Blue Sky Expands the Principal Target at the Corcovo Uranium Project, Argentina USA - English USA
Frankfurt Stock Exchange: MAL2
OTCQB Venture Market (OTC): BKUCF
VANCOUVER, BC, Aug. 6, 2025 /CNW/ - Blue Sky Uranium Corp. (TSXV: BSK) (FSE: MAL2) (OTC: BKUCF), ("Blue Sky" or the"Company") is pleased to announce the expansion of the principal target at the Corcovo Uranium Project, located in the Western Malargüe Mining District, Mendoza Province, Argentina. The Company has now reviewed and integrated data from an additional 104 historical oil & gas (" O&G") wells (part of a larger dataset) into its geological model. These new data build upon the previous interpretation that was based on 89 O&G drillholes (see News Release data June 4, 2025) and provide stronger support for a substantial uranium mineralized system with significant continuity, based on uranium equivalent (" eU") and gamma-ray anomalies in the Centenario Core horizon.
A new uranium equivalent grade-by-thickness (eU × thickness) map has been generated for the Centenario Core Horizon (see Figure 1). The map, which incorporates the 104 integrated wells, confirms the presence of the uranium mineralized zones consistent with roll front style mineralization. The northwestern extent of the uranium mineralized corridor remains open, suggesting potential for further expansion. Additionally, the map highlights a single principal corridor of uranium equivalent anomalies, along which multiple anomalies have been identified. One of these bodies is particularly noteworthy for its scale, measuring approximately 2.2 kilometres along a northwest–southeast trend and 500 metres in width (Figure 2). This data integration supports improved mapping of the uranium-bearing horizon and reinforces the potential for expansion of the uranium mineralized system.
Nikolaos Cacos, President & CEO of the Company stated, "The quality of the newly integrated data significantly improves our confidence in the continuity and scale of the uranium system at Corcovo. The Centenario Core horizon now shows potential for an even more extensive uranium mineralized system, and we are prioritizing the acquisition and interpretation of 3D seismic data to help delineate the geometry of the potential mineralized bodies. These are key steps in our process to advance the project in support of a potential resource estimation in the future."
The Corcovo Project covers 20,000 hectares at the northeastern margin of the O&G producing Neuquén Basin. The geological potential of the region for uranium in situ recovery (" ISR") deposits was initially defined by CNEA, the state-owned nuclear company, as reported in the International Atomic Energy Agency and Nuclear Energy Agency document titled: " Uranium 2024: Resources, Production and Demand". Blue Sky optioned the Corcovo project in 2024 as part of a strategic initiative to broaden the Company's medium to long-term prospects for discovery of additional uranium mineral resources. The project benefits from flat topography, road access, and year-round accessibility, supporting cost-effective exploration and potential future ISR development.
Deposit Model
The Inkai uranium project in Kazakhstan is one of the world-leading ISR mining projects and a model for exploration at Corcovo. This roll-front uranium mineralization is hosted in permeable Cretaceous fluvial sandstones, with mineralized zones located at depths of 350 to 530 metres. Individual orebody thicknesses range from 2 to 10 metres, with localized zones reaching up to 15 metres. A characteristic of Inkai is the continuity and scale of the mineralization: roll-front horizons are laterally extensive, commonly traceable for over 25 kilometers in length and up to hundreds of metres in width. These dimensions, combined with favorable porosity and permeability, support efficient and sustained ISR operations. The deposit averages approximately 0.03% U₃O₈ and contains proven and probable reserves totaling 368 million tonnes with 251 million pounds of U₃O₈ (www.cameco.com 06/02/2025).
Planned Activities and Data Acquisition
Blue Sky Uranium recently secured a historic subsurface dataset comprising data from several hundred O&G wells and 34 2D seismic lines. To date, the Company has processed and integrated 104 of these drillholes into its geological model. This initial integration has provided valuable insights into the Centenario Core horizon and has helped delineate the principal uranium-equivalent mineralized corridor.
The technical team is currently working to incorporate the remaining 344 historical drill holes, which will further enhance the geological and mineralization model. In parallel, the Company is actively pursuing access to 3D seismic data. This expanded effort will improve resolution of subsurface structures and stratigraphy especially throughout the northwestern section of the corridor, which remains open.
In addition, Blue Sky plans to collect water samples from active oil wells operating under secondary recovery once the Company obtains the necessary permits, and sample drill cuttings from historical wells. These samples are intended for geochemical validation of legacy gamma-ray log data and will support critical geochemical studies to confirm mineralization and guide further exploration. This additional information will be integrated with the 3D seismic interpretation to refine the morphology of horizons with anomalous uranium equivalent and their relation to subsurface geologic structures. It will be important to determine the porosity/permeability characteristics of the host and adjacent geologic units to evaluate their amenability to potential ISR application. The process is underway to secure access to this information.
Drill Hole Data Summary
Table 1. Summary of Drill Holes with Most Significant Intervals of Anomalous eU
(Cut-off 30ppm eU. Intervals approximate true thickness as all holes drilled vertically through flat-lying strata.)
Methodology and QA/QC
Blue Sky obtained oil and gas drilling data for 104 wells drilled at the area for work conducted on the properties between 2006 and 2018 through a formal request to the Mendoza provincial authority (Hydrocarbons Directorate – Under‑secretariat for Energy and Mining, Ministry of Economy and Energy, Province of Mendoza). The work was carried out by Pluspetrol S.A. and its corporate predecessors (see drill hole information in Table 2 for details). This data originates from historical oil and gas exploration programs and has not been independently verified by a Qualified Person.
Uranium equivalent values reported herein were obtained directly from calibrated spectral gamma-ray logs generated using NaI(Tl) crystal-based tools, with measurements taken approximately every 0.15 to 0.25 metres. Readers are cautioned that uranium-series disequilibrium may affect radiometric results, potentially leading to either underestimation or overestimation of actual uranium content.
The historical subsurface data integrated into Blue Sky Uranium's Corcovo Project were originally generated by O&G operators (see listing in Table 2). Based on their technical reports, the following QA/QC protocols were applied during data acquisition and processing:
Calibration and Control of Logging Equipment: Gamma-ray and other downhole sensors were routinely calibrated using industry-standard reference materials before and during acquisition campaigns to ensure accuracy and minimize equipment drift.
Mud Logging Quality Control: Continuous geological control was implemented through direct sampling and mud logging, allowing real-time reconstruction of lithology and stratigraphy. Data collection included detection and quantification of gases, assessment of lithological changes, and monitoring of drilling parameters, contributing to high-resolution control over depth and stratigraphic correlation.
Error Monitoring and Minimization: Protocols included redundant cross-checks of depth control through dual measurement systems (drill string length and wireline logging). Routine detection of measurement errors and recalibrations were documented, ensuring that error margins were kept minimal.
Database Validation by Blue Sky: Blue Sky Uranium has further validated the integrity of the historical data through a review of original reports and reprocessing of gamma-ray logs. Additionally, planned collection of drill cuttings and water samples from existing wells will support the calibration of equivalent uranium values against geochemical assays in the near term.
Qualified Persons
The technical contents of this news release have been reviewed and approved by Mr. Ariel Testi, CPG, who works for the Company and is a Qualified Person as defined in National Instrument 43-101.
About Blue Sky Uranium Corp.
Blue Sky Uranium Corp. is a leader in uranium discovery in Argentina. The Company's objective is to deliver exceptional returns to shareholders by rapidly advancing a portfolio of uranium deposits into low-cost producers, while respecting the environment, the communities, and the cultures in all the areas in which we work. Blue Sky's flagship Amarillo Grande Project was an in-house discovery of a new district that has the potential to be both a leading domestic supplier of uranium to the growing Argentine market and a new international market supplier. The Company's recently optioned Corcovo project has demonstrated potential to host an in-situ recovery uranium deposit. The Company is a member of the Grosso Group, a resource management group that has pioneered exploration in Argentina since 1993.
ON BEHALF OF THE BOARD
"Nikolaos Cacos"
______________________________________
Nikolaos Cacos, President, CEO and Director
Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.
This news release may contain forward-looking statements and forward-looking information (collectively, the "forward-looking statements") within the meaning of applicable securities laws. Forward-looking statements address future events and conditions and therefore involve inherent risks and uncertainties. Any statements that are contained in this press release that are not statements of historical fact may be deemed to be forward-looking statements. Forward-looking statements are often identified by terms such as "may", "should", "anticipate", "will", "estimates", "believes", "intends" "expects" and similar expressions which are intended to identify forward-looking statements. More particularly and without limitation, this press release contains forward-looking statements that, other than statements of historical fact, address activities, events or developments the Company believes, expects or anticipates will or may occur in the future, including, without limitation, statements about the Company's planned exploration campaigns, advancement of the Corcovo project, the future value of the previous work done to the Corcovo project and potential of the Corcovo project. Forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.
Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements and, even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: uncertainty relating to mineral resources; risks related to heavy metal and transition metal price fluctuations, particularly uranium and vanadium; risks relating to the dependence of the Company on key management personnel and outside parties; the potential impact of global pandemics; risks and uncertainties related to governmental regulation and the ability to obtain, amend, or maintain licenses, permits, or surface rights; risks associated with technical difficulties in connection with mining activities; and the possibility that future exploration, development or mining results will not be consistent with the Company's expectations, including in respect of the Company's planned exploration program described in this news release. Actual results may differ materially from those currently anticipated in such statements. Readers are encouraged to refer to the Company's public disclosure documents for a more detailed discussion of factors that may impact expected future results. The forward-looking statements contained in this press release are made as of the date of this press release, and the Company does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as expressly required by securities law.
SOURCE Blue Sky Uranium Corp.
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The Company received the requisite consents to implement the proposed amendments to the indenture governing the notes with a 50.38% approval, and validly delivered tenders in excess of the maximum tender amount set forth in the offer, Bondholders who participated in the tender offer had their notes repurchased pursuant to a proration factor of 55.63%. The transaction reduced the amount of the Company's outstanding notes by $80 million three years before maturity, for a total cash consideration of $57.6 million and recognizing a gain after fees and expenses associated with transaction of $11.7 million. The tender offer and consent solicitation provided the Company with increased financial flexibility, while also reducing its outstanding debt obligations. The amendments to the indenture aim to modernize Frontera's indenture in line with that of its peers and also provides targeted operational flexibility to deliver long-term business and reserve growth, including as a result of inorganic transactions. The carrying value for the 2028 Senior Unsecured Notes, as of June 30, 2025, is $310.3 million. Dividend: Pursuant to Frontera's dividend policy, Frontera's Board of Directors has declared a dividend of C$0.0625 per common share to be paid on or around October 16, 2025, to shareholders of record at the close of business on October 2, 2025. This dividend payment to shareholders is designated as an "eligible dividend" for purposes of the Income Tax Act (Canada). This dividend is eligible for the Company's Dividend Reinvestment Plan which provides Canadian resident shareholders of Frontera the option to automatically reinvest the cash dividends on their common shares into additional common shares, without paying brokerage commissions or services charges. Frontera's Three Core Businesses Frontera's three core businesses include: (1) its Colombia and Ecuador Upstream Onshore business, (2) its standalone and growing Colombian Infrastructure business, and (3) its potentially transformational Guyana Exploration business offshore Guyana. 2025 Guidance Update Frontera is adjusting its 2025 production guidance to reflect its Colombian operations only, now targeting 39,500 to 41,000 boed, following the divestment of its non-core assets in Ecuador. The Company is also revising its capital expenditures guidance downwards by approximately $20 million, reducing its development facilities capex to $45 - 65 million and exploration capex to $25 - 35 million. These changes reflect on the Company's disciplined approach to capital spending and ability to identify ongoing operational efficiencies. Additionally, the Company is providing Operating EBITDA Guidance at a $70/bbl Brent Price targeting between $320 - $360 million and revising our Adjusted Infrastructure EBITDA Guidance targeting between $110 - 125 million. (1) The Company's 2025 original and updated average production guidance range does not include in-kind royalties, operational consumption, quality volumetric compensation or potential production from successful exploration activities planned in 2025. (2) Per-bbl/boe metric on a share before royalties' basis. (3) Calculated using net production after royalties. (4) Supplementary financial measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A for further details. (5) Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A for further details (6) 2025 Original Guidance Operating EBITDA calculated at Brent between $75/bbl and COP/USD exchange rate of 4,250:1. (7) 2025 Updated Guidance Operating EBITDA calculated at Brent between $70/bbl and COP/USD exchange rate of 4,150:1.. (8) Other includes HSEQ activities and new field production technologies. Colombia & Ecuador Upstream Onshore Colombia During the second quarter of 2025, Frontera produced 39,778 boe/d from its Colombian operations (consisting of 27,535 bbl/d of heavy crude oil, 9,850 bbl/d of light and medium crude oil, 3,118 mcf/d of conventional natural gas and 1,846 boe/d of natural gas liquids). In the second quarter of 2025, the Company drilled 26 development wells mainly at the Quifa and CPE-6 blocks and completed well interventions at 22 others. Currently, the Company has 1 drilling rig and 2 well intervention rigs active at its Quifa and CPE-6 blocks in Colombia. Quifa Block: Quifa SW and Cajua At Quifa, second quarter 2025 production averaged 17,576 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company invested in facility expansion and the installation of new flow lines in the Cajua field, in the Quifa block to support new well production and the SAARA connection. In the second quarter 2025, the Company handled an average of approximately 1.78 million barrels of water per day in Quifa including SAARA. CPE-6 At CPE-6, second quarter 2025 production averaged approximately 7,771 bbl/d of heavy crude oil, decreasing from 8,056 bbl/d during the first quarter of 2025. During the second quarter 2025, the Company invested in the expansion of crude oil storage capacity and the implementation of new field production technologies. The Company handled an average of approximately 327 thousand barrels of water per day in CPE-6 in the second quarter of 2025. The Company's current water handling capacity in CPE-6 is approximately 370 thousand barrels of water per day. Other Colombia Developments At Guatiquia, production during the second quarter 2025 averaged 5,385 bbl/d of light and medium crude compared with 5,119 bbl/d in the first quarter 2025. During the quarter the Company performed a sidetrack in its Coralillo 3 well. In the Cubiro block production averaged 1,057 bbl/d of light and medium crude oil in the second quarter of 2025 compared with 1,213 bbl/d in the first quarter 2025. At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,960 boe/d of light and medium crude oil in the second quarter of 2025 compared to 1,840 boe/d of light and medium crude oil in the first quarter 2025. At the Sabanero block, production averaged 2,189 boe/d of heavy oil crude production in the second quarter of 2025 compared to 2,346 boe/d in the first quarter 2025. Colombia Exploration Assets At VIM-1, following engagement efforts with authorities and communities, the joint venture operating the VIM-1 block (Frontera 50% W.I., non-operator) has shifted its focus from Hidra-1 to the Guapo-1 exploratory well. By the second quarter 2025, all necessary designs and permits were secured for roadwork and site preparation for Guapo-1, with drilling and completion expected to occur in the second half of 2025. At Llanos 119, the Company is awaiting the decision of the Agencia Nacional de Hidrocarburos (ANH) on transferring exploration commitments to VIM-46 for a 3D seismic survey. Meanwhile, pre-seismic and pre-drilling social and environmental studies are underway at Llanos-99 and VIM-46. Ecuador In Ecuador, second quarter 2025 production averaged approximately 1,277 bbl/d of light and medium crude oil compared to 1,467 bbl/d in the prior quarter. At the Espejo block (Frontera holds a 50% W.I. and is a non-operator), long-term tests continued at the Espejo Sur-B3 well with production of 330 bbl/d gross and a water cut of 78%. Subsequent to the quarter, the Company agreed to divest its 50% interest in the Perico and Espejo blocks in Ecuador. The total cash consideration to Frontera for the blocks is $7.8 million, subject to working capital and other customary adjustments as of the effective date of January 1, 2025. The agreement includes an additional contingent consideration of $750,000, payable to Frontera upon the Perico block achieving cumulative gross production of two million barrels as from January 1, 2025. Closing of the transaction is subject to satisfaction of customary closing conditions, including the receipt of regulatory approvals for closing and operations takeover from the Ministry of Energy of Ecuador, and is expected to occur by the second quarter of 2026. 2. Infrastructure Colombia Frontera's Infrastructure Colombia Segment includes the Company's 35% equity interest in the ODL pipeline through Frontera's wholly owned subsidiary, FPI and the Company's 99.97% interest in Puerto Bahia. Beginning in 2024, the Infrastructure Colombia Segment also includes the Company's reverse osmosis water treatment facility (SAARA) and its palm oil plantation (ProAgrollanos). Frontera processed 119,409 barrels of water per day at is SAARA reverse osmosis water-treatment facility during the quarter and remains focused on reaching its goal of processing 250,000 barrels of water per day. On the Puerto Bahia side, the Reficar connection's construction was completed by the end of the quarter and, the Company's efforts shift to the first transported volumes, which are expected during the third quarter of 2025. The Company is progressing with its growth plans, including the LPG joint venture with Empresas Gasco. Infrastructure Colombia Segment Results Adjusted Infrastructure EBITDA in the second quarter of 2025 was $27.1 million, compared with $28.6 million during the first quarter 2025. The decrease was mainly due to higher operating costs in SAARA, offset by positive results in the ODL segment driven by the pipeline tariff increase and lower costs during the quarter. (1) Non-IFRS financial measure Segment capital expenditures for the three months ended June 30, 2025, totaled $4.8 million primarily driven by Puerto Bahia investments of $3.9 million, including: (i) $3.4 million in investment towards the Reficar connection, (ii) tank maintenance, and (iii) general cargo terminal facilities with additional investment in the SAARA project. (1) Non-IFRS financial measures (equivalent to a "non-GAAP financial measures", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures'' section on page 24 of the MD&A. The following table shows the volumes pumped per injection point in ODL: The following table shows throughput for the liquids port facility at Puerto Bahia: The following table shows the barrels of water per day treated and irrigated in SAARA and field performance indicators for Proagrollanos: (1) Tons per hectare per year for the three months ended June 30, are calculated using the total production for the last twelve months ended June 30. 3. Guyana Exploration On March 26, 2025, the Company and its subsidiaries Frontera Petroleum International Holding B.V. and Frontera Energy Guyana Holding Ltd. (the " Investors") sent a Notice of Intent to the Government of Guyana (the " GoG"). In this Notice of Intent, the Investors alleged breaches of the United Kingdom – Guyana Bilateral Investment Treaty and the Guyana Investment Act by the GoG. The communication initiated a 90-day period for consultations and negotiations between the parties to resolve the dispute amicably. After the 90-day period, no mutually, acceptable solution has been produced. As informed in previous quarters, Frontera Energy Guyana Corp. (" Frontera Guyana") and CGX Resources Inc. (" CGX Resources" and together with Frontera Guyana, the " Joint Venture") and its stakeholders are prepared to assert their legal rights. On July 23, 2025, the GoG, through its legal counsel, responded to the Investors, rejecting their claims regarding the Corentyne block license. The GoG reaffirmed its view that the Joint Venture's interest expired on June 28, 2024, but noted that it may consider a final meeting with the Investors, on a without prejudice basis, in October 2025, and the Joint Venture would be informed as to whether such a meeting will occur in September 2025 The Joint Venture remains firmly of the view that its interests in, and the license for, the Corentyne block remain in place and in good standing and that the Petroleum Agreement has not been terminated. Although the 90-day consultation and negotiation period derived from the Notice of Intent has now expired, the Joint Venture and its stakeholders continue to invite the GoG to amicably resolve the issues affecting the Joint Venture's investments in the Corentyne block. Should the parties not reach a mutually agreeable solution, the Joint Venture and its stakeholders are prepared to assert their legal rights. The Company evaluated the Corentyne E&E asset's recoverability given the GoG's conduct and communications, and its unwillingness to recognize the Joint Venture's rights during the consultation periods, which have since expired. Although all contractual requirements of the Company have been met and an external legal assessment determined that the Company's interests in the licenses and agreements for the Corentyne block remain valid, the GoG's positions mentioned above have restricted the Company's ability to develop activities under those licenses and agreements. This situation has led to uncertainty regarding the asset's future development and constituted an impairment indicator. Consequently, the Company recognized an impairment of $432.2 million in its income statement, and the Corentyne E&E asset's carrying value as of June 30, 2025 is $Nil (December 31, 2024 $431.9 million). The Joint Venture jointly hold 100% working interest in the Corentyne block, located offshore Guyana. Frontera Guyana and CGX Resources have agreed that their respective participating interests are 72.52% and 27.48%, which includes a 4.52% interest which CGX Resources agreed to assign to Frontera Guyana in 2023. The assignment of this 4.52% participating interest remains subject to the approval of the Government of Guyana, but is believed to be enforceable between Frontera Guyana and CGX Resources. Hedging Update As part of its risk management strategy, Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company's strategy aims to protect 40-60% of its estimated net after royalties' production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, thereby allowing the Company to take a more dynamic approach to the management of its hedging portfolio. The following table summarizes Frontera's hedging position as of August 13, 2025. The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of August 13, 2025 the Company had the following foreign currency derivatives contracts: Second Quarter 2025 Financial Results Conference Call Details A conference call for investors and analysts will be held on Thursday, August 14th, 2025, at 11:00 a.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Rene Burgos, Chief Financial Officer, and other members of the senior management team. Analysts and investors are invited to participate using the following dial-in numbers: A replay of the conference call will be available until 11:59 p.m. Eastern Time on August 21st, 2025. About Frontera: Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 22 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally and ethically responsible manner. Twitter: Facebook: LinkedIn: Cautionary Note Concerning Forward-Looking Statements This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, the Company's goal of enhancing shareholder value by returning capital to shareholders, the Company's intent to consider future shareholder initiatives including a potential future separation and other strategic transactions involving the Infrastructure business, the expected date for pre-drilling and drilling activity to commence in the Lower Magdalena Valley and Llanos Basins in Colombia, the operational timing of the connection project between Puerto Bahia and Reficar, holding the conference call for investors and the timing thereof, the Company's exploration and development plans and objectives, production levels, profitability, costs, future income generation capacity, cash levels (including the timing and ability to release restricted cash), regulatory approval, and the Company's hedging program and its ability to mitigate the impact of changes in oil prices) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: volatility in market prices for oil and natural gas; the newly imposed U.S. trade tariffs affecting over fifty countries and escalating tensions with China; the impact of the Russia-Ukraine conflict and the conflict in the Middle East; actions of the Organization of Petroleum Exporting Countries; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; the Company's ability to complete strategic initiatives or transactions to enhance the value of its common shares and the timing thereof; the Company's ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; political developments in the countries where the Company operates; the uncertainties involved in interpreting drilling results and other geological data; geological, technical, drilling and processing problems; timing on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility, the ability of the Joint Venture to reach an agreement with the GoG in respect of the Joint Venture's interest in the PA and PPL for the Corentyne block, and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 10, 2025 filed on SEDAR+ at Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein. This news release contains future oriented financial information and financial outlook information (collectively, "FOFI") (including, without limitation, statements regarding expected average production), and are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the Company's activities and results, and such information may not be appropriate for other purposes. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments, however, actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it is made, and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or otherwise, unless required by applicable laws. Non-IFRS Financial Measures This press release contains various "non-IFRS financial measures" (equivalent to "non-GAAP financial measures", as such term is defined in NI 52-112), "non-IFRS ratios" (equivalent to "non-GAAP ratios", as such term is defined in NI 52-112), "supplementary financial measures" (as such term is defined in NI 52-112) and "capital management measures" (as such term is defined in NI 52-112), which are described in further detail below. Such measures do not have standardized IFRS definitions. The Company's determination of these non-IFRS financial measures may differ from other reporting issuers and they are therefore unlikely to be comparable to similar measures presented by other companies. Furthermore, these financial measures should not be considered in isolation or as a substitute for measures of performance or cash flows as prepared in accordance with IFRS. These financial measures do not replace or supersede any standardized measure under IFRS. Other companies in our industry may calculate these measures differently than we do, limiting their usefulness as comparative measures. The Company discloses these financial measures, together with measures prepared in accordance with IFRS, because management believes they provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. These financial measures highlight trends in the Company's core business that may not otherwise be apparent when relying solely on IFRS financial measures. Further, management also uses non-IFRS measures to exclude the impact of certain expenses and income that management does not believe reflect the Company's underlying operating performance. The Company's management also uses non-IFRS measures in order to facilitate operating performance comparisons from period to period and to prepare annual operating budgets and as a measure of the Company's ability to finance its ongoing operations and obligations. Set forth below is a description of the non-IFRS financial measures, non-IFRS ratios, supplementary financial measures and capital management measures used in the MD&A. Operating EBITDA EBITDA is a commonly used non-IFRS financial measure that adjusts net income as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and DD&A. Operating EBITDA is a non-IFRS financial measure that represents the operating results of the Company's primary business, excluding the following items: restructuring, severance and other costs, post-termination obligation, payments of minimum work commitments and, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, and share-based compensation) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company. A reconciliation of Operating EBITDA to net loss is as follows: Three months ended June 30 Six months ended June 30 ($M) 2025 2024 2025 2024 Net loss (455,212) (2,846) (427,688) (11,349) Finance Income (2,073) (1,816) (3,556) (3,408) Finance expenses 18,310 17,429 33,715 34,699 Income tax (recovery) expense (12,957) 32,659 (22,608) 59,244 Depletion, depreciation and amortization 60,600 63,188 127,994 129,000 Expense (recovery) of asset retirement obligation 151 45 526 (997) Expenses of impairment 476,960 392 478,094 1,419 Trunkline incident costs — — 2,000 — Post-termination obligation (406) (364) (109) 186 Shared-based compensation 1,624 754 2,486 1,040 Restructuring, severance and other cost 9,526 1,052 10,527 2,855 Share of income from associates (14,124) (13,407) (29,233) (27,301) Foreign exchange loss 2,553 7,518 314 8,615 Other (income) loss (1,303) 2,774 (1,191) 3,133 Unrealized (gain) loss on risk management contracts (3,556) 3,646 (8,342) 11,585 Non-controlling interests (168) (288) (295) (443) Gain on repurchased of notes (11,735) (415) (11,925) (709) Debt extinguishment cost 5,964 — 5,964 — Colombian Temporary taxes 1,919 — 2,858 — Operating EBITDA 76,073 110,321 159,531 207,569 Capital Expenditures Capital expenditures is a non-IFRS financial measure that reflects the cash and non-cash items used by the Company to invest in capital assets. This financial measure considers oil and gas properties, plant and equipment, infrastructure, exploration and evaluation assets expenditures which are items reconciled to the Company's Statements of Cash Flows for the period. Infrastructure Colombia Calculations Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative, is a non-IFRS financial measure, and each is used to evaluate the performance of the Infrastructure Colombia Segment operations. Adjusted Infrastructure Revenue includes revenues of the Infrastructure Colombia Segment including ODL's revenue direct participation interest. Adjusted Infrastructure Operating Costs includes costs of the Infrastructure Colombia Segment including ODL's cost direct participation interest. Adjusted Infrastructure General and Administrative includes general and administrative costs of the Infrastructure Colombia Segment including ODL's general and administrative direct participation interest. A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative is provided below. (1) Revenues and expenses related to ODL are accounted for using the equity method, as described in Note 12 of the Interim Condensed Consolidated Financial Statements. Adjusted Infrastructure EBITDA The Adjusted Infrastructure EBITDA is a non-IFRS financial measure used to assist in measuring the operating results of the Infrastructure Colombia Segment business. (1) Non-IFRS financial measure Net Sales Net sales is a non-IFRS financial measure that adjusts revenue to include realized gains and losses from oil risk management contracts while removing the cost of any volumes purchased from third parties. This is a useful indicator for management, as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these oil risk management activities. The deduction of cost of purchases is helpful to understand the Company's sales performance based on the net realized proceeds from its own production, the cost of which is partially recovered when the blended product is sold. Net sales also exclude sales from port services, as it is not considered part of the oil and gas segment. Refer to the reconciliation in the "Sales" section on page 10 of the MD&A. Operating Netback and Oil and Gas Sales, Net of Purchases Operating netback is a non-IFRS financial measure and operating netback per boe is a non-IFRS ratio. Operating netback per boe is used to assess the net margin of the Company's production after subtracting all costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel and is an indicator of how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of any trading activities and results from its Infrastructure Colombia Segment from the per barrel metrics and adds the effects attributable to transportation and operating costs of any realized gain or loss on foreign exchange risk management contracts. Refer to the reconciliation in the "Operating Netback" section on page 9. The following is a description of each component of the Company's operating netback and how it is calculated. Oil and gas sales, net of purchases, is a non-IFRS financial measure that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining costs. Oil and gas sales, net of purchases per boe, is a non-IFRS ratio that is calculated using oil and gas sales, net of purchases, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below: (1) Excludes sales from infrastructure services, as they are not part of the oil and gas segment. Refer to the "Infrastructure Colombia" section on page 19 for further details. Non-IFRS Ratios Realized oil price, net of purchases, and realized gas price per boe Realized oil price, net of purchases, and realized gas price per boe are both non-IFRS ratios. Realized oil price, net of purchases, per boe is calculated using oil sales net of purchases, divided by total sales volumes, net of purchases. Realized gas price is calculated using sales from gas production divided by the conventional natural gas sales volumes. (1) Non-IFRS financial measure. Net sales realized price Net sales realized price is a non-IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts and less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below: Three months ended June 30 Six months ended June 30 ($M) 2025 2024 2025 2024 Oil and gas sales, net of purchases ($M) (1)(2) 170,943 217,130 368,918 417,904 Gain (loss) on oil price risk management contracts, net ($M) (3) 431 (3,796) (3,710) (7,285) (-) Royalties ($M) (2,304) (5,774) (5,364) (10,280) Net Sales ($M) 169,070 207,560 359,844 400,339 Sales volumes, net of purchases (boe) 2,872,688 2,868,593 5,936,619 5,615,246 Oil and gas sales, net of purchases ($/boe) 59.51 75.69 62.14 74.42 Premiums received (paid) on oil price risk management contracts (4) 0.15 (1.32) (0.62) (1.30) Royalties ($/boe) (0.80) (2.01) (0.90) (1.83) Net sales realized price ($/boe) 58.86 72.36 60.62 71.29 (1) Non-IFRS financial measure. (2) 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahia inter-segment costs related to diluent and oil purchases as well as transportation costs. (3) Includes the net amount of put premiums paid for expired positions and the positive cash settlement received from oil price contracts during the period. Refer to the "Gain (Loss) on Risk Management Contracts" section on page 15 for further details. (4) Supplementary financial measure. Purchase crude net margin Purchase crude net margin is a non-IFRS financial measure that is calculated using the purchased crude oil and products sales, less the cost of those volumes purchased from third parties including its transportation and refining costs. Purchase crude net margin per boe is a non-IFRS ratio that is calculated using the Purchase crude net margin, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below: (1) Cost of third-party volumes purchased for use and resale in the Company's oil operations, including its transportation and refining costs. (2) 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahía inter-segment costs related to diluent and oil purchases as well as transportation costs. Production costs (excluding energy cost), net of realized FX hedge impact, and production cost (excluding energy cost), net of realized FX hedge impact per boe Production costs (excluding energy cost), net of realized FX hedge impact is a non-IFRS financial measure that mainly includes lifting costs, activities developed in the blocks, processes to put the crude oil and gas in sales condition and the realized gain or loss on foreign exchange risk management contracts attributable to production costs. Production cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using production cost (excluding energy cost), net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below: (1) See "Gain (Loss) on Risk Management Contracts" on page 15. (2) Non-IFRS financial measure. Energy costs, net of realized FX hedge impact, and production cost, net of realized FX hedge impact per boe Energy costs, net of realized FX hedge impact is a non-IFRS financial measure that describes the electricity consumption and the costs of localized energy generation and the realized gain or loss on foreign exchange risk management contracts attributable to energy costs. Energy cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using energy cost, net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below: (1) See "Gain (Loss) on Risk Management Contracts" on page 15. (2) Non-IFRS financial measure. Transportation costs, net of realized FX hedge impact, and transportation costs, net of realized FX hedge impact per boe Transportation costs, net of realized FX hedge impact is a non-IFRS financial measure, that includes all commercial and logistics costs associated with the sale of produced crude oil and gas such as trucking and pipeline, and the realized gain or loss on foreign exchange risk management contracts attributable to transportation costs. Transportation cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using transportation cost, net of realized FX hedge impact divided by net production after royalties. A reconciliation of this calculation is provided below: Three months ended June 30 Six months ended June 30 2025 2024 2025 2024 Transportation costs ($M) 38,701 34,917 78,250 70,112 (-) Realized gain on FX hedge attributable to transportation costs ($M) (1) — (634) — (1,043) Puerto Bahía inter-segment costs (2) 692 470 1,328 901 Transportation costs, net of realized FX hedge impact ($M) (2)(3) 39,393 34,753 79,578 69,970 Net Production (boe) 3,389,204 3,139,955 6,652,293 6,210,568 Transportation costs, net of realized FX hedge impact ($/boe) 11.62 11.07 11.96 11.27 (1) See "Gain (Loss) on Risk Management Contracts" on page 15. (2) 2024 prior period figures are different compared with those previously reported as a result as a result of the inclusion of Puerto Bahia inter-segment costs related to cost of diluent and oil purchased, and transportation cost. (3) Non-IFRS financial measure. Supplementary Financial Measures Realized (loss) gain on oil risk management contracts per boe Realized (loss) gain on oil risk management contracts includes the gain or loss during the period, as a result of the Company´s exposure in derivative contracts of crude oil. Realized (loss) gain on oil risk management contracts per boe is a supplementary financial measure that is calculated using Realized (loss) gain on risk management contracts divided by total sales volumes, net of purchases. Royalties per boe Royalties includes royalties and amounts paid to previous owners of certain blocks in Colombia and cash payments for PAP. Royalties per boe is a supplementary financial measure that is calculated using the royalties divided by total sales volumes, net of purchases. NCIB weighted-average price per share Weighted-average price per share under the 2023 NCIB is a supplementary financial measure that corresponds to the weighted-average price of common shares purchased under the 2023 NCIB during the period. It is calculated using the total amount of common shares repurchased in U.S. dollars divided by the number of common shares repurchased. Capital Management Measures Restricted cash short- and long-term Restricted cash (short- and long-term) is a capital management measure, that sums the short-term portion and long-term portion of the cash that the Company has in term deposits that have been escrowed to cover future commitments and future abandonment obligations, or insurance collateral for certain contingencies and other matters that are not available for immediate disbursement. Total cash Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available, is comprised by the cash and cash equivalents and the restricted cash short and long-term. Total debt and lease liabilities Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company and is comprised of the debt of the 2028 Unsecured Notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets. Definitions: SOURCE Frontera Energy Corporation
Toronto Star
2 hours ago
- Toronto Star
Acceleware Ltd. Announces Closing of Shares for Debt Transactions
CALGARY, Alberta, Aug. 13, 2025 (GLOBE NEWSWIRE) — Acceleware® Ltd. ('Acceleware' or the 'Company') (TSX-V: AXE), a leading innovator of cutting-edge radio frequency ('RF') power-to-heat technologies targeting process heat for critical minerals, amine regeneration (for carbon capture and other applications), and enhanced oil production, is pleased to announce that further to its news release dated June 30, 2025, the Company has closed certain shares for debt transactions to settle $186,337 in certain trades payable, management fees and interest payable on convertible debentures of the Company by issuing up to 1,863,375 Units at a deemed price of $0.10 per Unit (the 'Shares for Debt Transactions'). Each Unit issued under the Shares for Debt Transactions consists of one common share of the Company (a 'Common Share') and one common share purchase warrant of the Company (a 'Warrant'). Each Warrant entitles the holder to acquire one Common Share, at an exercise price of $0.20 for 24 months from the date of issuance. If the Common Shares trade at a closing price at or greater than $0.30 per Common Share for a period of thirty (30) consecutive trading days, Acceleware may accelerate the expiry date of the Warrants by giving 30 days notice to the holders thereof. The Common Shares, Warrants and Common Shares underlying the Warrants will be subject to a four (4) month plus one day hold period in accordance with securities legislation.
