(in millions of Canadian dollars except where noted)

(Unaudited)

(Tabular amounts in millions of Canadian dollars, except as otherwise noted)

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. The Company's head office is located in Calgary, Alberta.

These unaudited interim condensed consolidated financial statements have been prepared in compliance with International Accounting Standard (“IAS”) 34 Interim Financial Reporting using the same accounting policies as those used in the Company's most recent audited annual consolidated financial statements, except as outlined in Note 2. These unaudited interim condensed consolidated financial statements do not include all of the disclosures included in the Company’s audited annual consolidated financial statements. Accordingly, they should be read in conjunction with the Company’s most recent audited annual consolidated financial statements which are available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov.

The unaudited interim condensed consolidated financial statements include the accounts of the Company and the subsidiaries that it controls.

The unaudited interim condensed consolidated financial statements have been prepared on a historical cost basis, except for certain financial instruments, which are stated at fair value.

These unaudited interim condensed consolidated financial statements reflect all adjustments which consist of normal recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of results. Interim results will fluctuate due to plant maintenance schedules, the seasonal demands for electricity and changes in energy prices. Consequently, interim condensed results are not necessarily indicative of annual results. TransAlta’s results are partly seasonal due to the nature of the electricity market and related fuel costs.

These unaudited interim condensed consolidated financial statements were authorized for issue by the Audit, Finance and Risk Committee on behalf of TransAlta's Board of Directors (the "Board") on Aug. 3, 2023.

The preparation of these unaudited interim condensed consolidated financial statements in accordance with IAS 34 requires management to use judgment and make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosures of contingent assets and liabilities. These estimates are subject to uncertainty. Actual results could differ from these estimates due to factors such as fluctuations in interest rates, foreign exchange rates, inflation and commodity prices, and changes in economic conditions, legislation and regulations.

During the three and six months ended June 30, 2023, there were changes in estimates relating to asset impairment reversals (Note 5) and decommissioning and restoration provisions (Note 15).

Refer to Note 2(P) of the Company's 2022 audited annual consolidated financial statements for further details on the significant accounting judgments and key sources of estimation uncertainty.

The accounting policies adopted in the preparation of the unaudited interim condensed consolidated financial statements are consistent with those followed in the preparation of the Company’s annual consolidated financial statements for the year ended Dec. 31, 2022, except for the adoption of new standards effective as of Jan. 1, 2023 and interpretations or amendments that have been issued but are not yet effective.

The majority of the Company's revenues are derived from the sale of 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.

Fuel and purchased power and OM&A expenses classified by nature are as follows:

The Company recognized the following asset impairment charges (reversals):

During the second quarter of 2023, internal valuations indicated the fair value less costs of disposal of the assets exceeded the carrying value due to a contract extension and changes in power price assumptions for two hydro facilities, which favourably impacted estimated future cash flows and resulted in a full recoverability test. As a result of the recoverability test an impairment reversal of $10 million was recognized. The recoverable amounts of $70 million in total were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement. The discount rate used in the fair value measurements was 6.32 per cent.

During the second quarter of 2022, the Company recorded an impairment charge of $6 million on a hydro facility, primarily as a result of increases in discount rates. The recoverable amount of $30 million was estimated based on fair value less cost of disposal utilizing a discounted cash flow approach and is categorized as a Level III fair value measurement.

During the first quarter of 2023, internal valuations indicated the fair value less costs of disposal of the assets exceeded the carrying value due to changes in power price assumptions for two wind facilities, which favourably impacted estimated future cash flows and resulted in a full recoverability test. As a result of the recoverability test an impairment reversal of $10 million was recognized. The recoverable amounts of $253 million in total were estimated based on fair value less costs of disposal utilizing a discounted cash flow approach and are categorized as a Level III fair value measurement. The discount rate used in the fair value measurements was 6.94 per cent.

During the second quarter of 2022, the Company recorded an impairment charge of $21 million on three wind facilities, primarily as a result of increases in discount rates. The recoverable amount of $289 million was estimated based on fair value less cost of disposal utilizing a discounted cash flow approach and is categorized as a Level III fair value measurement.

The components of net interest expense are as follows:

The components of income tax expense are as follows:

The Company’s subsidiaries with significant non-controlling interests are TransAlta Renewables Inc. ("TransAlta Renewables") and TransAlta Cogeneration L.P. The net earnings, distributions and equity attributable to TransAlta Renewables’ non-controlling interests include the 17 per cent non-controlling interest in Kent Hills Wind LP, which owns the 167 MW Kent Hills wind farm located in New Brunswick.

On July 10, 2023, the Company entered into an agreement to acquire all of the outstanding common shares of TransAlta Renewables not already owned, directly or indirectly, by TransAlta and certain of its affiliates subject to the approval of TransAlta Renewables shareholders. See Note 22 for details.

As at			June 30, 2023			Dec. 31, 2022
Trade accounts receivable			699			1,165
Collateral provided (Note 11)			307			304
Current portion of finance lease receivables			33			52
Loan receivable			—			4
Income taxes receivable			59			64
Trade and other receivables			1,098			1,589

As at			June 30, 2023			Dec. 31, 2022
Accounts payable and accrued liabilities			645			1,069
Interest payable			16			17
Collateral held (Note 11)			—			260
Accounts payable and accrued liabilities			661			1,346

Financial assets and financial liabilities are measured on an ongoing basis at cost, fair value or amortized cost.

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. The Level III classification is the lowest level classification in the fair value hierarchy.

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.

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.

Fair values are determined using inputs for the assets or liabilities that are not readily observable. 

For assets and liabilities that are recognized at fair value on a recurring basis, the Company determines whether transfers have occurred between levels in the hierarchy by re-assessing categorization (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period.

There were no changes in the Company’s valuation processes, valuation techniques and types of inputs used in the fair value measurements during the period. For additional information, please refer to Note 14 of the 2022 audited annual consolidated financial statements.

Commodity risk management assets and liabilities include risk management assets and liabilities that are used in the energy marketing and generation segments 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 June 30, 2023, are as follows: Level I – $76 million net liability (Dec. 31, 2022 – $23 million net asset), Level II – $104 million net liability (Dec. 31, 2022 – $173 million net asset) and Level III – $376 million net liability (Dec. 31, 2022 – $782 million net liability).

Significant changes in commodity net risk management assets (liabilities) during the six months ended June 30, 2023, are primarily attributable to contract settlements and volatility in market prices across multiple markets on both existing contracts and new contracts.

The following table summarizes the key factors impacting the fair value of the Level III commodity risk management assets and liabilities by classification during the six months ended June 30, 2023 and 2022, respectively:

As at June 30, 2023, the total Level III risk management asset balance was $90 million (Dec. 31, 2022 – $31 million) and Level III risk management liability balance was $466 million (Dec. 31, 2022 – $813 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 are outlined in the following table. 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.

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.

The contract is denominated in US dollars. The US dollar relative to the Canadian dollar did not change significantly from Dec. 31, 2022 to June 30, 2023 and did not have a significant impact on the base fair value or sensitivity values.

The Company has a coal rail transport agreement that includes an upside sharing mechanism until Dec. 31, 2025. Option pricing techniques have been utilized to value the obligation associated with this component of the agreement.

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 Company is party to a long-term contract for differences ("CFD") for the offtake of 100 per cent of the generation from its 90 MW Big Level wind facility. The CFD, together with the sale of electricity generated into the PJM Interconnection at the prevailing real-time energy market price, achieve the fixed contract price per MWh on proxy generation. Under the CFD, if the market price is lower than the fixed contract price the customer pays the company the difference and if the market price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. The contract matures in December 2034. The contract is accounted for as a derivative. Changes in fair value are presented in revenue.

The Company is party to two Virtual Power Purchase Agreements ("VPPAs") for the offtake of 100 per cent of the generation from its 130 MW Garden Plain wind project. The VPPAs, together with the sale of electricity generated into the Alberta power market at the pool price, achieve the fixed contract prices per MWh. Under the VPPAs, if the pool price is lower than the fixed contract price the customer pays the Company the difference and if the pool price is higher than the fixed contract price the Company refunds the difference to the customer. The customer is also entitled to the physical delivery of environmental attributes. Both VPPAs commence on commercial operation of the facility and extend for a weighted average of approximately 17 years.

In addition to the VPPAs, the Company has entered into a bridge contract, at one of the VPPAs price, that initially was for 16 months from Sept. 1, 2021, through Dec. 31, 2022, and will remain in effect until the commercial operation date is achieved. The customer is also entitled to the physical delivery of environmental attributes.

The energy component of these contracts is accounted for as derivatives. Changes in fair value are presented in revenue.

The Company is party to two long-term VPPAs for the offtake of 100 per cent of the generation from its 300 MW White Rock East and White Rock West wind power projects. The VPPAs, together with the sale of electricity generated into the US Southwest Power Pool ("SPP") market at the relevant price nodes, achieve the fixed contract prices per MWh. Under the VPPAs, if the SPP pricing is lower than the fixed contract price the customers pay the Company the difference and if the SPP pricing is higher than the fixed contract price the Company refunds the difference to the customers. The customers are also entitled to the physical delivery of environmental attributes. The VPPAs commence on commercial operation of the facilities, which is expected during the first half of 2024.

The Company is also party to a VPPA for the offtake of 100 per cent of the generation from its 200 MW Horizon Hill wind power project. The VPPA together with the sale of electricity generated into the US SPP market at the relevant price node, achieve the fixed contract price per MWh. Under the VPPA, if the SPP pricing is lower than the revised fixed contract price the customer pays the Company the difference and if the SPP pricing is higher than the revised fixed contract price the Company refunds the difference to the customer. The customer remains entitled to the physical delivery of environmental attributes. During the second quarter of 2023, the Company and the customer for the Horizon Hill wind project amended the associated VPPA. The VPPA commences on commercial operation of the facility, which is expected during the first half of 2024.

The energy component of these contracts is accounted for as derivatives. Changes in fair value are presented in revenue. The amendments to the Horizon Hill VPPA did not change the nature of the contract and the energy component continues to be accounted for as a derivative.

Other risk management assets and liabilities primarily include risk management assets and liabilities that are used in managing exposures on non-energy marketing transactions such as interest rates, the net investment in foreign operations and other foreign currency risks. Hedge accounting is not always applied.

Other risk management assets and liabilities with a total net liability fair value of $6 million as at June 30, 2023 (Dec. 31, 2022 – $6 million net liability) are classified as Level II fair value measurements.

The fair value of financial assets and liabilities measured at other than fair value is as follows:

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 provided, bank overdraft, accounts payable and accrued liabilities, collateral held and dividends payable) approximates fair value due to the liquid nature of the asset or liability. The fair values of the finance lease receivables approximate the carrying amounts as the amounts receivable represent cash flows from repayments of principal and interest.

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 10 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 condensed 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 (loss) and a reconciliation of changes is as follows:

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. For additional information on the Company's Risk Management Activities please refer to Note 15 of the 2022 audited annual consolidated financial statements.

Aggregate net risk management assets (liabilities) are as follows:

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.

Value at Risk ("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. Changes in market prices associated with proprietary trading activities affect net earnings in the period that the price changes occur. VaR at June 30, 2023, associated with the Company’s proprietary trading activities was $4 million (Dec. 31, 2022 – $4 million).

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.

VaR at June 30, 2023, associated with the Company’s commodity derivative instruments used in generation hedging activities was $25 million (Dec. 31, 2022 – $97 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 June 30, 2023, associated with these transactions was $26 million (Dec. 31, 2022 – $54 million), of which $21 million related to VPPAs (Dec. 31, 2022 – $26 million).

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 June 30, 2023:

The Company did not have significant expected credit losses as at June 30, 2023.

The Company’s maximum exposure to credit risk at June 30, 2023, 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 condensed 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 June 30, 2023, was $35 million (Dec. 31, 2022 – $64 million).

The Company has sufficient existing liquidity available to meet its upcoming debt maturities. The next major debt repayment is scheduled for September 2024. Our highly diversified asset portfolio, by both fuel type and operating region, and our long-term contracted asset base provide stability in our cash flows.

Liquidity risk relates to the Company’s ability to access capital to be used for capital projects, debt refinancing, proprietary trading activities, commodity hedging and general corporate purposes. A maturity analysis of the Company's financial liabilities as well as financial assets that are expected to generate cash inflows to meet cash outflows on financial liabilities, is as follows:

At June 30, 2023, the Company provided $307 million (Dec. 31, 2022 – $304 million) in cash and cash equivalents as collateral to regulated clearing agents and certain utility customers as security for commodity trading activities. These funds are held in segregated accounts by the clearing agents. The utility customers are obligated to pay interest on the outstanding balances. Collateral provided is included within trade and other receivables in the condensed consolidated statements of Financial Position.

At June 30, 2023, the Company held nil (Dec. 31, 2022 – $260 million) 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 related to physical and financial derivative transactions in a net asset position and is included in accounts payable and accrued liabilities in the condensed consolidated statements of financial position.

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.

At June 30, 2023, the Company had posted collateral of $343 million (Dec. 31, 2022 – $820 million) in the form of letters of credit on physical and financial derivative transactions 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 $206 million (Dec. 31, 2022 – $656 million) of collateral to its counterparties.

The components of inventory are as follows:

No inventory is pledged as security for liabilities.

As at June 30, 2023, the Company holds 1,109,181 emission credits in inventory that were purchased externally with a recorded book value of $53 million (Dec. 31, 2022 – 963,068 emission credits with a recorded book value of $27 million). The Company also has 2,742,481 (Dec. 31, 2022 – 3,619,450) of internally generated eligible emission credits from the Company's Wind and Solar and Hydro segments which have no recorded book value. This includes the eligible emission performance credits earned by the Alberta Hydro facilities formerly under dispute and has now been resolved. Refer to Note 19 for details.

Emission credits can be sold externally or can be used to offset future emission obligations from our gas facilities located in Alberta, where the compliance price of carbon is expected to increase, resulting in a reduced cash cost for carbon compliance. In June 2023, the Company settled the 2022 carbon compliance obligation in cash. The compliance price of carbon for the 2022 obligation settled was $50 per tonne and has increased to $65 per tonne in the current year.

On April 24, 2023, the Company acquired a 50 per cent interest in the Tent Mountain Renewable Energy Complex (“Tent Mountain”), an early-stage 320 MW pumped hydro energy storage development project, located in southwest Alberta, from Montem Resources Limited (“Montem”). The acquisition included land rights, fixed assets and intellectual property associated with the pumped hydro development project. The Company paid Montem approximately $8 million on closing and additional contingent payments of up to $17 million may become payable to Montem based on the achievement of specific development and commercial milestones. The Company and Montem jointly control Tent Mountain, with the result that the Company accounts for its interest in the joint venture as an investment using the equity method.

During the three and six months ended June 30, 2023, the Company had additions of $171 million and $434 million, respectively, mainly related to assets under construction for the Garden Plain wind project, the White Rock wind project, the Horizon Hill wind project, the Northern Goldfields solar project, the Mount Keith 132kv transmission expansion and other planned major maintenance. The Company also continued its rehabilitation plan for the Kent Hills wind facilities and capitalized additions of $21 million and $42 million, respectively, in the three and six months ended June 30, 2023.

There was an increase in the decommissioning provision resulting from a decrease in discount rates, largely driven by decreases in long-term market benchmark rates. This resulted in an increase in the related assets included in property, plant and equipment of $11 million (June 30, 2022 — $106 million decrease). Refer to Note 15 for further details.

During the three and six months ended June 30, 2023, the Company capitalized $13 million and $26 million, respectively (June 30, 2022 — $3 million and $4 million) of interest incurred during construction to property, plant and equipment (“PP&E”) at a weighted average rate of 6.2 per cent (June 30, 2022 — 6.1 per cent).

The change in decommissioning and other provision balances is as follows:

Other provisions include provisions arising from ongoing business activities, amounts related to commercial disputes between the Company and customers or suppliers and onerous contract provisions. The onerous contract provisions occurred as a result of decisions to no longer operate on coal in Canada. Payments related to coal contracts for Sheerness are required until 2025. At June 30, 2023, the remaining balance of the provision for the onerous coal contract was $8 million.

These facilities are the primary source of short-term liquidity after the cash flow generated from the Company's business. In June 2023, the TransAlta Corporation syndicated credit facility and TransAlta Renewables syndicated credit facility were amended and maturity dates were extended from June 30, 2026 to June 30, 2027. The TransAlta Corporation bilateral credit facilities were also amended and maturity dates were extended from June 30, 2024 to June 30, 2025.

The Company is in compliance with the terms of the credit facilities and all undrawn amounts are fully available. In addition to the $1.4 billion of committed capacity available under the credit facilities, the Company also has $0.9 billion of available cash and cash equivalents, net of bank overdraft. TransAlta’s debt has terms and conditions, including financial covenants, that are considered normal and customary. As at June 30, 2023, the Company was in compliance with all debt covenants.

On May 8, 2023, the Pingston Power Inc. non-recourse bond matured with a total aggregate repayment of $46 million, consisting of accrued interest and principal repayment.

The Melancthon Wolfe Wind LP, 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 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 second quarter of 2023, with the exception of Kent Hills Wind LP and TAPC Holdings LP, which has been impacted by higher interest rates. The funds in these entities will remain there until the next debt service coverage ratio can be calculated in the third quarter of 2023. At June 30, 2023, $65 million (Dec. 31, 2022 – $50 million) of cash was subject to certain financial restrictions. In accordance with the supplemental indenture, Kent Hills Wind LP cannot make any distributions to its partners until the foundation replacement work has been completed. A foundation replacement reserve account has been set up in accordance with the supplemental indenture, with funds in the account being used to pay foundation replacement costs. The account is funded quarterly with the last planned funding requirement received on March 31, 2023.

The balance in the account is $14 million as at June 30, 2023 (Dec. 31, 2022 – $65 million).

As at June 30, 2023, the Company had $41 million of restricted cash related to the TEC Hedland Pty Ltd bond. These cash reserves are required to be held under commercial arrangements and for debt service, which may be replaced by letters of credit in the future.

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.

TransAlta is authorized to issue an unlimited number of voting common shares without nominal or par value.

On March 27, 2023, the Company entered into an Automatic Share Purchase Plan which permitted an independent broker to repurchase shares under the NCIB during the first quarter blackout period through to the end of the current NCIB program, which expired on May 30, 2023. The number of shares repurchased during the blackout period was 2,943,600.

On May 26, 2023, the Toronto Stock Exchange (“TSX”) accepted the notice filed by the Company to implement a NCIB for a portion of its common shares. Pursuant to the NCIB, TransAlta may repurchase up to a maximum of 14,000,000 Common Shares. 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, 2023 and ends on May 30, 2024.

The effects of the Company's purchase and cancellation of common shares during the period are as follows:

On April 27, 2023, the Company declared a quarterly dividend of $0.055 per common share, payable on July 1, 2023.

On July 26, 2023, the Company declared a quarterly dividend of $0.055 per common share, payable on Oct. 1, 2023.

There have been no other transactions involving common shares between the reporting date and the date of completion of these condensed consolidated financial statements.

All preferred shares issued and outstanding are non-voting cumulative redeemable fixed or floating rate first preferred shares.

On July 26, 2023, the Company declared a quarterly dividend of $0.17981 per share on the Series A preferred shares, $0.41545 per share on the Series B preferred shares, $0.36588 per share on the Series C preferred shares, $0.48287 per share on the Series D preferred shares, $0.43088 per share on the Series E preferred shares and $0.31175 per share on the Series G preferred shares, payable on Sept. 30, 2023.

In addition to the commitments disclosed elsewhere in the financial statements and those disclosed in Note 37 of the 2022 audited annual consolidated financial statements, the Company has incurred the following additional contractual commitments in the six months ended June 30, 2023, either directly or through its interests in joint operations and joint ventures.

Approximate future payments under these agreements are as follows:

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. For the current material outstanding contingencies, please refer to Note 37 of the 2022 audited annual consolidated financial statements. Material changes to the contingencies have been described below.

The Alberta Energy Regulator ("AER") issued a subsurface order on May 27, 2019, which does not permit any hydraulic fracturing within three kilometers of the Brazeau Facility but permits hydraulic fracturing in all formations (except the Duvernay) within three-to-five kilometers of the Brazeau Facility. Subsequently, two oil and gas operators submitted applications to the AER for 10 well licenses (which include hydraulic fracturing activities) within three-to-five kilometers of the Brazeau Facility. The regulatory hearing to consider these applications - Proceeding 379 - was scheduled to be heard from Feb. 27 to March 10, 2023, but was adjourned to permit the O'Chiese First Nation to intervene and make submissions. The hearing will be in the fourth quarter of 2023, at the earliest.

The following tables provides each segment's results in the format that the TransAlta’s President and Chief Executive Officer (the chief operating decision maker) ("CODM"), review the Company's segments to make operating decisions and assess performance. The tables below show the reconciliation of the total segmented results and adjusted EBITDA to the statement of earnings (loss) reported under IFRS.

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.