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Published Feb 20, 2025 • 14 minute read
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CALGARY, Alberta, Feb. 20, 2025 (GLOBE NEWSWIRE) — Prairie Provident Resources Inc. (“Prairie Provident” or the “Company”) (TSX:PPR) is pleased to announce the closing of the first tranche of its recently announced equity financing, for $4,800,000 in gross proceeds from its principal and largest shareholder, PCEP Canadian Holdco, LLC (“PCEP”) upon the issue of 112,941,176 common shares (“Common Shares”) at a price of $0.0425 per Common Share (the “First Tranche Closing”).
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The First Tranche Closing is part of the $9,100,000 brokered equity financing previously announced by the Company, led by Research Capital Corporation as the lead agent and sole bookrunner on behalf of a syndicate of agents including Haywood Securities Inc. (collectively the “Agents”) and consisting of:
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The First Tranche Closing was completed under the Private Placement.
Prairie Provident’s Top Tier Basal Quartz Play in Michichi: A Unique Publicly Traded BQ Junior
Prairie Provident has established its Basal Quartz (“BQ”) play in the Michichi core area as a significant growth driver, supported by robust well economics, an extensive drilling inventory, and strategic infrastructure. The Company has a land position of approximately 153,000 net acres (239 net sections) in Michichi, of which it has identified over 40 horizontal BQ drilling opportunities, providing ample room for growth. Publicly-available industry data indicates that production along the BQ trend has surpassed 40,000 boe/d (77% liquids), with operators having drilled over 100 horizontal wells in 2024 alone, further de-risking the play. Offset competitor wells in analogous zones have demonstrated peak production rates exceeding 1,200 bbl/d, further validating the play’s potential. The BQ play offers attractive returns and payouts, making it, in the Company’s view, one of the most competitive plays in the Western Canadian Sedimentary Basin (WCSB). Based on internal estimates, the Company’s BQ wells have the potential to deliver impressive internal rates of return greater than 300% (based on WTI US$70/bbl and AECO C$3.00/mcf) with payout periods of approximately eight months or less.
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Additional Financing Details
As previously disclosed, PCEP and certain directors and officers of the Company intended to participate in the Offerings in an aggregate amount of approximately $7,350,000 (collectively, the “Lead Orders”). The First Tranche Closing represents $4,800,000 of this participation, with the remaining $2,550,000 in Lead Orders provided for through director commitments and the Company’s subscription agreement with PCEP. Prairie Provident expects $200,000 of the remaining Lead Orders to be fulfilled under the Private Placement and $2,350,000 to be fulfilled under the LIFE Offering. All subscriptions on account of Lead Orders are subject to insider participation limits under applicable Toronto Stock Exchange rules.
Prairie Provident intends to use the net proceeds from the Offerings to drill two additional Basal Quartz horizontal wells in the first quarter of 2025 and for working capital and general corporate purposes, including expenses related to the Offerings.
The second and final tranche of the Offerings is expected to occur on or about February 27, 2025.
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For further details regarding the Offerings, please refer to the Company’s press release dated February 11, 2025.
There is an offering document related to the LIFE Offering that can be accessed under the Company’s issuer profile at www.sedarplus.ca and on the Company’s website at www.ppr.ca. Prospective investors should read this offering document before making an investment decision.
The Common Shares issued in the First Tranche Closing are subject to a statutory hold period of four months plus a day from February 20, 2025.
In connection with the First Tranche Closing, the Company paid the Agents an advisory fee equal to 1% of gross proceeds.
This news release does not constitute an offer to sell, or the solicitation of an offer to buy, nor shall there be any sale of, any securities in the United States or to or for the account or benefit of U.S. persons or persons in the United States, or in any other jurisdiction in which, or to or for the account or benefit of any other person to whom, any such offer, solicitation or sale would be unlawful. These securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the “U.S. Securities Act”), or the securities laws of any state of the United States, and may not be offered or sold within the United States or to, or for the account or benefit of, U.S. persons or persons in the United States except in compliance with, or pursuant to an available exemption from, the registration requirements of the U.S. Securities Act and applicable U.S. state securities laws. “United States” and “U.S. person” have the meanings ascribed to them in Regulation S under the U.S. Securities Act.
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Multilateral Instrument 61-101 – Protection of Minority Security Holders in Special Transactions
PCEP’s purchase of Common Shares under the First Tranche Closing did, and the further Lead Order subscriptions as contemplated above will, constitute ‘related party transactions’ for the Company within the meaning of Multilateral Instrument 61-101 – Protection of Minority Security Holders in Special Transactions (“MI 61-101”), which are exempt from the formal valuation and minority approval requirements of MI 61-101 pursuant to sections 5.5(a) and 5.7(a) thereof on the basis that neither the fair market value of the subject matter of the transactions, nor the fair market value of the consideration for the transactions, insofar as they involve interested parties, exceeds 25% of the Company’s market capitalization as calculated for purposes of MI 61-101. Prairie Provident did not file a material change report 21 days before completion of the First Tranche Closing and, if applicable, will not be filing one at least 21 days before the anticipated closing date of the second and final tranche of the Offerings, as the overall transaction timetable is less than 21 days from commencement to closing and it is commercially impracticable to delay the process.
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ABOUT PRAIRIE PROVIDENT
Prairie Provident is a Calgary-based company engaged in the exploration and development of oil and natural gas properties in Alberta, including a position in the emerging Basal Quartz trend in the Michichi area of Central Alberta.
For further information, please contact:
Dale Miller, Executive Chairman
Phone: (403) 292-8150
Email: info@ppr.ca
Forward-Looking Information
This news release contains certain statements (“forward-looking statements”) that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future performance, events or circumstances, are based upon internal assumptions, plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “believe”, “expect”, “intend”, “plan”, “budget”, “forecast”, “target”, “estimate”, “propose”, “potential”, “project”, “seek”, “continue”, “may”, “will”, “should” or similar words suggesting future outcomes or events or statements regarding an outlook.
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Without limiting the foregoing, this news release contains forward-looking statements pertaining to: Basal Quartz drilling opportunities, including estimated payout periods on potential Basal Quartz wells; completion of the second and final tranche of the Offerings, the expected closing date thereof, and fulfillment of the Lead Orders therein; the intended use of proceeds from the Offerings; and the intended number of Basal Quartz wells that are anticipated to be drilled by the Company in the first quarter of 2025.
Forward-looking statements are based on a number of material factors, expectations or assumptions of Prairie Provident which have been used to develop such statements, but which may prove to be incorrect. Although the Company believes that the expectations and assumptions reflected in such forward-looking statements are reasonable, undue reliance should not be placed on forward-looking statements, which are inherently uncertain and depend upon the accuracy of such expectations and assumptions. Prairie Provident can give no assurance that the forward-looking statements contained herein will prove to be correct or that the expectations and assumptions upon which they are based will occur or be realized. Actual results or events will differ, and the differences may be material and adverse to the Company. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: results from drilling and development activities; consistency with past operations; the quality of the reservoirs in which Prairie Provident operates and continued performance from existing wells (including with respect to production profile, decline rate and product type mix); the continued and timely development of infrastructure in areas of new production; the accuracy of the estimates of Prairie Provident’s reserves volumes; future commodity prices; future operating and other costs; future USD/CAD exchange rates; future interest rates; continued availability of external financing and internally generated cash flow to fund Prairie Provident’s current and future plans and expenditures, with external financing on acceptable terms; the impact of competition; the general stability of the economic and political environment in which Prairie Provident operates; the general continuance of current industry conditions; the timely receipt of any required regulatory approvals; the ability of Prairie Provident to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Prairie Provident has an interest in to operate the field in a safe, efficient and effective manner; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Prairie Provident to secure adequate product transportation; the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Prairie Provident operates; and the ability of Prairie Provident to successfully market its oil and natural gas production.
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The forward-looking statements included in this news release are not guarantees of future performance or promises of future outcomes and should not be relied upon. Such statements, including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements including, without limitation: reduced access to external debt financing; higher interest costs or other restrictive terms of debt financing; changes in realized commodity prices; changes in the demand for or supply of Prairie Provident’s products; the early stage of development of some of the evaluated areas and zones; the potential for variation in the quality of the geologic formations targeted by Prairie Provident’s operations; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; the imposition of any tariffs or other restrictive trade measures or countermeasures affecting trade between Canada and the United States; changes in development plans of Prairie Provident or by third party operators; increased debt levels or debt service requirements; inaccurate estimation of Prairie Provident’s oil and reserves volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of adequate insurance coverage; the impact of competitors; and such other risks as may be detailed from time-to-time in Prairie Provident’s public disclosure documents (including, without limitation, those risks identified in this news release and Prairie Provident’s current Annual Information Form dated April 1, 2024 as filed with Canadian securities regulators and available from the SEDAR+ website (www.sedarplus.ca) under Prairie Provident’s issuer profile).
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The forward-looking statements contained in this news release speak only as of the date of this news release, and Prairie Provident assumes no obligation to publicly update or revise them to reflect new events or circumstances, or otherwise, except as may be required pursuant to applicable laws. All forward-looking statements contained in this news release are expressly qualified by this cautionary statement.
Oil and Gas Reader Advisories
Barrels of Oil Equivalent
The oil and natural gas industry commonly expresses production volumes and reserves on a “barrel of oil equivalent” basis (“boe”) whereby natural gas volumes are converted at the ratio of six thousand cubic feet to one barrel of oil. The intention is to sum oil and natural gas measurement units into one basis for improved analysis of results and comparisons with other industry participants. A boe conversion ratio of six thousand cubic feet to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip. It does not represent a value equivalency at the wellhead nor at the plant gate, which is where Prairie Provident sells its production volumes. Boe’s may therefore be a misleading measure, particularly if used in isolation. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency ratio of 6:1, utilizing a 6:1 conversion ratio may be misleading as an indication of value.
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Analogous Information
Information in this news release regarding initial production rates from offset wells drilled by other industry participants located in geographical proximity to the Company’s lands may constitute “analogous information” within the meaning of National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101). This information is derived from publicly available information sources (as at the date of this news release) that Prairie Provident believes (but cannot confirm) to be independent in nature. The Company is unable to confirm that the information was prepared by a qualified reserves evaluator or auditor within the meaning of NI 51-101, or in accordance with the Canadian Oil and Gas Evaluation (COGE) Handbook. Although the Company believes that this information regarding geographically proximate wells helps management understand and define reservoir characteristics of lands in which Prairie Provident has an interest, the data relied upon by the Company may be inaccurate or erroneous, may not in fact be indicative or otherwise analogous to the Company’s land holdings, and may not be representative of actual results from wells that may be drilled or completed by the Company in the future.
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Potential Drilling Opportunities vs Booked Locations
This news release refers to potential drilling opportunities and booked locations. Unless otherwise indicated, references to booked locations in this news release are references to proved drilling locations or probable drilling locations, being locations to which Sproule Associated Limited (Sproule) attributed proved or probable reserves in its most recent year-end evaluation of Prairie Provident’s reserves data, effective December 31, 2023. Sproule’s year‑end evaluation was in accordance with NI 51-101 and, pursuant thereto, the COGE Handbook. References in this news release to potential drilling opportunities are references to locations for which there are no attributed reserves or resources, but which the Company internally estimates can be drilled based on current land holdings, industry practice regarding well density, and internal review of geologic, geophysical, seismic, engineering, production and resource information. There is no certainty that the Company will drill any particular locations, or that drilling activity on any locations will result in additional reserves, resources or production. Locations on which Prairie Provident in fact drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, commodity prices, costs, actual drilling results, additional reservoir information and other factors. There is a higher level of risk associated with locations that are potential drilling opportunities and not booked locations. Prairie Provident generally has less information about reservoir characteristics associated with locations that are potential drilling opportunities and, accordingly, there is greater uncertainty whether wells will ultimately be drilled in such locations and, if drilled, whether they will result in additional reserves, resources or production.
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Type Well Information
Information contained in this news release regarding estimated payout periods and internal rate of return (IRR) on potential Basal Quartz wells is based on the Company’s internally-defined type wells. Type well information reflects Prairie Provident’s expectations and experience in relation to wells of the indicated types, including with respect to costs, production and decline rates. There is no assurance that actual well-related results (including payout periods and IRR) will be in accordance with those suggested by the type well information. Actual results will differ, and the difference may be material.
Payout
Prairie Provident considers payout on a well to be achieved when future net revenue from the well is equal to the capital costs to drill, complete, equip and tie-in the well based on project economics. Forecasted payout periods disclosed in this news release are based on the following commodity price and CAD/USD exchange rate assumptions: USD $70.00/bbl WTI, CAD $3.00/Mcf AECO, CAD $1.35-to-USD $1.00.
Initial Production Rates
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This news release discloses initial production rates for certain wells as indicated. Initial production rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Actual results will differ from those realized during an initial short-term production period, and the difference may be material.
Non-GAAP Measures
This news release uses the financial measure internal rate of return (IRR). IRR is a non-GAAP financial measure within the meaning of applicable Canadian securities laws , which does not have a standardized or prescribed meaning under International Financial Reporting Standards (IFRS) and may not be comparable to similar measures presented by other issuers. Investors are cautioned that non-GAAP measures should not be construed as a substitute or an alternative to net income or cash flows from operating activities as determined in accordance with IFRS. IRR is a measure used in financial analysis to estimate the profitability of potential investments and/or projects, and means the discount rate that makes the net present value equal to zero in a discounted cash flow analysis.
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Written by GlobeNewswire on . Posted in Canada. Leave a Comment
The content in this section is supplied by GlobeNewswire for the purposes of distributing press releases on behalf of its clients. Postmedia has not reviewed the content.
Author of the article:
GlobeNewswire
Published Feb 20, 2025 • 44 minute read
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.
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“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.
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“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
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Full Year 2024 Financial Highlights
Other Business Highlights and Updates
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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.
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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.
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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.
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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.
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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 | ) |
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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:
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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:
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:
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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:
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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:
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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:
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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:
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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:
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:
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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:
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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:
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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:
The fourth quarter production increase of 161 GWh, or five per cent, benefited from:
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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:
Gross margin for the three months ended Dec. 31, 2024 was impacted by:
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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:
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:
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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 | $0.24 annualized |
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The Company’s outlook for 2025 may be impacted by a number of factors as detailed further below.
Market | 2025 Assumptions | 2024 Assumptions | 2024 Actual | |
Alberta spot ($/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 |
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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.
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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 |
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Written by Emilie Grant on . Posted in Canada. Leave a Comment
Nutrien Ltd. has announced its Q424 results, with net earnings of US$118 million (US$0.23 diluted net earnings per share). Q424 adjusted EBITDA1 was US$1.1 billion and adjusted net earnings per share1 was US$0.31.
“Nutrien delivered higher upstream fertilizer sales volumes, accelerated operational efficiency and cost savings initiatives and increased downstream retail earnings in 2024, demonstrating significant progress towards our 2026 performance targets. We took a disciplined and intentional approach to our capital allocation decisions, further optimising capital expenditures and returning US$1.2 billion to shareholders through dividends and share repurchases,” commented Ken Seitz, Nutrien’s President and CEO.
“The outlook for our business in 2025 is supported by expectations for strong crop input demand and firming potash fundamentals. Nutrien has a world-class asset base, and we remain focused on strategic priorities that strengthen our core business and deliver structural improvements to our earnings and free cash flow,” added Mr. Seitz.
Generated net earnings of US$700 million (US$1.36 diluted net earnings per share) and adjusted EBITDA of US$5.4 billion (US$3.47 adjusted net earnings per share) for the full year of 2024.
Retail adjusted EBITDA increased to US$1.7 billion in 2024 supported by higher product margins and lower expenses, as we continue to simplify our business and accelerate downstream network optimisation initiatives.
Potash adjusted EBITDA decreased to US$1.8 billion in 2024 as lower net selling prices more than offset increased sales volumes. The company mined 35% of its potash ore t using automation in 2024, providing efficiency, flexibility and safety benefits, while supporting its highest annual production levels on record and a reduction in controllable cash cost of product manufactured per t.
Nitrogen adjusted EBITDA of US$1.9 billion in 2024 was relatively flat as lower net selling prices offset higher sales volumes and lower natural gas costs. Total ammonia production increased in 2024, driven by less maintenance downtime and improved natural gas utilisation and reliability at our operations in Trinidad.
Divested non-core assets and equity investments totalling approximately US$60 million in 2024, providing incremental cash flow to allocate to high conviction priorities that are core to our long-term strategy.
Repurchased 3.9 million shares for a total of US$190 million in the second half of 2024 and an additional 1.9 million shares in 2025 for US$96 million as of February 18, 2025. Nutrien’s Board of Directors approved the purchase of up to 5% of Nutrien’s outstanding common shares over a twelve-month period through the renewal of our normal course issuer bid (NCIB), which is subject to acceptance by the Toronto Stock Exchange.
Nutrien’s Board of Directors approved an increase in the quarterly dividend to US$0.545 per share. Nutrien continues to target a stable and growing dividend, having now increased the dividend per share by 36% since the beginning of 2018.
1.This is a non-GAAP financial measure. See the “Non-GAAP Financial Measures” section.
2. Our discussion of highlights set out on this page is a comparison of the results for the twelve months ended December 31, 2024 to the results for the twelve months ended December 31, 2023, unless otherwise noted.
Read the article online at: https://www.worldfertilizer.com/project-news/20022025/nutrien-reports-q424-results/
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The content in this section is supplied by GlobeNewswire for the purposes of distributing press releases on behalf of its clients. Postmedia has not reviewed the content.
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GlobeNewswire
Published Feb 20, 2025 • Last updated 2 hours ago • 7 minute read
THIS ANNOUNCEMENT AND THE INFORMATION CONTAINED HEREIN IS RESTRICTED AND IS NOT FOR RELEASE, PUBLICATION OR DISTRIBUTION, IN WHOLE OR IN PART, DIRECTLY OR INDIRECTLY, IN, INTO OR FROM THE UNITED STATES, AUSTRALIA, JAPAN OR THE REPUBLIC OF SOUTH AFRICA OR TO BE TRANSMITTED, DISTRIBUTED TO, OR SENT BY, ANY NATIONAL OR RESIDENT OR CITIZEN OF ANY SUCH COUNTRIES OR ANY OTHER JURISDICTION IN WHICH SUCH RELEASE, PUBLICATION OR DISTRIBUTION MAY CONTRAVENE LOCAL SECURITIES LAWS OR REGULATIONS.
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CASCAIS, Portugal, Feb. 20, 2025 (GLOBE NEWSWIRE) — Pulsar Helium Inc. (AIM: PLSR, TSXV: PLSR, OTCQB: PSRHF) (“Pulsar” or the “Company”), a leading helium project development company, is pleased to announce that down-hole testing equipment is scheduled to mobilise to site on Monday, February 24th. The tools consist of an optical televiewer and LithoScanner, both of which will be run on both the Jetstream #1 and #2 appraisal wells.
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Expanded Reservoir Potential
Elevated helium values were observed in both Jetstream #1 and #2 over a gross vertical thickness of 3,350 and 3,178 feet (1,021 and 969 meters), respectively. This consistency between wells suggests that the interpreted geophysical data accurately indicates that the helium-bearing zone extends beyond 2,200 feet (671 meters), which was the total depth of Jetstream #1 before deepening. The increased gross helium-bearing interval has the potential to enhance the project’s resource potential, highlighting the significance of the Topaz Project.
Strategic Significance
The Jetstream #1 appraisal well reached a TD of 2,200 feet (671 meters) on February 27, 2024. This identified top-tier helium concentrations of up to 14.5%, significantly exceeding the widely accepted economic threshold of 0.3%. Moreover, CO2 concentrations exceeded 70%, which is expected to further enhance the project’s economics. The recent deepening of Jetstream #1 and the completion of Jetstream #2 are crucial steps in advancing Pulsar’s strategy to meet the growing global demand for helium as the Company progresses toward its production objective.
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This news release does not constitute an offer to sell or a solicitation of an offer to buy any of the securities in the United States. The securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the “U.S. Securities Act”) or any state securities laws and may not be offered or sold within the United States or to U.S. Persons unless registered under the U.S. Securities Act and applicable state securities laws or an exemption from such registration is available.
On behalf Pulsar Helium Inc.
“Thomas Abraham-James”
President, CEO and Director
Further Information:
Pulsar Helium Inc.
connect@pulsarhelium.com
+ 1 (218) 203-5301 (USA/Canada)
+44 (0) 2033 55 9889 (United Kingdom)
https://pulsarhelium.com
https://x.com/pulsarhelium
https://ca.linkedin.com/company/pulsar-helium-inc.
Strand Hanson Limited
(Nominated & Financial Adviser, and Joint Broker)
Ritchie Balmer / Rob Patrick / Richard Johnson
+44 (0) 207 409 3494
OAK Securities*
(Joint Broker)
Jerry Keen (Corporate Broking) / Henry Clarke (Institutional Sales) / Dillon Anadkat (Corporate Advisory)
info@OAK-securities.com
+44 203 973 3678
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BlytheRay Ltd
(Financial PR)
Megan Ray / Said Izagaren
+44 207 138 3204
pulsarhelium@blytheray.com
*OAK Securities is the trading name of Merlin Partners LLP, a firm incorporated in the United Kingdom and regulated by the UK Financial Conduct Authority.
About Pulsar Helium Inc.
Pulsar Helium Inc. is a publicly traded company listed on the AIM market of the London Stock Exchange and the TSX Venture Exchange with the ticker PLSR, as well as on the OTCQB with the ticker PSRHF. Pulsar’s portfolio consists of its flagship Topaz helium project in Minnesota, USA, and the Tunu helium project in Greenland. Pulsar is the first mover in both locations with primary helium occurrences not associated with the production of hydrocarbons identified at each.
Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
Forward-Looking Statements
This news release and the interview contains forward-looking information within the meaning of Canadian securities legislation (collectively, “forward-looking statements”) that relate to the Company’s current expectations and views of future events. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as “will likely result”, “are expected to”, “expects”, “will continue”, “is anticipated”, “anticipates”, “believes”, “estimated”, “intends”, “plans”, “forecast”, “projection”, “strategy”, “objective” and “outlook”) are not historical facts and may be forward-looking statements. Forward-looking statements herein include, but are not limited to, statements relating to the potential impact of deepening Jetstream #1 and the potential impact of such deepening on the next iteration of the resource estimate; the expected timing to commence drilling; and the potential for future wells. Forward-looking statements may involve estimates and are based upon assumptions made by management of the Company, including, but not limited to, the Company’s capital cost estimates, management’s expectations regarding the availability of capital to fund the Company’s future capital and operating requirements and the ability to obtain all requisite regulatory approvals.
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No reserves have been assigned in connection with the Company’s property interests to date, given their early stage of development. The future value of the Company is therefore dependent on the success or otherwise of its activities, which are principally directed toward the future exploration, appraisal and development of its assets, and potential acquisition of property interests in the future. Un-risked Contingent and Prospective Helium Volumes have been defined at the Topaz Project. However, estimating helium volumes is subject to significant uncertainties associated with technical data and the interpretation of that data, future commodity prices, and development and operating costs. There can be no guarantee that the Company will successfully convert its helium volume to reserves and produce that estimated volume. Estimates may alter significantly or become more uncertain when new information becomes available due to for example, additional drilling or production tests over the life of field. As estimates change, development and production plans may also vary. Downward revision of helium volume estimates may adversely affect the Company’s operational or financial performance.
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Helium volume estimates are expressions of judgement based on knowledge, experience and industry practice. These estimates are imprecise and depend to some extent on interpretations, which may ultimately prove to be inaccurate and require adjustment or, even if valid when originally calculated, may alter significantly when new information or techniques become available. As further information becomes available through additional drilling and analysis the estimates are likely to change. Any adjustments to volume could affect the Company’s exploration and development plans which may, in turn, affect the Company’s performance. The process of estimating helium resources is complex and requires significant decisions and assumptions to be made in evaluating the reliability of available geological, geophysical, engineering, and economic date for each property. Different engineers may make different estimates of resources, cash flows, or other variables based on the same available data.
Forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Company’s control, which could cause actual results and events to differ materially from those that are disclosed in or implied by such forward- looking statements. Such risks and uncertainties include, but are not limited to, that Pulsar may be unsuccessful in deepening the Jetstream #1, in drilling commercially productive wells; the uncertainty of resource estimation; operational risks in conducting exploration, including that drill costs may be higher than estimates and the potential for
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delays in the commencement of drilling; commodity prices; health, safety and environmental factors; and other factors set forth above as well as under “Cautionary Note Regarding Forward Looking Statements and Market and Industry Data” and “Risk Factors” in the AIM Admission Document published on October 14th, 2024, found on the Company’s web site at https://pulsarhelium.com/investors/aim-rule-26/default.aspx.
Forward-looking statements contained in this news release are as of the date of this news release, and the Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. New factors emerge from time to time, and it is not possible for the Company to predict all of them or assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. No assurance can be given that the forward-looking statements herein will prove to be correct and, accordingly, investors should not place undue reliance on forward-looking statements. Any forward-looking statements contained in this news release are expressly qualified in their entirety by this cautionary statement.
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Koryx Copper Incorporated, a Canadian copper development company advancing its 100% owned Haib Copper Project in Namibia, has been recognised as one of the top 50 performers on the Toronto Stock Exchange (TSX) Venture Exchange for 2025.
According to a statement issued by the Vancouver-based company, which is also building a portfolio of copper exploration licences in Zambia, the accolade is based on an outstanding 400% share price appreciation and 737% market capitalisation growth in 2024.
The company was ranked in the top 10 mining companies in the category.
“The 50 companies on the list delivered an average share price appreciation of 207% to investors in 2024, up from 121% in 2023 and 73% in 2022,” reads the statement. The group holds a combined market capitalisation of US$21.7 billion (about N$403 billion) — an increase of over US$16 billion (about N$297 billion) over the course of the year.
“We are very proud to be recognised as a top 50 TSX Venture Exchange (TSXV) company for 2025, especially given the significant corporate restructure and re-positioning of the company in 2024,” says Koryx president and chief executive Heye Daun.
He says the award is a testament to the Koryx team’s experience and capabilities.
“Looking forward to 2025, we are fully-funded and already executing on a transformative work programme to fast track our flagship Haib Copper Project.
“We remain focused on continuing to de-risk and grow our assets while continuing to create value for shareholders,” he says.
The 2025 TSX Venture 50 showcases the top 50 of over 1 600 TSXV issuers. Eligible listed issuers are ranked based on three equally weighted criteria of a one-year share price appreciation, market capitalisation increase, and consolidated trading value as of 31 December, 2024.
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(All financial figures in United States dollars unless otherwise stated)
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Norbert Schlenker, the president of Libra Investment Management, reportedly came up with the idea for Norbert’s Gambit nearly 40 years ago. The concept became more prevalent over the past 20 years.
Schlenker used his idea to convert currency between Canadian and U.S. dollars using inter-listed stocks. For example, some Canadian stocks listed on the Toronto Stock Exchange (TSX) are also listed in U.S. dollars on the New York Stock Exchange (NYSE). This inter-listing can allow an investor to buy in one currency and sell in the other currency, effectively converting dollars for only the cost of trading commissions.
On Feb. 14, 2025, Royal Bank of Canada (RBC) shares closed at $168.67 per share on the TSX. On the NYSE, they closed at $119.04. The price difference represents the foreign exchange rate between the two currencies. The Canadian-dollar shares were trading at about a 1.417 premium to the U.S.-dollar shares because the U.S. dollar closed at 1.418 Canadian dollars on Feb. 14, 2025.
As the currencies move, the shares on the two exchanges should be worth almost the same, after accounting for the foreign exchange rate at the time.
An investor may be able to purchase Royal Bank shares in Canadian dollars on the TSX and then “journal” the dual-listed shares to NYSE-listed Royal Bank shares, selling them in U.S. dollars. “Journaling” refers to transferring equivalent shares from one exchange to another.
One problem with buying inter-listed common shares is that the shares can fluctuate in value.
Norbert’s Gambit can also be implemented using an exchange-traded fund (ETF) like the Global X US Dollar Currency ETF, which trades in Canadian and U.S. dollars on the TSX. The ticker symbol is DLR (Canadian dollar) or DLR.U (U.S. dollar).
The DLR/DLR.U ETF tracks the value of the U.S. dollar in either U.S. dollars or Canadian dollars, so the investor may be less exposed to changes in an underlying stock price that can be volatile.
Written by TSX Stocks on . Posted in Canada. Leave a Comment
*
Toronto Stock Exchange closes down 23 points or 0.09%
*
Market fell almost a percentage point in early trade
*
Energy stocks up 0.87%, mining stocks gain up 0.1%
*
Barrick Gold shares up 2.5% after Mali government deal
(New throughout)
By Promit Mukherjee and Pranav Kashyap
Feb 19 (Reuters) –
Canada’s main stock index closed marginally lower on Wednesday, after a global equity sell-off was largely cushioned by energy shares, recovery in mining stocks and minutes of the U.S. Federal Reserve’s January meeting.
The S&P/TSX Composite index lost 0.09%, or close to 22.68 points, to end at 25,626.16.
U.S. President Donald Trump on Tuesday announced
tariffs on automotive imports
“in the neighborhood of 25%” and said that more details will be revealed on April 2. Duties will be slapped on pharmaceutical and semiconductor imports, he added.
Asian and European markets closed sharply lower on Wednesday, with the pan-European STOXX 600 index
falling 0.9%
, its biggest single-day drop this year.
U.S. shares
closed higher in a rebound after the Federal Reserve released the
minutes of its meeting
, with the S&P 500 posting its second straight all-time closing high.
Fed policymakers expressed concern about U.S. economic growth due to Trump’s policies, the minutes showed.
“The big picture here is that the markets continue to exhibit a surprising degree of resilience to all the headline risk,” said Elvis Picardo, portfolio manager at Luft Financial, iA Private Wealth.
Investors in this bull market do not want to miss any buying opportunity, he said.
Some analysts said the Fed’s concerns on growth hint at a potential interest rate cut, boosting investor optimism.
In Canada, the financial sector, with a weight of nearly one-third of the composite index, lost 0.27%. Royal Bank of Canada, the biggest company by market capitalization, fell 0.02%.
The sell-off was largely softened by energy stocks , which rose 0.87% as oil prices held near a one-week high of $76 per barrel on worries about supply disruptions in Russia and the U.S.
Mining stocks also helped to contain the slide in the main index, led by higher gold prices and an over 2.5% jump in Barrick Gold shares.
Reuters reported that the
miner has signed
a new agreement with the Mali government to end an almost two-year-old dispute over its mining assets. (Reporting by Promit Mukherjee in Ottawa and Pranav Kashyap in Bangalore; Editing by Sahal Muhammed and Richard Chang)
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