (Dec. 31, 2020 — 16.5 million common shares). The Company is authorized to grant options to purchase up to an aggregate of 14.5 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 2021, the Company granted executive officers of the Company a total of 0.7 million stock options with a weighted average exercise price of $9.86 that vest after a three-year period and expire seven years after issuance (2020 — 0.7 million stock options at $9.17; 2019 — 1.4 million stock options at $5.65). The expense recognized relating to these grants during 2021 was approximately $2 million (2020 — approximately $2 million, 2019 — approximately $1 million).
The total options outstanding and exercisable under these stock option plans at Dec. 31, 2021, are outlined below:
 Options outstanding
Range of exercise prices(1)
($ per share)
Number of options (millions)
Weighted
average
remaining
contractual
life (years)
Weighted
average
exercise
price
 ($ per share)
5.00 - 9.00
3.2 4.27.54 
 (1) Options currently exercisable as at Dec. 31, 2021.





TRANSALTA CORPORATION F76
Notes to Consolidated Financial Statements
31. Employee Future Benefits
A. Description 
The Company sponsors registered pension plans in Canada and the US covering substantially all employees of the Company 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, 2021. 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, 2021.
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 Company. The Company 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 Company posted a letter of credit in March 2021 for the amount of $97 million to secure the obligations under the supplemental plan.
The Company 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, 2021, respectively. The measurement date used to determine the present value obligation for both plans was Dec. 31, 2021.
The Company 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.
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, 2021RegisteredSupplementalOtherTotal
Current service cost3 2 1 6 
Administration expenses1 — — 1 
Interest cost on defined benefit obligation12 2 — 14 
Interest on plan assets(8)— — (8)
Curtailment and amendment gain(7)— — (7)
Defined benefit expense1 4 1 6 
Defined contribution expense8 — — 8 
Net expense9 4 1 14 
Year ended Dec. 31, 2020RegisteredSupplementalOtherTotal
Current service cost5 2 1 8 
Administration expenses1 — — 1 
Interest cost on defined benefit obligation16 3 1 20 
Interest on plan assets(11)(1)— (12)
Curtailment and amendment gain(2)— — (2)
Defined benefit expense9 4 2 15 
Defined contribution expense9 — — 9 
Net expense18 4 2 24 




TRANSALTA CORPORATION F77

Notes to Consolidated Financial Statements

Year ended Dec. 31, 2019RegisteredSupplementalOtherTotal
Current service cost7 2 1 10 
Administration expenses2 — — 2 
Interest cost on defined benefit obligation19 3 1 23 
Interest on plan assets(12)(1)— (13)
Curtailment and amendment gain(3)— — (3)
Defined benefit expense13 4 2 19 
Defined contribution expense9 — — 9 
Net expense22 4 2 28 

C. Status of Plans
 
The status of the defined benefit pension and other post-employment benefit plans is as follows:
Year ended Dec. 31, 2021RegisteredSupplementalOtherTotal
Fair value of plan assets339 14 — 353 
Present value of defined benefit obligation(469)(101)(23)(593)
Funded status – plan deficit(130)(87)(23)(240)
Amount recognized in the consolidated financial statements:    
Accrued current liabilities(4)(6)(2)(12)
Other long-term liabilities(126)(81)(21)(228)
Total amount recognized(130)(87)(23)(240)

Year ended Dec. 31, 2020RegisteredSupplementalOtherTotal
Fair value of plan assets367 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)

D. Plan Assets
 
The fair value of the plan assets of the defined benefit pension and other post-employment benefit plans is as follows:
 RegisteredSupplementalOtherTotal
As at Dec. 31, 2019373 13 — 386 
Interest on plan assets11 1 — 12 
Net return on plan assets25 (1)— 24 
Contributions6 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, 2020367 14 — 381 
Interest on plan assets8 — — 8 
Net return on plan assets14 (1)— 13 
Contributions5 6 1 12 
Benefits paid(54)(5)(1)(60)
Administration expenses(1)— — (1)
As at Dec. 31, 2021339 14 — 353 





TRANSALTA CORPORATION F78
Notes to Consolidated Financial Statements
The fair value of the Company’s defined benefit plan assets by major category is as follows:
Year ended Dec. 31, 2021Level ILevel IILevel IIITotal
Equity securities    
Canadian— 29 4 33 
US— 20 — 20 
International47 79 — 126 
Private— — 1 1 
Bonds    
AAA— 28 — 28 
AA— 54 — 54 
A— 36 — 36 
BBB1 24 — 25 
Below BBB— 10 — 10 
Money market and cash and cash equivalents— 20 — 20 
Total48 300 5 353 
Year ended Dec. 31, 2020Level ILevel IILevel IIITotal
Equity securities    
Canadian— 64 — 64 
US— 30 — 30 
International— 103 — 103 
Private— — 1 1 
Bonds
AAA— 36 — 36 
AA— 67 — 67 
A— 34 — 34 
BBB1 22 — 23 
Below BBB— 4 — 4 
Money market and cash and cash equivalents— 19 — 19 
Total1 379 1 381 

Plan assets do not include any common shares of the Company at Dec. 31, 2021 and Dec. 31, 2020. The Company charged the registered plan nil for administrative services provided for the year ended Dec. 31, 2021 (2020 — nil).






TRANSALTA CORPORATION F79

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:
 RegisteredSupplementalOtherTotal
Present value of defined benefit obligation as at Dec. 31, 2019543 99 22 664 
Current service cost5 2 1 8 
Interest cost16 3 1 20 
Benefits paid(45)(5)(1)(51)
Curtailment(2)— — (2)
Actuarial loss arising from financial assumptions43 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, 2020542 109 24 675 
Current service cost3 2 1 6 
Interest cost12 2 — 14 
Benefits paid(54)(5)(1)(60)
Curtailment(7)— — (7)
Actuarial gain arising from financial assumptions(26)(7)(1)(34)
Actuarial gain arising from experience adjustments(1)— — (1)
Present value of defined benefit obligation as at Dec. 31, 2021469 101 23 593 

The weighted average duration of the defined benefit plan obligation as at Dec. 31, 2021, is 13.6 years.

F. Contributions
 
The expected employer contributions for 2022 for the defined benefit pension and other post-employment benefit plans are as follows:
 RegisteredSupplementalOtherTotal
Expected employer contributions5 6 2 13 





TRANSALTA CORPORATION F80
Notes to Consolidated Financial Statements
G. Assumptions
 
The significant actuarial assumptions used in measuring the Company’s defined benefit obligation for the defined benefit pension and other post-employment benefit plans are as follows:
 As at Dec. 31, 2021As at Dec. 31, 2020
(per cent)RegisteredSupplementalOther RegisteredSupplementalOther
Accrued benefit obligation      
Discount rate2.8 2.8 2.7 2.4 2.3 2.3 
Rate of compensation increase2.9 3.0 — 2.9 3.0 — 
Assumed health-care cost trend rate   
Health-care cost escalation(1)(3)
— — 6.8 — — 6.8 
Dental-care cost escalation— — 4.0 — — 4.0 
Benefit cost for the year   
Discount rate2.4 2.3 2.3 3.0 3.0 3.0 
Rate of compensation increase2.9 3.0 — 2.9 3.0 — 
Assumed health-care cost trend rate   
Health-care cost escalation(2)(4)
— — 7.1 — — 7.1 
Dental-care cost escalation— — 4.0 — — 4.0 
(1) 2021 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) 2021 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) 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.
(4) 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.

H. Sensitivity Analysis
 
The following table outlines the estimated increase in the net defined benefit obligation assuming certain changes in key assumptions:
 Canadian plansUS plans
Year ended Dec. 31, 2021Registered  Supplemental  Other PensionOther
1% decrease in the discount rate
61 15 2 3 1 
1% increase in the salary scale
3 — — — — 
1% increase in the health-care cost trend rate
— — 2 — — 
10% improvement in mortality rates
20 4 — 1 — 

32. Joint Arrangements
Joint arrangements at Dec. 31, 2021, included the following:
Joint operationsSegment
Ownership
 (per cent)
Description
SheernessGas50Dual-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
Goldfields PowerGas50Gas-fired facility in Australia operated by TransAlta
Fort SaskatchewanGas60Cogeneration facility in Alberta, of which TA Cogen has a 60 per cent interest, operated by TransAlta
Fortescue River
   Gas Pipeline		Gas43Natural gas pipeline in Western Australia, operated by DBP Development Group
McBride LakeWind and Solar50Wind generation facility in Alberta operated by TransAlta
SoderglenWind and Solar50Wind generation facility in Alberta operated by TransAlta
PingstonHydro50Hydro facility in British Columbia operated by TransAlta
Joint ventureSegment
Ownership
 (per cent)
Description
SkookumchuckWind and Solar49Wind generation facility in Washington operated by Southern Power

 




TRANSALTA CORPORATION F81

Notes to Consolidated Financial Statements
33. Cash Flow Information
A. Change in Non-Cash Operating Working Capital
Year ended Dec. 31202120202019
(Use) source:   
Accounts receivable(28)(79)261 
Prepaid expenses9 2 — 
Income taxes receivable— (4)(6)
Inventory42 6 (13)
Accounts payable, accrued liabilities and provisions153 160 (130)
Income taxes payable(2)4 9 
Change in non-cash operating working capital174 89 121 

B. Changes in Liabilities from Financing Activities
Balance Dec. 31, 2020Cash issuancesRepayments and dividends paidNew leasesDividends declaredForeign exchange impactOther
Balance Dec. 31, 2021
Long-term debt and lease
  liabilities		3,361 173 (214)1 — (39)(15)3,267 
Exchangeable securities730 — — — — — 5 735 
Dividends payable (common and preferred)59 — (87)— 90 — — 62 
Total liabilities from financing activities4,150 173 (301)1 90 (39)(10)4,064 
Balance Dec. 31, 2019Cash issuancesRepayments and dividends paidNew leasesDividends declaredForeign exchange impactOtherBalance
Dec. 31, 2020
Long-term debt and lease
   liabilities		3,212 753 (620)16 — 5 (5)3,361 
Exchangeable securities326 400 — — — — 4 730 
Dividends payable (common and preferred)37 — (86)— 107 — 1 59 
Total liabilities from financing activities3,575 1,153 (706)16 107 5 — 4,150 





TRANSALTA CORPORATION F82
Notes to Consolidated Financial Statements
34. Capital
TransAlta’s capital is comprised of the following:
As at Dec. 3120212020Increase/
(decrease)
Long-term debt(1)
3,267 3,361 (94)
Exchangeable securities735 730 5 
Equity   
Common shares2,901 2,896 5 
Preferred shares942 942 — 
Contributed surplus46 38 8 
Deficit(2,453)(1,826)(627)
Accumulated other comprehensive earnings146 302 (156)
Non-controlling interests1,011 1,084 (73)
Less: available cash and cash equivalents(2)
(947)(703)(244)
Less: principal portion of restricted cash on TransAlta OCP bonds(3)
(17)(11)(6)
Less: fair value asset of hedging instruments on long-term debt(4)
(2)(2)— 
Total capital5,629 6,811 (1,182)
(1) Includes lease liabilities, amounts outstanding under credit facilities, tax equity liabilities and current portion of long-term debt.
(2) The Company 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 Company includes the principal portion of restricted cash on TransAlta OCP bonds because this cash is restricted specifically to repay outstanding debt.
(4) The Company 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 Company’s overall capital management strategy and its objectives in managing capital are as follows:
A. Maintain a Strong Financial Position 
The Company 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 Company to access capital markets at reasonable interest rates. 
Maintaining a strong balance sheet also allows its commercial team to contract the Company’s portfolio with a variety of counterparties on terms and prices that are favourable to the Company’s financial results and provides the Company with better access to capital markets through commodity and credit cycles. The Company has an investment grade credit rating from DBRS (stable outlook). During 2021, Moody's reaffirmed its issuer rating of Ba1 with a stable outlook; DBRS reaffirmed the Company’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 Company’s Unsecured Debt rating and Issuer Rating of BB+ with stable outlook. The Company remains focused on maintaining a strong financial position and cash flow coverage ratios. Credit ratings provide information relating to the Company's financing costs, liquidity and operations and affect the Company's ability to obtain short-term and long-term financing and/or the cost of such financing.

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. Liquidity
For the years ended Dec. 31, 2021 and 2020, cash inflows and outflows are summarized below. The Company manages variations in working capital using existing liquidity under credit facilities to ensure sufficient cash and credit is available to fund operations, pay dividends, distribute payments to subsidiaries' non-controlling interests and invest in PP&E.




TRANSALTA CORPORATION F83

Notes to Consolidated Financial Statements
Year ended Dec. 3120212020Increase
(decrease)
Cash flow from operating activities1,001 702 299 
Change in non-cash working capital(174)(89)(85)
Cash flow from operations before changes in working capital827 613 214 
Dividends paid on common shares(48)(47)(1)
Dividends paid on preferred shares(39)(39)— 
Distributions paid to subsidiaries’ non-controlling interests(156)(97)(59)
Property, plant and equipment expenditures(480)(486)6 
Inflow (outflow)104 (56)160 

TransAlta maintains sufficient cash balances and committed credit facilities to fund periodic net cash outflows related to its business. At Dec. 31, 2021, $1.3 billion (2020 — $1.5 billion) of the Company’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 Company’s principal operating subsidiaries at Dec. 31, 2021, are as follows:
SubsidiaryCountryOwnership
(per cent)		Principal activity
TransAlta Generation PartnershipCanada100Generation and sale of electricity
TransAlta Cogeneration, L.P.Canada50.01Generation and sale of electricity
TransAlta Centralia Generation, LLCUS100Generation and sale of electricity
TransAlta Energy Marketing Corp.Canada100Energy marketing
TransAlta Energy Marketing (U.S.), Inc.US100Energy marketing
TransAlta Energy (Australia), Pty Ltd.Australia100Generation and sale of electricity
TransAlta Renewables Inc.Canada60.1Generation and sale of electricity
Associate or joint ventureCountryOwnership
(per cent)		Principal activity
SP Skookumchuck Investment, LLCUS49Generation and sale of electricity
EMG International, LLCUS30Wastewater treatment and biogas fuel to generate electricity
Transactions between the Company and its subsidiaries have been eliminated on consolidation and are not disclosed. Associates and joint ventures have been equity accounted for by the Company.

A.Transactions with Key Management Personnel 
TransAlta’s key management personnel include the President and Chief Executive Officer ("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. 31202120202019
Total compensation30 27 30 
Comprised of:   
  Short-term employee benefits14 12 13 
  Post-employment benefits1 2 2 
  Termination benefits— — 2 
  Share-based payments15 13 13 





TRANSALTA CORPORATION F84
Notes to Consolidated Financial Statements
B.TransAlta Renewables Acquisitions
North Carolina Solar
On Nov. 5, 2021, TransAlta completed the sale of a 100 per cent economic interest in the 122 MW portfolio of solar facilities in North Carolina for US$102 million. Pursuant to the transaction, a TransAlta subsidiary owns North Carolina Solar directly and another subsidiary issued tracking preferred shares to TransAlta Renewables reflecting the economic interest in the facilities.

Ada and Skookumchuck
On April 1, 2021, the Company completed the sale of its 100 per cent economic interest in the 29 MW Ada cogeneration facility and its 49 per cent economic interest in the 137 MW Skookumchuck wind facility to TransAlta Renewables for $43 million and $103 million, respectively. Pursuant to the transaction, a TransAlta subsidiary owns Ada and Skookumchuck directly and another subsidiary issued tracking preferred shares to TransAlta Renewables reflecting the economic interest in the facilities.

Big Level and Antrim
During 2021, TransAlta Renewables subscribed for additional tracking preferred shares in Big Level and Antrim for $7 million (US$6 million). In addition, TransAlta Renewables repaid a portion of the total outstanding promissory notes to the Company related to the Big Level and Antrim wind facilities in the amount of $18 million (US$14 million).

Windrise Wind
On Dec. 23, 2020, TransAlta announced that it had entered into definitive agreements for the acquisition by TransAlta Renewables, a subsidiary of the Company, of its 100 per cent direct interest in the 206 MW Windrise wind project located in the Municipal District of Willow Creek, Alberta. On Feb. 26, 2021, TransAlta completed the sale of its 100 per cent direct interest in the 206 MW Windrise wind project to TransAlta Renewables, for $213 million.

WindCharger
On Aug. 1, 2020, the WindCharger battery storage project was sold to TransAlta Renewables for $12 million.

TEC Offering
In relation to the TEC Offering, TransAlta Renewables has received $480 million (AU$515 million) of the proceeds 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.

36. Commitments and Contingencies
In addition to commitments disclosed elsewhere in the financial statements, the Company 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:
 202220232024202520262027 and thereafterTotal
Natural gas, transportation and
  other contracts		47 54 45 44 45 508 743 
Transmission9 9 6 6 2 — 32 
Coal supply and mining
   agreements1
76 98 90 75 — — 339 
Long-term service agreements89 46 43 32 25 54 289 
Operating leases4 3 3 1 1 31 43 
Growth941 276 — — — — 1,217 
TransAlta Energy Transition Bill6 6 — — — — 12 
Total1,172 492 187 158 73 593 2,675 
(1) Relates to coal supply and mining agreements for Centralia Unit 2.




TRANSALTA CORPORATION F85

Notes to Consolidated Financial Statements
A. Natural Gas, Transportation and Other Contracts 
The Company has fixed price or volume natural gas purchase and transportation contracts. Upon closing of the sale of the Pioneer Pipeline, additional 15-year natural gas transportation agreements for 275 terajoules ("TJ") per day on a firm basis by 2023 arose, bringing the total firm natural gas transportation to 400 TJ per day. Additionally, on June 30, 2021, the Company's agreement to purchase 139 TJ per day of natural gas from Tidewater Midstream & Infrastructure Ltd. was terminated and the commitment related to commodity dispatching was discharged, resulting in a reduction to the commitments disclosed at Dec. 31, 2020, by approximately $1.3 billion.
B. Transmission 
The Company has several agreements to purchase transmission network capacity in Canada and the Pacific Northwest. Provided certain conditions for delivering the service are met, the Company 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. Pricing is reflective of current market conditions.
Commitments related to mining agreements for the Company’s share of its Sheerness joint operation have been reduced due to the accelerated plans to eliminate coal as a fuel source at the Sheerness facility. Amounts due under the contract and a mining royalty agreement for the Highvale mine have been recognized as onerous contract provisions, with the result that no amounts are included as future commitments. For additional information refer to Note 9.
D. Long-Term Service Agreements 
TransAlta has various service agreements in place, primarily for inspections, repairs and maintenance that may be required on natural gas facilities, coal facilities, equipment for coal and gas, and turbines at various wind facilities.
E. Operating Leases
Operating leases include lease commitments not recognized under IFRS 16 and lease commitments that have not yet commenced, mainly related to buildings, vehicles and land.

F. Growth 
Commitments for growth relate to the following projects: White Rock Wind Projects, Garden Plain wind project, Horizon Hill wind project and the Northern Goldfields Solar Project.

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 Memorandum of Agreement ("MOA"), The Company has 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 portion thereof would no longer be required. As of Dec. 31, 2021, the Company has funded approximately US$46 million of the commitment, which is recognized in other assets in the Consolidated Statements of Financial Position.
H. 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 Company’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 Company responds as required.





TRANSALTA CORPORATION F86
Notes to Consolidated Financial Statements
I. Transmission Line Loss Rule Proceeding 
The Company 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. The AUC approved an invoice settlement process and all three planned settlements have been received. The first two invoices were settled by the first quarter of 2021 and the third invoice settled in the second quarter of 2021. The true-up invoices issued by the AESO in the fourth quarter of 2021 were settled by Dec. 31, 2021, with no further invoices expected.
II. Fortescue Metals Group Ltd. ("FMG") at South Hedland Power Station
On May 2, 2021, the Company entered into a conditional settlement with FMG. The settlement was concluded and the actions were formally dismissed in the Supreme Court of Western Australia on Dec. 7, 2021. The settlement amount has been recorded as revenue in the fourth quarter of 2021, while all other balances previously provided for have been reversed. The settlement has resulted in FMG continuing as a customer of the South Hedland facility.

III. Mangrove Claim
On April 23, 2019, the Mangrove Partners Master Fund Ltd. ("Mangrove") commenced an action in the Ontario Superior Court of Justice naming the Company, the incumbent members of the Board of the Company on such date, and Brookfield as defendants. Mangrove was seeking to set aside the 2019 Brookfield transaction. The parties reached a confidential settlement and the action was discontinued in the Ontario Superior Court of Justice on April 30, 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 was heard on July 8, 2021. After the hearing, counsel for ENMAX raised concerns that one of the three justices on the appeal panel was distracted during the hearing. The justice has since recused herself from the hearing and the parties made submissions with respect to whether the remaining two justices can continue to issue the decision or whether a new hearing is required. On Nov. 8, 2021, the Alberta Court of Appeal released its decision and ordered that the appeal be re-heard by a new three-person panel of the Court of Appeal, which was heard on Jan. 27, 2022. TransAlta remains of the view 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 claimed force majeure under the Alberta PPA. ENMAX, the purchaser under the Alberta PPA at the time, did not dispute the force majeure but the Balancing Pool attempted to do so, seeking to recover $12 million in capacity payment charges it paid to TransAlta while the unit was offline. The parties reached a confidential settlement on April 21, 2021, and this matter is now resolved.

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 2022 or early 2023. 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 emission performance credits ("EPCs") earned by the Hydro facilities as a result of opting those facilities into the Carbon Competitiveness Incentive Regulation from 2018-2020 inclusive. The Balancing Pool claims ownership of the EPCs because it believes the change-in-law provisions under the Hydro PPA require the EPCs to be passed through to the Balancing Pool. TransAlta has not received any benefit from the EPCs or from any purported change in law and believes that the Balancing Pool has no rights to these credits. An arbitration has commenced, and the hearing is scheduled for Feb. 6-10, 2023.






TRANSALTA CORPORATION F87

Notes to Consolidated Financial Statements
VIII. Direct Assigned Capital Deferral Account ("DACDA") Application
AltaLink Management Ltd. ("AltaLink") and TransAlta (as a secondary applicant) filed an application before the AUC to recover its 2016-2018 DACDA costs incurred for the 240 kV line upgrades for the Edmonton Region Project. The AUC disallowed 15 per cent (approximately $3 million) of TransAlta’s portion. TransAlta disputed this finding and filed a permission to appeal application with the Court of Appeal and a review and variance application with the AUC (the “R&V”). The AUC dismissed the R&V application on April 22, 2021. The permission to appeal was subsequently discontinued on July 5, 2021, which concludes this matter.

IX. Sarnia Outages
The Sarnia cogeneration facility experienced three separate outages between May 19, 2021, and June 9, 2021, that resulted in steam interruptions to its industrial customers. As a result, the customers have submitted claims for liquidated damages. Steam supply disruptions of this nature are atypical and infrequent at the Sarnia cogeneration facility. The Company conducted an investigation to determine the root cause of each of the three events, which concluded all three outages were within TransAlta's control. As such, liquidated damages in an amount dictated by the applicable agreements are payable by TransAlta to the customers for the three outages.

X. Kaybob 3 Cogeneration Dispute
The Company is engaged in a dispute with ET Canada as a result of ET Canada’s purported termination of agreements between the parties to develop, construct and operate a 40 MW cogeneration facility at the Kaybob South No. 3 sour gas processing facility. TransAlta commenced an arbitration seeking full compensation for ET Canada's wrongful termination of the agreements. ET Canada seeks a declaration that the agreements were lawfully terminated. A hearing is scheduled for two weeks starting Jan. 9, 2023.

37. Segment Disclosures
A. Description of Reportable Segments 
The Company has six reportable segments as described in Note 1.
The following tables provides each segment's results in the format that the CODM reviews the Company's segments to make operating decisions and assess performance. The CODM assesses the performance of the operating segments based on a measure of adjusted EBITDA. This measurement basis represents earnings before income taxes, adjusted for the effects of: depreciation of property, plant and equipment and amortization of intangibles, depreciation of right‐of‐use assets, finance lease income, unrealized mark-to-market gains or losses and unrealized foreign exchange gains or losses on commodity transactions, depreciation on our mining equipment included in fuel and purchased power, interest income recorded on the prepaid funds, write-down of coal inventory and parts and material inventory related to the Highvale mine and coal operations at our natural gas converted facilities, going off-coal which resulted in the remaining coal supply payments on the existing coal supply agreement being recognized as an onerous contract, impairment charges, share of (profit) loss of joint venture, and other costs or income adjustments. The tables below show the reconciliation of the total segmented results and adjusted EBITDA to the statement of earnings (loss) reported under IFRS. Prior periods have been adjusted for comparable purposes.
For internal reporting purpose, the earnings information from the Company's investment in Skookumchuck has been presented in the Wind and Solar segment on a proportionate basis. Information on a proportionate basis reflects the Company'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.





TRANSALTA CORPORATION F88
Notes to Consolidated Financial Statements
B. Reported Adjusted Segment Earnings (Loss) and Segment Assets
I. Reconciliation of Adjusted EBITDA to Earnings before Income Tax
Year ended Dec. 31, 2021Hydro
Wind & Solar(1)
Gas(2)
Energy Transition(3)
Energy
Marketing		CorporateTotal
Equity investments(1)
Reclass adjustmentsIFRS financials
Revenues383 323 1,109 709 211 4 2,739 (18)— 2,721 
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss— 25 (40)19 (38)— (34)— 34 — 
Decrease in finance lease receivable— — 41 — — — 41 — (41)— 
Finance lease income— — 25 — — — 25 — (25)— 
Unrealized foreign exchange gain on commodity— — (3)— — — (3)— 3 — 
Adjusted revenues383 348 1,132 728 173 4 2,768 (18)(29)2,721 
Fuel and purchased power16 17 457 560 — 4 1,054 — — 1,054 
Reclassifications and adjustments:
Australian interest income— — (4)— — — (4)— 4 — 
Mine depreciation— — (79)(111)— — (190)— 190 — 
Coal inventory write-down— — — (17)— — (17)— 17 — 
Adjusted fuel and purchased power16 17 374 432 — 4 843 — 211 1,054 
Carbon compliance(4)
— — 118 60 — — 178 — — 178 
Gross margin367 331 640 236 173 — 1,747 (18)(240)1,489 
OM&A42 59 175 117 36 84 513 (2)— 511 
Reclassifications and adjustments:
Parts and materials write-down— — (2)(26)— — (28)— 28 — 
Curtailment gain— — — 6 — — 6 — (6)— 
Adjusted OM&A42 59 173 97 36 84 491 (2)22 511 
Taxes, other than income taxes3 10 13 6 — 1 33 (1)— 32 
Net other operating expense (income)— — (40)48 — — 8 — — 8 
Reclassifications and adjustments:
Royalty onerous contract and contract termination penalties— — — (48)— — (48)— 48 — 
Adjusted net other operating income— — (40)— — — (40)— 48 8 
Adjusted EBITDA322 262 494 133 137 (85)1,263 
Equity income from associate9 
Finance lease income
25 
Depreciation and amortization(529)
Asset impairment(648)
Net interest expense(6)
(245)
Foreign exchange gain
16 
Gain on sale of assets and other54 
Loss before income taxes
(380)
(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.
(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.
(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.
(4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes.
(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.
(6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings.





TRANSALTA CORPORATION F89

Notes to Consolidated Financial Statements
Year ended Dec. 31, 2020 Hydro
Wind & Solar(1)
Gas(2)
Energy Transition(3)
Energy
Marketing		CorporateTotal
Equity accounted investments(1)
Reclass adjustmentsIFRS financials
Revenues152 332 787 704 122 7 2,104 (3)— 2,101 
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss— 2 33 (14)21 — 42 — (42)— 
Decrease in finance lease receivable— — 17 — — — 17 — (17)— 
Finance lease income— — 7 — — — 7 — (7)— 
Unrealized foreign exchange loss on commodity— — 4 — — — 4 — (4)— 
Adjusted revenues152 334 848 690 143 7 2,174 (3)(70)2,101 
Fuel and purchased power8 25 325 435 — 12 805 — — 805 
Reclassifications and adjustments:
Australian interest income— — (4)— — — (4)— 4 — 
Mine depreciation— — (100)(46)— — (146)— 146 — 
Coal inventory write-down— — — (37)— — (37)— 37 — 
Adjusted fuel and purchased
  power		8 25 221 352 — 12 618 — 187 805 
Carbon compliance(4)
— — 120 48 — (5)163 — — 163 
Gross margin144 309 507 290 143 — 1,393 (3)(257)1,133 
OM&A37 53 166 106 30 80 472 — — 472 
Taxes, other than income taxes2 8 13 9 — 1 33 — — 33 
Net other operating expense (income)— — (11)— — — (11)— — (11)
Reclassifications and adjustments:
Impact of Sheerness going off-coal— — (28)— — — (28)— 28 — 
Adjusted net other operating income(39)— — — (39)— 28 (11)
Adjusted EBITDA(5)
105 248 367 175 113 (81)927 
Equity income from associate1 
Finance lease income7 
Depreciation and amortization(654)
Asset impairment(84)
Net interest expense(6)
(238)
Foreign exchange loss17 
Gain on sale of assets and other9 
Loss before income taxes(303)
(1) Skookumchuck has been included on a proportionate basis in the Wind and Solar segment.
(2) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.
(3) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.
(4) As of the first quarter of 2021, carbon compliance costs have been reclassified from fuel and purchase power costs and disclosed separately. Prior periods have been adjusted for comparative purposes.
(5) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.
(6) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings.






TRANSALTA CORPORATION F90
Notes to Consolidated Financial Statements
Year ended Dec. 31, 2019 HydroWind & Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		CorporateTotalReclass adjustmentsIFRS financials
Revenues156 312 851 905 129 (6)2,347 — 2,347 
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss— (17)6 (12)(10)— (33)33 — 
Decrease in finance lease receivable— — 24 — — — 24 (24)— 
Finance lease income— — 6 — — — 6 (6)— 
Adjusted revenues156 295 887 893 119 (6)2,344 3 2,347 
Fuel and purchased power7 16 315 539 — 4 881 — 881 
Reclassifications and adjustments:
Australian interest income— — (4)— — — (4)4 — 
Mine depreciation— — (81)(40)— — (121)121 — 
Adjusted fuel and purchased power7 16 230 499 — 4 756 125 881 
Carbon compliance— — 138 77 — (10)205 — 205 
Gross margin149 279 519 317 119 — 1,383 (122)1,261 
OM&A36 50 162 124 30 73 475 — 475 
Taxes, other than income taxes3 8 9 8 — 1 29 — 29 
Net other operating expense (income)— (10)(41)— — 2 (49)— (49)
Termination of Sundance B and C PPAs— — (14)(42)— — (56)— (56)
Adjusted EBITDA(3)
110 231 403 227 89 (76)984 
Finance lease income6 
Depreciation and amortization(590)
Asset impairment(25)
Gain on termination of Keephills 3 coal rights contract88 
Net interest expense(4)
(179)
Foreign exchange loss(15)
Gain on sale of assets and other46 
Earnings before income taxes193 
(1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.
(2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.
(3) Adjusted EBITDA is not defined and has no standardized meaning under IFRS.
(4) Includes accretion by segment and interest expense is not allocated as its related to Corporate debt and borrowings.






TRANSALTA CORPORATION F91

Notes to Consolidated Financial Statements
II. Selected Consolidated Statements of Financial Position Information
As at Dec. 31, 2021HydroWind
and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		CorporateTotal
PP&E466 2,304 2,036 481 — 33 5,320 
Right-of-use assets5 64 7 1 — 18 95 
Intangible assets3 147 56 9 5 36 256 
Goodwill258 175 — — 30 — 463 
As at Dec. 31, 2020HydroWind
and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		CorporateTotal
PP&E467 2,005 2,102 1,232 — 16 5,822 
Right-of-use assets6 55 5 53 — 22 141 
Intangible assets4 159 66 36 7 41 313 
Goodwill258 175 — — 30 — 463 
(1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.
(2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.

III. Selected Consolidated Statements of Cash Flows Information
Additions to non-current assets are as follows:
Year ended Dec. 31, 2021HydroWind
and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		CorporateTotal
Additions to non-current assets:     
 PP&E29 166 167 90 — 28 480 
 Intangible assets— — — 1 — 8 9 
Year ended Dec. 31, 2020HydroWind
and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		CorporateTotal
Additions to non-current assets:     
 PP&E22 174 199 78 — 13 486 
 Intangible assets— — — 1 — 13 14 
Year ended Dec. 31, 2019HydroWind
and
Solar
Gas(1)
Energy Transition(2)
Energy
Marketing		CorporateTotal
Additions to non-current assets:     
 PP&E23 229 74 90 — 1 417 
 Intangible assets— — — 2 — 12 14 
(1) Includes the segments previously known as Australian Gas and North American Gas and the gas generation assets from the segment previously known as Alberta Thermal.
(2) Includes the segment previously known as Centralia and the coal generation assets from the segment previously known as Alberta Thermal.





TRANSALTA CORPORATION F92
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. 31202120202019
Depreciation and amortization expense on the Consolidated Statements of
  Earnings (Loss)		529 654 590 
Depreciation included in fuel, carbon compliance and purchased power (Note 6)190 144 119 
Depreciation and amortization on the Consolidated Statements of Cash Flows719 798 709 


C. Geographic Information
I. Revenues
Year ended Dec. 31202120202019
Canada1,854 1,227 1,460 
US731 716 727 
Australia136 158 160 
Total revenue2,721 2,101 2,347 
II. Non-Current Assets
Property, plant and
equipment		Right-of-use assetsIntangible assetsOther assets
As at Dec. 3120212020202120202021202020212020
Canada4,051 4,661 52 107 141 185 15 74 
US860 737 39 30 85 94 61 61 
Australia409 424 4 4 30 34 66 71 
Total5,320 5,822 95 141 256 313 142 206 

D. Significant Customer 
During the year ended Dec. 31, 2021, sales to the AESO represent 35 per cent of the Company’s total revenue (2020 — sales to the AESO represented 15 per cent of the Company’s total revenue). There were no other companies greater than 10 per cent of the Company's total revenue.





TRANSALTA CORPORATION F93

Exhibit 23.1
  
eylogoa01a.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. 333-260935, 333-236894 pertaining to TransAlta Corporation’s Share Unit Plan, and Form S-8 Nos. 333-72454 and 333-101470 pertaining to TransAlta Corporation’s Share Option Plan

b.Form F-10 No. 333-257098 pertaining to the registration of Debt and Equity Securities

of TransAlta Corporation and the use herein of our reports dated February 23, 2022, with respect to the consolidated statements of financial position as at December 31, 2020 and 2021 and the consolidated statements of earnings (loss), comprehensive earnings (loss), changes in equity and cash flows for each of the years in the three year period ended December 31, 2021, and the effectiveness of internal control over financial reporting of TransAlta Corporation as of December 31, 2021, included in this Annual Report on Form 40-F.



 
 
 /s/Ernst & Young LLP
Calgary, Alberta
February 23, 2022
Chartered Professional Accountants
 


 
 
A member firm of Ernst & Young Global Limited

Exhibit 31.1
 
Certifications
I, John H. Kousinioris, 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.
 
February 23, 2022 
 /s/ John H. Kousinioris
 John H. Kousinioris
 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.
February 23, 2022 
 /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, 2021 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John H. Kousinioris, 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/ John H. Kousinioris
John H. Kousinioris
President and Chief Executive Officer
 
Dated: February 23, 2022
 
 
 
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, 2021 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: February 23, 2022
 
 
 
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.