TransAlta Reports Strong 2024 Results, Announces Dividend Increase and 2025 Annual Guidance

CALGARY, Alberta, Feb. 20, 2025 (GLOBE NEWSWIRE) -- TransAlta Corporation (TransAlta or the Company) (TSX: TA) (NYSE: TAC) today reported its financial results for the fourth quarter and year ended Dec. 31, 2024.

“Our business delivered solid results within the upper range of our guidance, driven by high availability across our generation portfolio, along with the enduring performance of our optimization and hedging strategies. During the year, we added 2.2 GW of generation to our fleet, with three contracted wind facilities achieving commercial operation in addition to the acquisition of Heartland Generation. We also returned $214 million, or $0.71 per share, of value to shareholders through dividends and share repurchases at an average price of $10.59 per share,” said John Kousinioris, President and Chief Executive Officer of TransAlta.

“Given our confidence in the future, we are pleased to announce that our Board of Directors has approved an eight per cent increase to our common share dividend, now equivalent to $0.26 per share on an annualized basis. This represents our sixth consecutive annual dividend increase, affirming our Company's commitment to returning value to shareholders,” added Mr. Kousinioris.

“Our portfolio of generating facilities continues to perform well. In 2025, we expect to generate between $450 and $550 million of free cash flow. We maintain a balanced, prudent and disciplined approach to capital allocation and balance sheet strength. We remain focused on advancing development opportunities at our legacy thermal energy campuses, along with pursuing longer term growth options with a commitment to maximizing shareholder value. Looking to 2025 and beyond, I am optimistic about our Company’s momentum and opportunities."

Fourth Quarter 2024 Financial Highlights

• Adjusted EBITDA⁽¹⁾ of $285 million, compared to $289 million for the same period in 2023
• Free Cash Flow (FCF)⁽¹⁾ of $48 million, or $0.16 per share, compared to $121 million, or $0.39 per share, for the same period in 2023
• Cash flow from operating activities of $215 million, compared to $310 million from the same period in 2023
• Net loss attributable to common shareholders of $65 million, or $0.22 per share, compared to $84 million, or $0.27 per share, for the same period in 2023

Full Year 2024 Financial Highlights

• Achieved the upper range of both 2024 adjusted EBITDA and FCF guidance
• Returned $143 million of capital to common shareholders through the buyback of 13.5 million common shares at an average price of $10.59 per share
• Adjusted EBITDA of $1,253 million, compared to $1,632 million from the same period in 2023
• FCF of $569 million, or $1.88 per share, compared to $890 million, or $3.22 per share, from the same period in 2023
• Net earnings attributable to common shareholders of $177 million, or $0.59 per share, compared to $644 million, or $2.33 per share, from the same period in 2023
• Exited 2024 with a strong financial position, with adjusted net debt to adjusted EBITDA of 3.6 times and available liquidity of $1.6 billion

Other Business Highlights and Updates

• Announced an annual dividend increase of eight per cent, now equivalent to $0.26 per share on an annualized basis, which represents the sixth year of consecutive dividend growth
• Provided 2025 guidance including adjusted EBITDA of $1.15 to $1.25 billion and FCF of $450 to $550 million, or $1.51 to $1.85 per share
• Completed the acquisition of Heartland Generation at a purchase price of $542 million in December 2024, which added 1.7 GW to gross installed capacity
• Achieved strong operational availability of 91.2 per cent in 2024, compared to 88.8 per cent in 2023
• 2024 Total Recordable Injury Frequency of 0.56 compared to 0.30 in 2023
• Reduced scope 1 and 2 GHG emissions intensity in 2024 to 0.35 tCO₂e/MWh from 2023 levels of 0.41 tCO₂e/MWh
• Achieved commercial operation at the White Rock West and East wind facilities in January and April 2024, respectively
• Achieved commercial operation at the Horizon Hill facility in May 2024
• Completed the Mount Keith 132kV expansion project during the first quarter of 2024
  

Key Business Developments

Declared Increase in Common Share Dividend
The Company’s Board of Directors has approved a $0.02 annualized increase to the common share dividend, or 8 per cent increase, and declared a dividend of $0.065 per common share to be payable on July 1, 2025 to shareholders of record at the close of business on June 1, 2025. The quarterly dividend of $0.065 per common share represents an annualized dividend of $0.26 per common share.

TransAlta Acquired Heartland Generation from Energy Capital Partners

On Dec. 4, 2024, the Company closed the acquisition of Heartland Generation Ltd. and certain affiliates (collectively, Heartland) for a purchase price of $542 million from an affiliate of Energy Capital Partners (ECP), the parent of Heartland (the Transaction). To meet the requirements of the federal Competition Bureau, the Company entered into a consent agreement with the Commissioner of Competition pursuant to which TransAlta agreed to divest Heartland's Poplar Hill and Rainbow Lake assets (the Planned Divestitures) following closing of the Transaction. In consideration of the Planned Divestitures, TransAlta and ECP agreed to a reduction of $80 million from the original purchase price for the Transaction. ECP will be entitled to receive the proceeds from the sale of Poplar Hill and Rainbow Lake, net of certain adjustments following completion of the Planned Divestitures. TransAlta also received a further $95 million at closing of the Transaction to reflect the economic benefit of the Heartland business arising from Oct. 31, 2023 to the closing date of the Transaction, pursuant to the terms of the share purchase agreement. The net cash payment for the Transaction, before working capital adjustments, totalled $215 million, and was funded through a combination of cash on hand and draws on TransAlta's credit facilities.

Excluding the Planned Divestitures, the Transaction adds 1.7 GW (net interest) of complementary capacity from nine facilities, including contracted cogeneration and peaking generation, legacy gas-fired thermal generation, and transmission capacity, all of which will be critical to support reliability in the Alberta electricity market.

Mothballing of Sundance Unit 6

On Nov. 4, 2024, the Company provided notice to the Alberta Electric System Operator (AESO) that Sundance Unit 6 will be mothballed on April 1, 2025, for a period of up to two years depending on market conditions. TransAlta maintains the flexibility to return the mothballed unit to service when market fundamentals improve or opportunities to contract are secured. The unit remains available and fully operational for the first quarter of 2025.

Production Tax Credit (PTC) Sale Agreements

On Feb. 22, 2024, the Company entered into 10-year transfer agreements with an AA- rated customer for the sale of approximately 80 per cent of the expected PTCs to be generated from the White Rock and the Horizon Hill wind facilities.

On June 21, 2024, the Company entered into an additional 10-year transfer agreement with an A+ rated customer for the sale of the remaining 20 per cent of the expected PTCs.

The expected average annual EBITDA⁽¹⁾ from the two agreements is approximately $78 million (US$57 million).

Normal Course Issuer Bid (NCIB)

TransAlta remains committed to enhancing shareholder returns through appropriate capital allocation such as share buybacks and its quarterly dividend. In the first quarter of 2024, the Company announced an enhanced common share repurchase program for 2024, allocating up to $150 million, and targeting up to 42 per cent of 2024 FCF guidance, to be returned to shareholders in the form of share repurchases and dividends.

On May 27, 2024, the Company announced that it had received approval from the Toronto Stock Exchange to purchase up to 14 million common shares pursuant to an NCIB during the 12-month period that commenced May 31, 2024, and terminates May 31, 2025. Any common shares purchased under the NCIB will be cancelled.

For the year ended Dec. 31, 2024, the Company purchased and cancelled a total of 13,467,400 common shares at an average price of $10.59 per common share, for a total cost of $143 million, including taxes.

Horizon Hill Wind Facility Achieves Commercial Operation

On May 21, 2024, the 202 MW Horizon Hill wind facility achieved commercial operation. The facility is located in Logan County, Oklahoma and is fully contracted to Meta Platforms Inc. for the offtake of 100 per cent of the generation.

White Rock Wind Facilities Achieve Commercial Operation

On Jan. 1, 2024, the 100 MW White Rock West wind facility achieved commercial operation. On April 22, 2024, the 202 MW White Rock East wind facility also completed commissioning. The facilities are located in Caddo County, Oklahoma and are contracted under two long-term power purchase agreements (PPAs) with Amazon Energy LLC for the offtake of 100 per cent of the generation.

Mount Keith 132kV Expansion Complete

The Mount Keith 132kV expansion project, located in Western Australia, was completed during the first quarter of 2024. The expansion was developed under the existing PPA with BHP Nickel West (BHP), which extends until Dec. 31, 2038. The expansion will facilitate the connection of additional generating capacity to the transmission network which supports BHP's operations.

Year Ended and Fourth Quarter 2024 Highlights

$ millions, unless otherwise stated	Year Ended		Three Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2024		Dec. 31, 2023
Operational information
Availability (%)	91.2	88.8	87.8		86.9
Production (GWh)	22,811	22,029	6,199		5,783
Select financial information
Revenues	2,845	3,355	678		624
Adjusted EBITDA(1)	1,253	1,632	285		289
Earnings (loss) before income taxes	319	880	(51	)	(35	)
Net earnings (loss) attributable to common shareholders	177	644	(65	)	(84	)
Cash flows
Cash flow from operating activities	796	1,464	215		310
Funds from operations(1)	810	1,351	137		229
Free cash flow(1)	569	890	48		121
Per share
Net earnings (loss) per share attributable to common shareholders, basic and diluted	0.59	2.33	(0.22	)	(0.27	)
Funds from operations per share(1),(2)	2.68	4.89	0.46		0.74
FCF per share(1),(2)	1.88	3.22	0.16		0.39
Dividends declared per common share	0.24	0.22	0.12		0.12
Weighted average number of common shares outstanding	302	276	298		308

Segmented Financial Performance

$ millions	Year Ended				Three Months Ended
	Dec. 31, 2024		Dec. 31, 2023		Dec. 31, 2024		Dec. 31, 2023
Hydro	316		459		57		56
Wind and Solar	316		257		95		82
Gas	535		801		116		141
Energy Transition	91		122		28		26
Energy Marketing	131		109		27		14
Corporate	(136	)	(116	)	(38	)	(30	)
Adjusted EBITDA	1,253		1,632		285		289
Earnings (loss) before income taxes	319		880		(51	)	(35	)

Full Year 2024 Financial Results Summary

For the year ended Dec. 31, 2024, the Company demonstrated strong financial and operational performance. The results were within the upper range of management's expectations due to active management of the Company's merchant portfolio and hedging strategies. During 2024, the Company settled a higher volume of hedges at prices that were significantly above the spot market in Alberta and achieved commercial operation at the White Rock and Horizon Hill wind facilities. On Dec. 4, 2024, the Company completed the acquisition of Heartland Generation, which added 1.7 GW to gross installed capacity. Refer to the Significant and Subsequent Events section of our MD&A dated Dec. 31, 2024, for details on the Heartland acquisition and the Planned Divestitures.

Availability for the year ended Dec. 31, 2024, was 91.2 per cent, compared to 88.8 per cent in 2023, an increase of 2.4 percentage points, primarily due to:

• The addition of the White Rock and Horizon Hill wind facilities; and
• The return to service of the Kent Hills wind facilities.

Total production for the year ended Dec. 31, 2024, was 22,811 GWh, compared to 22,029 GWh for the same period in 2023, an increase of 782 GWh, or four per cent, primarily due to:

• Production from new facilities, including the White Rock West and East wind facilities commissioned in January and April 2024, respectively, the Horizon Hill wind facility commissioned in May 2024, and the Northern Goldfields solar facilities commissioned in November 2023;
• Production from the facilities acquired with Heartland;
• Favourable market conditions in the Ontario wholesale power market that enabled higher dispatch at the Sarnia facility in the Gas segment that resulted in higher merchant production to the Ontario grid;
• The return to service of the Kent Hills wind facilities in the first quarter of 2024; and
• Full-year production from the Garden Plain wind facility; partially offset by
• Increased economic dispatch at the Centralia facility due to lower market prices compared to the prior year in the Energy Transition segment; and
• Higher dispatch optimization in Alberta.
  

Adjusted EBITDA for the year ended Dec. 31, 2024, was $1,253 million, compared to $1,632 million in 2023, a decrease of $379 million, or 23.2 per cent. The major factors impacting adjusted EBITDA include:

• Gas adjusted EBITDA decreased by $266 million, or 33 per cent, compared to 2023, primarily due to lower power prices in the Alberta market and resulting increase in economic dispatch, an increase in the price of carbon, higher carbon costs and fuel usage related to production and lower capacity payments, partially offset by a higher volume of favourable hedging positions settled, the utilization of emission credits to settle a portion of our 2023 GHG obligation and lower natural gas prices;
• Hydro adjusted EBITDA decreased by $143 million, or 31 per cent, compared to 2023, primarily due to lower spot power prices and ancillary services prices in the Alberta market, partially offset by realized premiums above the spot power prices, higher environmental and tax attributes revenues due to higher sales of emission credits to third parties and intercompany sales to the Gas segment and higher ancillary service volumes due to increased demand by the AESO;
• Energy Transition adjusted EBITDA decreased by $31 million, or 25 per cent, compared to 2023, primarily due to increased economic dispatch driven by lower market prices which negatively impacted merchant production, partially offset by lower fuel and purchased power costs; and
• Corporate adjusted EBITDA decreased by $20 million, or 17 per cent, compared to 2023, primarily due to higher spending to support strategic and growth initiatives; partially offset by
• Wind and Solar adjusted EBITDA increasing by $59 million, or 23 per cent, compared to 2023, primarily due to new sales of production tax credits, the return to service of the Kent Hills wind facilities, the commercial operation of the White Rock and Horizon Hill wind facilities, partially offset by lower realized power pricing in the Alberta market and higher OM&A due to the addition of new wind facilities; and
• Energy Marketing adjusted EBITDA increasing by $22 million, or 20 per cent, compared to 2023, primarily due to favourable market volatility and timing of realized settled trades during the current year in comparison to the prior year and lower OM&A.

Cash flow from operating activities totalled $796 million for the year ended Dec. 31, 2024, compared to $1,464 million in the same period in 2023, a decrease of $668 million, or 46 per cent, primarily due to:

• Lower gross margin due to lower revenues, excluding the effect of unrealized losses from risk management activities, partially offset by lower fuel and purchased power;
• Higher OM&A due to increased spending on planning and design of an ERP system upgrade, higher spending on strategic and growth initiatives, penalties assessed by the Alberta Market Surveillance Administrator for self-reported contraventions and Heartland acquisition-related transaction and restructuring costs;
• Higher current income tax expense due to the full utilization of Canadian non-capital loss carryforwards in 2023, which was partially offset by lower earnings before income tax in 2024;
• Unfavourable change in non-cash operating working capital balances due to lower accounts payables and accrued liabilities, partially offset by lower collateral provided as a result of market price volatility;
• Higher interest expense on debt primarily due to lower capitalized interest resulting from lower construction activity in 2024 compared to 2023; and
• Lower interest income due to lower cash balances and lower interest rates.

FCF totalled $569 million for the year ended Dec. 31, 2024, compared to $890 million for the same period in 2023, a decrease of $321 million, or 36 per cent, primarily driven by:

• The adjusted EBITDA items noted above;
• Higher current income tax expense due to the full utilization of Canadian non-capital loss carryforwards in 2023, partially offset by lower earnings before income taxes in 2024; and
• Higher net interest expense due to lower capitalized interest resulting from lower construction activity in 2024 compared to 2023, and lower interest income due to lower cash balances and interest rates in 2024 compared to prior year; partially offset by
• Lower distributions paid to subsidiaries' non-controlling interests relating to lower TA Cogen net earnings resulting from lower merchant pricing in the Alberta market and the cessation of distributions to TransAlta Renewables non-controlling interest;
• Lower sustaining capital expenditures due to the receipt of a lease incentive related to the Company's head office and lower planned major maintenance at our Alberta and Western Australian gas facilities, partially offset by higher major maintenance at our Alberta Hydro assets; and
• Higher provisions accrued in the current year compared to the prior year resulting in higher FCF.

Earnings before income taxes totalled $319 million for the year ended Dec. 31, 2024, compared to $880 million in the same period in 2023, a decrease of $561 million, or 64 per cent.

Net earnings attributable to common shareholders totalled $177 million for the year ended Dec. 31, 2024, compared to $644 million in the same period in 2023, a decrease of $467 million, or 73 per cent, primarily due to:

• The adjusted EBITDA items discussed above;
• Higher asset impairment charges due to an increase in decommissioning and restoration provisions on retired assets, driven by a decrease in discount rates and revisions in estimated decommissioning costs and higher impairment charges related to development projects that are no longer proceeding;
• Lower unrealized mark-to-market gains and lower realized gains on closed exchange positions in the Energy Marketing segment mainly driven by market volatility across North American power and natural gas markets;
• Higher unrealized mark-to-market losses recorded in the Wind and Solar segment primarily related to the long-term wind energy sales at the Oklahoma facilities;
• Higher interest expense due to lower capitalized interest during 2024 resulting from lower construction activity in 2024 compared to 2023;
• Lower capacity payments in 2024 for Southern Cross Energy in Western Australia due to the scheduled conclusion on Dec. 31, 2023 of the demand capacity charge under the customer contract, partially offset by the commencement in March 2024 of capacity payments for the Mount Keith 132kV expansion;
• Heartland acquisition-related transaction and restructuring costs;
• Lower interest income due to lower cash balances and lower interest rates during 2024;
• Higher spending in connection with planning and design work on a planned upgrade to the ERP system;
• Lower income tax expense due to lower earnings; and
• Penalties assessed by the Alberta Market Surveillance Administrator for self-reported contraventions pertaining to Hydro ancillary services provided during 2021 and 2022; partially offset by
• Lower depreciation and amortization compared to 2023 related to revisions of useful lives of certain facilities in prior and current periods, partially offset by the commercial operation of new facilities during the year and the return to service of the Kent Hills wind facilities;
• Higher unrealized mark-to-market gains recorded in the Energy Transition segment primarily related to favourable changes in forward prices;
• A recovery related to the reversal of previously derecognized Canadian deferred tax assets; and
• Higher net other operating income mainly due to Sundance A decommissioning cost reimbursement.
  

Fourth Quarter Financial Results Summary

Fourth quarter 2024 results were in-line with management's expectations due to active management of the Company's merchant portfolio and hedging strategies, despite lower power prices in the Alberta and mid-Columbia markets. The Company settled a higher volume of hedges that were significantly above average spot prices during the period. The acquisition of Heartland on Dec. 4, 2024 positively contributed to production in the Gas segment and further diversifies TransAlta’s competitive portfolio in the highly dynamic and shifting electricity landscape in Alberta by adding 1.7 GW to gross installed capacity.

Availability for the three months ended Dec. 31, 2024, was 87.8 per cent, compared to 86.9 per cent for the same period in 2023, an increase of 0.9 percentage points, primarily due to:

• The addition of the White Rock and Horizon Hill wind facilities which operated with high availability;
• The return to service of the Kent Hills wind facilities;
• Higher availability in the Hydro segment due to lower planned outages;
• Higher availability in the Energy Transition segment due to lower unplanned outages; and
• Positive contribution from the addition of the gas facilities acquired with Heartland; partially offset by
• Lower availability for the Gas segment due to planned outages at Sarnia, Sheerness and Keephills.

Production for the three months ended Dec. 31, 2024, was 6,199 GWh, compared to 5,783 GWh for the same period in 2023. The increase of 416 GWh, or seven per cent, was primarily due to:

• Higher production in the Wind and Solar segment due to the addition of the Horizon Hill and White Rock West and East wind facilities during 2024;
• Higher production in the Hydro segment compared to the same period in 2023 due to water conservation in the fourth quarter of 2023 that resulted in lower production volumes compared to the current period; partially offset by
• Lower production in the Energy Transition segment due to higher dispatch optimization, which negatively affected merchant production; and
• Lower production in the Gas segment driven by lower availability at the Sarnia facility due to planned outages, higher economic dispatch in Alberta and lower production from Western Australia due to lower demand, partially offset by positive contribution from the Heartland gas facilities.

Adjusted EBITDA for the three months ended Dec. 31, 2024, was $285 million, compared to $289 million in the same period of 2023, a decrease of $4 million, or one per cent. The major factors impacting adjusted EBITDA are summarized below:

• Gas adjusted EBITDA decreased by $25 million, or 18 per cent, due to lower realized power prices in Alberta, an increase in the carbon price in Canada and higher OM&A driven by higher maintenance costs at the South Hedland facility, partially offset by a higher volume of favourable hedging positions settled, positive contribution from the Heartland gas facilities and lower capacity payments;
• Corporate adjusted EBITDA decreased by $8 million, or 27 per cent, due to higher spending to support strategic and growth initiatives; partially offset by
• Wind and Solar adjusted EBITDA increasing by $13 million, or 16 per cent, due to environmental and tax attributes revenues from the sale of PTCs from the White Rock and Horizon Hill wind facilities to taxable US counterparties, higher revenues driven by increased production from the addition of the White Rock and Horizon Hill wind facilities and the return to service of the Kent Hills wind facilities, partially offset by unfavourable merchant power prices in Alberta;
• Energy Marketing adjusted EBITDA increasing by $13 million, or 93 per cent, due to favourable market volatility and the timing of realized settled trades during 2024 in comparison to the same period in 2023;
• Energy Transition adjusted EBITDA increasing by $2 million, or eight per cent, compared to 2023, primarily due to lower fuel and purchased power costs, partially offset by increased economic dispatch due to lower market prices; and
• Hydro adjusted EBITDA increasing by $1 million, or two per cent, due to higher merchant revenues driven by higher volumes, partially offset by lower spot power prices and lower environmental and tax attributes revenues.

FCF totalled $48 million for the three months ended Dec. 31, 2024, compared to $121 million in the same period in 2023, a decrease of $73 million, or 60 per cent, primarily due to:

• The adjusted EBITDA items noted above;
• Higher realized foreign exchange losses compared to realized foreign exchange gains in the comparative period;
• Higher current income tax expense due to the full utilization of Canadian non-capital loss carryforwards in 2023, partially offset by a higher loss before income taxes in the current period compared to the same period in 2023;
• Higher net interest expense due to lower capitalized interest as a result of capital projects being completed in the first half of 2024 and lower interest income due to lower cash balances in 2024; and
• Higher dividends paid on preferred shares; partially offset by
• Lower distributions paid to subsidiaries' non-controlling interests due to lower TA Cogen net earnings;
• Lower sustaining capital due to lower planned maintenance at the Alberta gas facilities, partially offset by higher planned maintenance at the Sarnia cogeneration facility and Alberta hydro facilities; and
• Higher provisions accrued in the current year compared to the prior year resulting in higher FCF.

Net loss attributable to common shareholders for the three months ended Dec. 31, 2024, was $65 million, compared to a net loss of $84 million in the same period of 2023, an improvement of $19 million, or 23 per cent, primarily due to:

• The adjusted EBITDA items discussed above;
• Higher interest expense due to lower capitalized interest in the fourth quarter of 2024 resulting from lower capital activity compared to the same period in 2023;
• Heartland acquisition-related transaction and restructuring costs in the fourth quarter of 2024;
• Higher ERP upgrade costs related to planning and design work;
• Penalties assessed by the Alberta Market Surveillance Administrator for self-reported contraventions pertaining to Hydro ancillary services provided during 2021 and 2022;
• Higher depreciation and amortization due to the commercial operation of the White Rock and Horizon Hill wind facilities during 2024; and
• Higher taxes other than income taxes, mainly consisting of property taxes due to the addition of new wind facilities during 2024; partially offset by
• Higher realized and unrealized foreign exchange gains;
• Lower realized gains on closed exchange positions in 2024 compared to the same period in 2023;
• An income tax recovery relative to the prior period expense as a result of a higher loss before income taxes due to the above noted items; in addition to lower non-deductible expenses;
• Lower net earnings attributable to non-controlling interest compared to the same period in 2023 due to lower merchant pricing in the Alberta market;
• Higher net other operating income mainly due to Sundance A decommissioning cost reimbursement; and
• Lower asset impairment charges related to the decommissioning and restoration provisions on retired assets driven by lower discount rates in the current period compared to the same period in 2023, partially offset by impairment charges related to development projects that are no longer proceeding.

Alberta Electricity Portfolio

For the three months and year ended Dec. 31, 2024, the Alberta electricity portfolio generated 3,150 GWh and 11,809 GWh, respectively, compared to 2,989 GWh and 11,759 GWh, respectively, in the same periods in 2023. The annual production increase of 50 GWh, or 0.4 per cent, was primarily due to:

• Higher production in the Gas segment due to the addition of gas facilities from the acquisition of Heartland; and
• A full-year of production from the addition of the Garden Plain wind facility, which was commissioned in August 2023; partially offset by
• Higher dispatch optimization in the Gas segment; and
• Lower production from the Alberta hydro facilities due to lower water resources compared to the prior year.

The fourth quarter production increase of 161 GWh, or five per cent, benefited from:

• Higher production from the Gas segment due to the Heartland acquisition; and
• Higher production from the Alberta hydro facilities due to significant water conservation during the fourth quarter of 2023; partially offset by
• Higher economic dispatch for the Alberta gas facilities; and
• Lower production in the Wind and Solar segment due to lower wind resource.

Gross margin for the Alberta portfolio for the three months and year ended Dec. 31, 2024, was $191 million and $856 million, respectively, a decrease of $24 million and $392 million, respectively, compared to the same periods in 2023. The annual decrease was primarily due to:

• The impact of lower Alberta spot power prices and lower hydro ancillary services prices;
• Increased dispatch optimization in the Gas segment driven by lower power prices; and
• An increase in the carbon price per tonne from $65 in 2023 to $80 in 2024; partially offset by
• Higher gains realized on financial hedges settled in the period;
• Higher environmental and tax attributes revenues due to the increased sales of emission credits to third parties and intercompany sales from the Hydro segment to the Gas segment;
• The utilization of emission credits in the Gas segment in 2024 to settle a portion of our 2023 GHG obligation;
• Higher hydro ancillary services volumes due to increased demand by the AESO; and
• Lower natural gas prices.

Gross margin for the three months ended Dec. 31, 2024 was impacted by:

• Lower Alberta spot power prices;
• Higher carbon compliance costs due to increase in the carbon price from $65 per tonne in 2023 to $80 per tonne in 2024; and
• Higher purchased power due to the contractual requirement to fulfill physical power trades; partially offset by
• Higher gains realized on financial hedges settled in the period.

Alberta power prices for 2024 were lower compared to 2023. The average spot power price per MWh for the three months and year ended Dec. 31, 2024, was $52 and $63, respectively, compared to $82 and $134, respectively, in the same periods in 2023. This was primarily due to:

• Higher generation from the addition of increased supply of new renewables and combined-cycle gas facilities into the market compared to the prior period; and
• Lower natural gas prices.

Hedged volumes for the three months and year ended Dec. 31, 2024, were 2,637 GWh and 9,080 GWh at an average price of $80 per MWh and $84 per MWh, respectively, compared to 1,824 GWh and 7,550 GWh at an average price of $90 per MWh and $110 per MWh, respectively, in 2023.

Liquidity and Financial Position

We maintain adequate available liquidity under our committed credit facilities. As at Dec. 31, 2024, we had access to $1.6 billion in liquidity, including $336 million in cash, which exceeds the funds required for committed growth, sustaining capital and productivity projects.

2025 Outlook and Financial Guidance

For 2025, management expects adjusted EBITDA to be in the range of $1.15 to $1.25 billion and FCF to be in the range of $450 to $550 million, based on the following, relative to 2024:

• Higher contribution from the wind and solar portfolio due to a full-year impact of new asset additions of the White Rock and Horizon Hill wind facilities;
• Contribution from assets acquired with Heartland;
• Lower contributions from the legacy merchant hydro, wind and gas assets in Alberta which are expected to step down due to lower expected average power prices in Alberta given baseload gas and renewables supply additions in late 2024 and 2025;
• Lower current income tax expense in 2025 compared to 2024 actual; and
• Increased net interest expense in 2025 as a result of the Heartland acquisition and lower interest income earned on lower cash deposits and lower capitalized interest on growth projects.
  

The following table outlines our expectations regarding key financial targets and related assumptions for 2025 and should be read in conjunction with the narrative discussion that follows and the Governance and Risk Management section of the MD&A for additional information:

Measure	2025 Target	2024 Target	2024 Actual
Adjusted EBITDA	$1,150 to $1,250 million	$1,150 to $1,300 million	$1,253 million
FCF	$450 to $550 million	$450 to $600 million	$569 million
FCF per share	$1.51 to $1.85	$1.47 to $1.96	$1.88
Annual dividend per share	$0.26 annualized	$0.24 annualized	$0.24 annualized

The Company's outlook for 2025 may be impacted by a number of factors as detailed further below.

Market	2025 Assumptions	2024 Assumptions	2024 Actual
Alberta spot ($/MWh)	$40 to $60	$75 to $95	$63
Mid-Columbia spot (US$/MWh)	US$50 to US$70	US$85 to US$95	US$76
AECO gas price ($/GJ)	$1.60 to $2.10	$2.50 to $3.00	$1.29

Alberta spot price sensitivity: a +/- $1 per MWh change in spot price is expected to have a +/-$3 million impact on adjusted EBITDA for 2025.

Other assumptions relevant to the 2025 outlook

	2025 Assumptions	2024 Assumptions	2024 Actual
Energy Marketing gross margin	$110 to $130 million	$110 to $130 million	$167 million
Sustaining capital	$145 to $165 million	$130 to $150 million	$142 million
Current income tax expense	$95 to $130 million	$95 to $130 million	$143 million
Net interest expense	$255 to $275 million	$240 to $260 million	$231 million

Hedging assumptions	Q1 2025		Q2 2025		Q3 2025		Q4 2025		2026
Hedged production (GWh)	2,117		1,758		1,942		1,845		4,713
Hedge price ($/MWh)	$72		$70		$70		$70		$75
Hedged gas volumes (GJ)	14 million		6 million		6 million		6 million		18 million
Hedge gas prices ($/GJ)	$2.98		$3.63		$3.77		$3.65		$3.67

Conference call

TransAlta will host a conference call and webcast at 9:00 a.m. MST (11:00 a.m. EST) today, Feb. 20, 2025, to discuss our fourth quarter and year end 2024 results. The call will begin with comments from John Kousinioris, President and Chief Executive Officer, and Joel Hunter, EVP Finance and Chief Financial Officer, followed by a question-and-answer period.

Fourth Quarter and Full Year 2024 Conference Call

Webcast link: https://edge.media-server.com/mmc/p/zd49obg6 

To access the conference call via telephone, please register ahead of time using the call link here: https://register.vevent.com/register/BI5c12d9a2da0e4e06892f413e217f0350. Once registered, participants will have the option of 1) dialing into the call from their phone (via a personalized PIN); or 2) clicking the “Call Me” option to receive an automated call directly to their phone.

Related materials will be available on the Investor Centre section of TransAlta’s website at https://transalta.com/investors/presentations-and-events/. If you are unable to participate in the call, the replay will be accessible at https://edge.media-server.com/mmc/p/zd49obg6. A transcript of the broadcast will be posted on TransAlta’s website once it becomes available.

Notes

(1)These items (adjusted EBITDA, FCF and annual average EBITDA) 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 (loss) trends more readily in comparison with prior periods’ results. Please refer to the Non-IFRS Measures section of this earnings release for further discussion of these items, including, where applicable, reconciliations to measures calculated in accordance with IFRS.
(2)Funds from operations (FFO) per share and free cash flow (FCF) per share are calculated using the weighted average number of common shares outstanding during the period. Refer to the Additional IFRS Measures and Non-IFRS Measures section of the MD&A for the purpose of these non-‍IFRS ratios.

Non-IFRS financial measures and other specified financial measures

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 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, as an alternative to, or more meaningful than, our IFRS results.

Adjusted EBITDA

Each business segment assumes responsibility for its operating results measured by adjusted EBITDA. Adjusted EBITDA is an important metric for management that represents our core operational results. 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.

Average Annual EBITDA

Average annual EBITDA is a forward-looking non-IFRS financial measure that is used to show the average annual EBITDA that the project is expected to generate.

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. The most directly comparable IFRS measure is Cash Flow from Operations.

Free Cash Flow (FCF)

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. The most directly comparable IFRS measure is Cash Flow from Operations.

Non-IFRS Ratios

FFO per share, FCF per share and adjusted net debt to adjusted EBITDA are non-IFRS ratios that are presented in the MD&A. Refer to the Reconciliation of Cash Flow from Operations to FFO and FCF and Key Non-IFRS Financial Ratios sections of the 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 are non-IFRS ratios.

Reconciliation of these non-IFRS financial measures to the most comparable IFRS measure are provided below.

Reconciliation of Non-IFRS Measures on a Consolidated Basis

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the three months ended Dec. 31, 2024:

Three months ended Dec. 31, 2024 $ millions	Hydro		Wind & Solar(1)		Gas		Energy Transition		Energy Marketing	Corporate		Total		Equity accounted investments(1)		Reclass adjustments		IFRS financials
Revenues	93		104		319		155		14	—		685		(7	)	—		678
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	4		23		26		(8	)	19	—		64		—		(64	)	—
Realized gains (losses) on closed exchange positions	—		—		(1	)	2		1	—		2		—		(2	)	—
Decrease in finance lease receivable	—		1		5		—		—	—		6		—		(6	)	—
Finance lease income	—		2		3		—		—	—		5		—		(5	)	—
Revenues from Planned Divestitures	—		—		(1	)	—		—	—		(1	)	—		1		—
Brazeau penalties	(20	)	—		—		—		—	—		(20	)	—		20		—
Unrealized foreign exchange gain on commodity	—		—		(1	)	—		—	—		(1	)	—		1		—
Adjusted revenues	77		130		350		149		34	—		740		(7	)	(55	)	678
Fuel and purchased power	3		8		136		102		—	—		249		—		—		249
Reclassifications and adjustments:
Fuel and purchased power related to Planned Divestitures	—		—		(1	)	—		—	—		(1	)	—		1		—
Australian interest income	—		—		(1	)	—		—	—		(1	)	—		1		—
Adjusted fuel and purchased power	3		8		134		102		—	—		247		—		2		249
Carbon compliance	—		—		39		—		—	—		39		—		—		39
Gross margin	74		122		177		47		34	—		454		(7	)	(57	)	390
OM&A	47		27		67		19		7	68		235		(1	)	—		234
Reclassifications and adjustments:
Brazeau penalties	(31	)	—		—		—		—	—		(31	)	—		31		—
ERP integration costs	—		—		—		—		—	(14	)	(14	)	—		14		—
Acquisition-related transaction and restructuring costs	—		—		—		—		—	(16	)	(16	)	—		16		—
Adjusted OM&A	16		27		67		19		7	38		174		(1	)	61		234
Taxes, other than income taxes	1		3		4		—		—	—		8		1		—		9
Net other operating income	—		(3	)	(10	)	(9	)	—	—		(22	)	—		—		(22	)
Reclassifications and adjustments:
Sundance A decommissioning cost reimbursement	—		—		—		9		—	—		9		—		(9	)	—
Adjusted net other operating income	—		(3	)	(10	)	—		—	—		(13	)	—		(9	)	(22	)
Adjusted EBITDA(2)	57		95		116		28		27	(38	)	285
Equity income																		2
Finance lease income																		5
Depreciation and amortization																		(143	)
Asset impairment charges																		(20	)
Interest income																		11
Interest expense																		(92	)
Foreign exchange gain																		17
Loss before income taxes																		(51	)

(1)  The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)  Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Non-IFRS financial measures and other specified financial measures section in this earnings release and may not be comparable to similar measures presented by other issuers.

The following table reflects adjusted EBITDA by segment and provides reconciliation to loss before income taxes for the three months ended Dec. 31, 2023:

Three months ended Dec. 31, 2023 $ millions	Hydro		Wind & Solar(1)		Gas		Energy Transition	Energy Marketing		Corporate		Total		Equity accounted investments(1)		Reclass adjustments		IFRS financials
Revenues	77		94		246		175	39		—		631		(7	)	—		624
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	(2	)	20		53		7	(19	)	—		59		—		(59	)	—
Realized gain on closed exchange positions	—		—		23		—	4		—		27		—		(27	)	—
Decrease in finance lease receivable	—		—		15		—	—		—		15		—		(15	)	—
Finance lease income	—		—		2		—	—		—		2		—		(2	)	—
Unrealized foreign exchange gain on commodity	—		—		1		—	—		—		1		—		(1	)	—
Adjusted revenues	75		114		340		182	24		—		735		(7	)	(104	)	624
Fuel and purchased power	5		8		127		138	—		—		278		—		—		278
Reclassifications and adjustments:
Australian interest income	—		—		(1	)	—	—		—		(1	)	—		1		—
Adjusted fuel and purchased power	5		8		126		138	—		—		277		—		1		278
Carbon compliance	—		—		27		—	—		—		27		—		—		27
Gross margin	70		106		187		44	24		—		431		(7	)	(105	)	319
OM&A	13		25		56		18	10		29		151		(1	)	—		150
Taxes, other than income taxes	1		1		—		—	—		1		3		—		—		3
Net other operating income	—		(3	)	(10	)	—	—		—		(13	)	—		—		(13	)
Adjusted net other operating income	—		(2	)	(10	)	—	—		—		(12	)	—		(1	)	(13	)
Adjusted EBITDA(2)	56		82		141		26	14		(30	)	289
Equity income																		3
Finance lease income																		2
Depreciation and amortization																		(132	)
Asset impairment charges																		(26	)
Interest income																		12
Interest expense																		(66	)
Foreign exchange loss																		(7	)
Loss before income taxes																		(35	)

(1)  The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)  Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Non-IFRS financial measures and other specified financial measures section in this earnings release and may not be comparable to similar measures presented by other issuers.

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the year ended Dec. 31, 2024:

Year ended Dec. 31, 2024 $ millions	Hydro		Wind & Solar(1)		Gas		Energy Transition		Energy Marketing		Corporate		Total		Equity accounted investments(1)		Reclass adjustments		IFRS financials
Revenues	409		357		1,350		616		168		(34	)	2,866		(21	)	—		2,845
Reclassifications and adjustments:
Unrealized mark-to-market (gain) loss	1		84		(60	)	(36	)	14		—		3		—		(3	)	—
Realized gain (loss) on closed exchange positions	—		—		7		2		(15	)	—		(6	)	—		6		—
Decrease in finance lease receivable	—		2		19		—		—		—		21		—		(21	)	—
Finance lease income	—		6		8		—		—		—		14		—		(14	)	—
Revenues from Planned Divestitures	—		—		(1	)	—		—		—		(1	)	—		1		—
Brazeau penalty	(20	)	—		—		—		—		—		(20	)	—		20		—
Unrealized foreign exchange loss on commodity	—		—		(2	)	—		—		—		(2	)	—		2		—
Adjusted revenues	390		449		1,321		582		167		(34	)	2,875		(21	)	(9	)	2,845
Fuel and purchased power	16		30		475		418		—		—		939		—		—		939
Reclassifications and adjustments:
Fuel and purchased power related to Planned Divestitures	—		—		(1	)	—		—		—		(1	)	—		1		—
Australian interest income	—		—		(4	)	—		—		—		(4	)	—		4		—
Adjusted fuel and purchased power	16		30		470		418		—		—		934		—		5		939
Carbon compliance	—		—		145		1		—		(34	)	112		—		—		112
Gross margin	374		419		706		163		167		—		1,829		(21	)	(14	)	1,794
OM&A	86		97		198		69		36		173		659		(4	)	—		655
Reclassifications and adjustments:
Brazeau penalty	(31	)	—		—		—		—		—		(31	)	—		31		—
ERP implementation costs	—		—		—		—		—		(14	)	(14	)	—		14		—
Acquisition-related transaction and restructuring costs	—		—		—		—		—		(24	)	(24	)			24		—
Adjusted OM&A	55		97		198		69		36		135		590		(4	)	69		655
Taxes, other than income taxes	3		16		13		3		—		1		36		—		—		36
Net other operating income	—		(10	)	(40	)	(9	)	—		—		(59	)	—		—		(59	)
Reclassifications and adjustments:
Sundance A decommissioning cost reimbursement	—		—		—		9		—		—		9		—		(9	)	—
Adjusted net other operating income	—		(10	)	(40	)	—		—		—		(50	)	—		(9	)	(59	)
Adjusted EBITDA(2)	316		316		535		91		131		(136	)	1,253
Equity income																			5
Finance lease income																			14
Depreciation and amortization																			(531	)
Asset impairment charges																			(46	)
Interest income																			30
Interest expense																			(324	)
Foreign exchange gain																			5
Gain on sale of assets and other																			4
Earnings before income taxes																			319

(1)  The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)  Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Non-IFRS financial measures and other specified financial measures section in this earnings release and may not be comparable to similar measures presented by other issuers.

The following table reflects adjusted EBITDA by segment and provides reconciliation to earnings before income taxes for the year ended Dec. 31, 2023:

Year ended Dec. 31, 2023 $ millions	Hydro		Wind & Solar(1)		Gas		Energy Transition		Energy Marketing		Corporate		Total		Equity accounted investments(1)		Reclass adjustments		IFRS financials
Revenues	533		357		1,514		751		220		1		3,376		(21	)	—		3,355
Reclassifications and adjustments:
Unrealized mark-to-market loss	(4	)	16		(67	)	(5	)	23		—		(37	)	—		37		—
Realized gain (loss) on closed exchange positions	—		—		10		—		(91	)	—		(81	)	—		81		—
Decrease in finance lease receivable	—		—		55		—		—		—		55		—		(55	)	—
Finance lease income	—		—		12		—		—		—		12		—		(12	)	—
Unrealized foreign exchange gain on commodity	—		—		1		—		—		—		1		—		(1	)	—
Adjusted revenues	529		373		1,525		746		152		1		3,326		(21	)	50		3,355
Fuel and purchased power	19		30		453		557		—		1		1,060		—		—		1,060
Reclassifications and adjustments:
Australian interest income	—		—		(4	)	—		—		—		(4	)	—		4		—
Adjusted fuel and purchased power	19		30		449		557		—		1		1,056		—		4		1,060
Carbon compliance	—		—		112		—		—		—		112		—		—		112
Gross margin	510		343		964		189		152		—		2,158		(21	)	46		2,183
OM&A	48		80		192		64		43		115		542		(3	)	—		539
Taxes, other than income taxes	3		12		11		3		—		1		30		(1	)	—		29
Net other operating income	—		(7	)	(40	)	—		—		—		(47	)			—		(47	)
Reclassifications and adjustments:
Insurance recovery	—		1		—		—		—		—		1		—		(1	)	—
Adjusted net other operating income	—		(6	)	(40	)	—		—		—		(46	)	—		(1	)	(47	)
Adjusted EBITDA(2)	459		257		801		122		109		(116	)	1,632
Equity income																			4
Finance lease income																			12
Depreciation and amortization																			(621	)
Asset impairment reversals																			48
Interest income																			59
Interest expense																			(281	)
Foreign exchange gain																			(7	)
Gain on sale of assets and other																			4
Earnings before income taxes																			880

(1)  The Skookumchuck wind facility has been included on a proportionate basis in the Wind and Solar segment.
(2)  Adjusted EBITDA is not defined and has no standardized meaning under IFRS. Refer to the Non-IFRS financial measures and other specified financial measures section in this earnings release and may not be comparable to similar measures presented by other issuers.

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:

	Three Months Ended				Year Ended
$ millions, unless otherwise stated	Dec. 31, 2024		Dec. 31, 2023		Dec. 31, 2024		Dec. 31, 2023
Cash flow from operating activities(1)	215		310		796		1,464
Change in non-cash operating working capital balances	(97	)	(135	)	(38	)	(124	)
Cash flow from operations before changes in working capital	118		175		758		1,340
Adjustments
Share of adjusted FFO from joint venture(1)	4		3		8		8
Decrease in finance lease receivable	6		15		21		55
Clean energy transition provisions and adjustments(2)	—		4		—		11
Sundance A decommissioning cost reimbursement	(9	)	—		(9	)	—
Realized gain (loss) on closed exchanged positions	2		27		(6	)	(81	)
Acquisition-related transaction and restructuring costs	11		—		19		—
Other(3)	5		5		19		18
FFO(4)	137		229		810		1,351
Deduct:
Sustaining capital(1)	(67	)	(74	)	(142	)	(174	)
Productivity capital	(1	)	(1	)	(1	)	(3	)
Dividends paid on preferred shares	(13	)	(12	)	(52	)	(51	)
Distributions paid to subsidiaries’ non-controlling interests	(6	)	(19	)	(40	)	(223	)
Principal payments on lease liabilities	(3	)	(2	)	(6	)	(10	)
Other	1		—		—		—
FCF(4)	48		121		569		890
Weighted average number of common shares outstanding in the period	298		308		302		276
FFO per share(4)	0.46		0.74		2.68		4.89
FCF per share(4)	0.16		0.39		1.88		3.22

(1)  Includes our share of amounts for the Skookumchuck wind facility, an equity-accounted joint venture.
(2)  2023 includes amounts related to onerous contracts recognized in 2021 and a voluntary contribution to the US Defined Benefit Pension Plan for the Centralia thermal facility.
(3)  Other consists of production tax credits, which is a reduction to tax equity debt, less distributions from an equity-accounted joint venture.
(4)  These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. Refer to the Non-IFRS Measures section in this earnings release .

The table below provides a reconciliation of our adjusted EBITDA to our FFO and FCF:

	Three Months Ended				Year Ended
$ millions, unless otherwise stated	Dec. 31, 2024		Dec. 31, 2023		Dec. 31, 2024		Dec. 31, 2023
Adjusted EBITDA(1)(4)	285		289		1,253		1,632
Provisions	2		(1	)	10		(1	)
Net interest expense(2)	(64	)	(41	)	(231	)	(164	)
Current income tax recovery (expense)	(20	)	5		(143	)	(50	)
Realized foreign exchange gain (loss)	(20	)	9		(27	)	(4	)
Decommissioning and restoration costs settled	(12	)	(15	)	(41	)	(37	)
Other non-cash items	(34	)	(17	)	(11	)	(25	)
FFO(3)(4)	137		229		810		1,351
Deduct:
Sustaining capital(4)	(67	)	(74	)	(142	)	(174	)
Productivity capital	(1	)	(1	)	(1	)	(3	)
Dividends paid on preferred shares	(13	)	(12	)	(52	)	(51	)
Distributions paid to subsidiaries’ non-controlling interests	(6	)	(19	)	(40	)	(223	)
Principal payments on lease liabilities	(3	)	(2	)	(6	)	(10	)
Other	1		—		—		—
FCF(4)	48		121		569		890

(1)  Adjusted EBITDA is defined in the Additional IFRS Measures and Non-IFRS Measures of this earnings release and reconciled to earnings (loss) before income taxes above.
(2) Net interest expense includes interest expense less interest income and excludes non-cash items like financing amortization and accretion.
(3)  These items are not defined and have no standardized meaning under IFRS and may not be comparable to similar measures presented by other issuers. FFO and FCF are defined in the Non-IFRS financial measures and other specified financial measures section of in this earnings release and reconciled to cash flow from operating activities above.
(4)  Includes our share of amounts for Skookumchuck wind facility, an equity-accounted joint venture.

TransAlta is in the process of filing its Annual Information Form, Audited Consolidated Financial Statements and accompanying notes, as well as the associated Management’s Discussion & Analysis (MD&A). These documents will be available today on the Investors section of TransAlta’s website at www.transalta.com or through SEDAR at www.sedarplus.ca.

TransAlta will also be filing its Form 40-F with the US Securities and Exchange Commission. The form will be available through their website at www.sec.gov. Paper copies of all documents are available to shareholders free of charge upon request.

About TransAlta Corporation:

TransAlta owns, operates and develops a diverse fleet of electrical power generation assets in Canada, the United States and Western Australia with a focus on long-term shareholder value. TransAlta provides municipalities, medium and large industries, businesses and utility customers with clean, affordable, energy efficient and reliable power. Today, TransAlta is one of Canada’s largest producers of wind power and Alberta’s largest producer of hydro-electric power. For over 112 years, TransAlta has been a responsible operator and a proud member of the communities where we operate and where our employees work and live. TransAlta aligns its corporate goals with the UN Sustainable Development Goals and the Future-Fit Business Benchmark, which also defines sustainable goals for businesses. Our reporting on climate change management has been guided by the International Financial Reporting Standards (IFRS) S2 Climate-related Disclosures Standard and the Task Force on Climate-related Financial Disclosures (TCFD) recommendations. TransAlta has achieved a 70 per cent reduction in GHG emissions or 22.7 million tonnes CO2e since 2015 and received an upgraded MSCI ESG rating of AA.

For more information about TransAlta, visit our web site at transalta.com.

Cautionary Statement Regarding Forward-Looking Information

This news release 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"). 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 or implied by the forward-looking statements. In particular, this news release contains forward-looking statements about the following, among other things: the strategic objectives of the Company and that the execution of the Company's strategy will realize value for shareholders; our capital allocation and financing strategy; our sustainability goals and targets, including those in our 2024 Sustainability Report; our 2025 Outlook; our financial and operational performance, including our hedge position; optimizing and diversifying our existing assets; the increasingly contracted nature of our fleet; expectations about strategies for growth and expansion, including opportunities for Centralia redevelopment, and data centre opportunities; expected costs and schedules for planned projects; expected regulatory processes and outcomes, including in relation to the Alberta restructured energy market; the power generation industry and the supply and demand of electricity; the cyclicality of our business; expected outcomes with respect to legal proceedings; the expected impact of future tax and accounting changes; and expected industry, market and economic conditions.

The forward-looking statements contained in this news release are based on many assumptions including, but not limited to, the following: no significant changes to applicable laws and regulations; no unexpected delays in obtaining required regulatory approvals; no material adverse impacts to investment and credit markets; no significant changes to power price and hedging assumptions; no significant changes to gas commodity price assumptions and transport costs; no significant changes to interest rates; no significant changes to the demand and growth of renewables generation; no significant changes to the integrity and reliability of our facilities; no significant changes to the Company's debt and credit ratings; no unforeseen changes to economic and market conditions; and no significant event occurring outside the ordinary course of business.

These assumptions are based on information currently available to TransAlta, including information obtained from third-party sources. Actual results may differ materially from those predicted. Factors that may adversely impact what is expressed or implied by forward-looking statements contained in this news release include, but are not limited to: fluctuations in power prices; changes in supply and demand for electricity; our ability to contract our electricity generation for prices that will provide expected returns; our ability to replace contracts as they expire; risks associated with development projects and acquisitions; any difficulty raising needed capital in the future on reasonable terms or at all; our ability to achieve our targets relating to ESG; long-term commitments on gas transportation capacity that may not be fully utilized over time; changes to the legislative, regulatory and political environments; environmental requirements and changes in, or liabilities under, these requirements; operational risks involving our facilities, including unplanned outages and equipment failure; disruptions in the transmission and distribution of electricity; reductions in production; impairments and/or writedowns 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; reduced labour availability and ability to continue to staff our operations and facilities; disruptions to our supply chains; climate-change related risks; reductions to our generating units' relative efficiency or capacity factors; general economic risks, including deterioration of equity and debt markets, increasing interest rates or rising inflation; general domestic and international economic and political developments, including potential trade tariffs; industry risk and competition; counterparty credit risk; inadequacy or unavailability of insurance coverage; increases in the Company's income taxes and any risk of reassessments; 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 "Governance and Risk Management" in the MD&A, which section is incorporated by reference herein.

Readers are urged to consider these factors carefully when evaluating the forward-looking statements and are cautioned not to place undue reliance on them. The forward-looking statements included in this news release 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.

Note: All financial figures are in Canadian dollars unless otherwise indicated.

For more information:

Investor Inquiries:	Media Inquiries:
Phone: 1-800-387-3598 in Canada and US	Phone: 1-855-255-9184
Email: investor_relations@transalta.com	Email: ta_media_relations@transalta.com