Latest news with #Management'sDiscussionandAnalysis
Toronto Star
2 days ago
- Business
- Toronto Star
Maxim Power Corp. Announces 2025 Second Quarter Financial and Operating Results
CALGARY, Alberta, Aug. 07, 2025 (GLOBE NEWSWIRE) — Maxim Power Corp. ('MAXIM' or the 'Corporation') (TSX: MXG) announced today the release of financial and operating results for the second quarter ended June 30, 2025. The unaudited condensed consolidated interim financial statements, accompanying notes and Management's Discussion and Analysis ('MD&A') will be available on SEDAR+ and on MAXIM's website on August 7, 2025. All figures reported herein are Canadian dollars unless otherwise stated.
Cision Canada
2 days ago
- Business
- Cision Canada
Keyera Announces 2025 Second Quarter Results and Raises Dividend
CALGARY, AB, Aug. 7, 2025 /CNW/ - Keyera Corp. (TSX: KEY) ("Keyera") announced its second quarter financial results today, the highlights of which are included in this news release. To view Management's Discussion and Analysis (the "MD&A") and financial statements, visit either Keyera's website or its filings on SEDAR+ at View PDF "Keyera delivered strong results this quarter, reflecting the strength of our integrated value chain and continued growing customer demand," said Dean Setoguchi, President and CEO. "We advanced our strategy with the sanctioning of KFS Frac III and KAPS Zone 4 along with strong commercial momentum across our asset base. This growth in stable, fee-for-service cash flow allows us to sustainably increase the dividend. We also announced the transformational acquisition of Plains' Canadian NGL assets, which will further expand our scale, enhance service offerings, and create lasting value for customers and shareholders." Second Quarter Highlights Financial Results Adjusted earnings before interest, taxes, depreciation, and amortization, 1 ("adjusted EBITDA") were $252 million (Q2 2024 – $326 million), including $12 million in transaction costs related to the Plains acquisition. These results also reflect increased year-over-year contributions from the Gathering and Processing and Liquids Infrastructure segments which were more than offset by lower Marketing segment contributions. Distributable cash flow 1 ("DCF") was $159 million or $0.69 per share for the quarter (Q2 2024 – $202 million or $0.88 per share). Net earnings were $127 million (Q2 2024 – $142 million). Sustainable Dividend Growth Keyera has increased its dividend by 4%, supported by the continued growth in its fee-for-service business and a payout ratio 1 that remains within the company's target range. This increase reflects the company's confidence in the quality, stability and continued growth of its cash flows. Continued Growth in High Quality, Fee-For-Service Realized Margin 1 Fee-for-service realized margin 1 was $255 million, up 8.4% from $235 million in the same period last year, driven by strong performance in both Gathering and Processing and Liquids Infrastructure segments. The Gathering and Processing ("G&P") segment generated realized margin 1 of $111 million (Q2 2024 – $102 million), reflecting continued strong performance from the North region gas plants. The North region accounted for over 70% of the segment's realized margin 1. The Liquids Infrastructure segment achieved quarterly realized margin 1 of $143 million (Q2 2024 – $133 million), driven by the continued growth in long-term contracted volumes on KAPS, high fractionation utilization, and near-record quarterly shipments on Keyera's condensate system. Marketing Segment Results – The Marketing segment recorded quarterly realized margin 1 of $60 million (Q2 2024 – $136 million). The year-over-year decline is mainly due to lower overall commodity prices. Strong Financial Position – The company ended the quarter with net debt to adjusted EBITDA 2 of 2.0 times, below the targeted range of 2.5 to 3.0 times, excluding acquisition related costs. Keyera's strong balance sheet provided the flexibility to pursue the recently announced transformative acquisition of Plains' Canadian NGL business, a transaction that will strengthen the company's value chain, offer a broader and more efficient service for customers and be highly accretive to shareholders. 2025 Guidance Update Marketing segment 2025 realized margin 1 is expected to remain within the previous guidance range of $310 million to $350 million, which is inclusive of the estimated $50 million impact of the AEF outage. Growth capital expenditures are now expected to range between $275 million and $300 million (previously between $300 million and $330 million). This adjustment reflects a shift in timing of certain expenditures which are now scheduled for 2026. Maintenance capital expenditures are unchanged and expected to range between $70 million and $90 million. Cash taxes are unchanged and expected to range between $100 million and $110 million. Strong Contracting Momentum Supporting Capital-Efficient Growth On a stand-alone basis, Keyera remains on track to achieve its 7–8% fee-based adjusted EBITDA 1 compound annual growth rate target from 2024 to 2027. During the quarter, the company secured several additional long-term integrated contracts across its value chain, supporting the sanctioning of both the KFS Frac III expansion and KAPS Zone 4. These projects will support continued growth well beyond 2027. Over the past several months, Keyera added more than 100,000 barrels per day of new long-term contracted volumes on KAPS Zones 1 through 4, up from 75,000 barrels per day disclosed in early June. At the same time, the KFS complex, including the Frac II de-bottleneck and Frac III expansion, is now substantially all contracted, further strengthening utilization and returns across the system. KFS Frac II Debottleneck – Sanctioned in February, this 8,000 barrel per day project is expected to cost $85 million. Fabrication of major equipment is underway and on-site construction is progressing well. The additional capacity is expected to be in service in mid-2026. KFS Frac III Expansion – Sanctioned in May, this 47,000 barrel per day expansion is expected to cost $500 million, including investments to enhance egress capability at the site. Detailed design is underway and early works construction activities have kicked off at site, with the facility targeted to enter service in mid-2028. KAPS Zone 4 – Sanctioned in June for an estimated cost of $220 million (net to Keyera), this 85-kilometre extension from Pipestone to Gordondale, including new pump stations, will enhance connectivity to growing Montney production in Northeast BC and Northwest Alberta. Engineering is underway and long lead items have been ordered. The project is expected to be in service in mid-2027. Keyera continues to advance additional growth opportunities, including potential expansions of North Region G&P capacity, enhanced rail and logistics capabilities to support growing fractionation volumes, and further liquids extraction projects. Acquisition of Plains' Canadian NGL Business On June 17, Keyera announced it had entered into a definitive agreement to acquire substantially all of Plains' Canadian NGL business, plus select U.S. assets, for $5.15 billion in cash. This transaction is expected to close in the first quarter of 2026, subject to regulatory approvals. In connection with the acquisition, the company successfully closed a $2.07 billion bought-deal offering of subscription receipts during the quarter. Upon closing of the acquisition, each subscription receipt will be exchanged for one common share of the company, partially funding the purchase price. The acquisition represents a natural extension of Keyera's integrated NGL value chain and will provide customers with more reliable, cost-effective, and flexible services across the country. It brings key Canadian energy infrastructure under Canadian ownership, supports long-term energy security, and enhances Canada's economic resilience. With assets across Alberta, Saskatchewan, Manitoba, and Ontario, and a strong presence in both western and eastern hubs, the combined platform will deliver more customer value through enhanced market access and operational efficiency. The transaction is expected to be mid-teens accretive to DCF per share in its first full year, inclusive of approximately $100 million in highly achievable, near-term run-rate synergies, and will increase Keyera's fee-based adjusted EBITDA 1 by approximately 50% over the same period. The transaction was structured to preserve Keyera's strong financial position and maintain investment grade credit ratings, with pro forma leverage expected to remain within the company's long-term target range. CEO's Message to Shareholders Executing on Our Strategy with Strong Momentum. We continue to see strong customer demand across our integrated system, reflecting the value of our service offering and our position as a competitive alternative in the basin. In 2025, we've sanctioned three capital-efficient growth projects—KFS Frac II debottleneck, KFS Frac III, and KAPS Zone 4—secured over 100,000 barrels per day of new long-term contracted volumes on KAPS, and expanded our LPG export capacity through our agreement with AltaGas. Our Fort Saskatchewan fractionation complex, including both expansions, is now substantially all contracted. With this momentum, we remain on track to deliver our 7–8% fee-based adjusted EBITDA growth target from 2024 to 2027, and are seeing continued demand growth beyond that timeframe. Together with our strong balance sheet, these achievements laid the foundation for the transformational acquisition of Plains' Canadian NGL business, a step that meaningfully expands our scale, enhances our service offerings, and creates lasting value for customers and shareholders. Constructive Outlook for Western Canadian Volume Growth. The outlook for volume growth in the Western Canadian Sedimentary Basin remains strong. Low-cost, long-life resources in the Montney and Duvernay, combined with improved market access, are supporting increased gas production leading to higher NGL volumes. Key demand drivers include increasing LNG exports, petrochemical development, oil sands growth, and emerging sectors such as AI and data centres. As volumes grow, producers are seeking efficient, flexible infrastructure with strong market connectivity to maximize netbacks for their NGLs. With our integrated platform and commercial strength, Keyera is well positioned to support the next phase of basin development. Transformational Acquisition Strengthens Platform and National Infrastructure. The acquisition of Plains' Canadian NGL business marks a defining moment for Keyera and a step change in our platform. It significantly expands the scale, reach, and resilience of our operations, creating a fully integrated NGL corridor that stretches from the liquids-rich producing regions of Western Canada to key demand hubs in Asia, the Prairies, Ontario, and the U.S. These highly complementary assets enhance our ability to offer customers more reliable, cost-effective, and flexible service by improving market access, optimizing product flows, and helping maximize netbacks. This is a compelling Canadian success story which also brings critical infrastructure under Canadian ownership and strengthens national energy security, while ensuring that reinvestment, value creation, and decision-making remain in Canada. For shareholders, it maintains the stability of our cash flow and the strength of our balance sheet, enhances our ability to grow the dividend sustainably, and provides a scalable platform for long-term value creation on a per share basis. Disciplined Capital Allocation to Maximize Long-Term Value. As we execute on this next phase of growth, our commitment to financial discipline remains unchanged. We continue to prioritize investments that are capital-efficient, supported by long-term contracts, and aligned with our strategy to grow fee-for-service cash flow. The Plains acquisition was structured to preserve our investment-grade credit ratings and leverage targets, reinforcing our commitment to maintaining a strong balance sheet. We will continue to assess future opportunities with the same disciplined approach, ensuring each decision supports our long-term strategy and delivers sustainable value for shareholders. On behalf of Keyera's board of directors and management team, I want to thank our employees, customers, shareholders, Indigenous rights holders, and other stakeholders for their continued support. Together, we will continue to drive Keyera's success and contribute positively to Canada's energy landscape. Dean Setoguchi President and CEO Keyera Corp. Second Quarter 2025 Results Conference Call and Webcast Keyera will be conducting a conference call and webcast for investors, analysts, brokers and media representatives to discuss the financial results for the second quarter of 2025 at 8:00 a.m. Mountain Time (10:00 a.m. Eastern Time) on Thursday, August 7, 2025. Callers may participate by dialing 1-888-510-2154 or 1-437-900-0527. A recording of the conference call will be available for replay until 10:00 PM Mountain Time on Thursday, August 21, 2025 (12:00 AM Eastern Time on Friday, August 22, 2025), by dialing 1-888-660-6345 or 1-289-819-1450 and entering passcode 75904. To join the conference call without operator assistance, you may register and enter your phone number here to receive an instant automated call back. This link will be active on Thursday, August 7, 2025, at 7:00 AM Mountain Time (9:00 AM Eastern Time). A live webcast of the conference call can be accessed here or through Keyera's website at Shortly after the call, an audio archive will be posted on the website for 90 days. Additional Information For more information about Keyera Corp., please visit our website at or contact: Dan Cuthbertson, General Manager, Investor Relations Katie Shea, Senior Advisor, Investor Relations Tyler Monzingo, Senior Specialist, Investor Relations Email: [email protected] Telephone: 1-403-205-7670 Toll free: 1-888-699-4853 For media inquiries, please contact: Amanda Condie, Manager, Corporate Communications Email: [email protected] Telephone: 1-855-797-0036 About Keyera Corp. Keyera Corp. (TSX: KEY) operates an integrated Canadian-based energy infrastructure business with extensive interconnected assets and depth of expertise in delivering energy solutions. Its predominantly fee-for-service based business consists of natural gas gathering and processing; natural gas liquids processing, transportation, storage, and marketing; iso-octane production and sales; and an industry-leading condensate system in the Edmonton/Fort Saskatchewan area of Alberta. Keyera strives to provide high quality, value-added services to its customers across North America and is committed to conducting its business ethically, safely and in an environmentally and financially responsible manner. Non-GAAP and Other Financial Measures This news release refers to certain financial and other measures that are not determined in accordance with Generally Accepted Accounting Principles ("GAAP"). Measures such as funds from operations, distributable cash flow, distributable cash flow per share, payout ratio, realized margin, fee-for-service realized margin, EBITDA, adjusted EBITDA and compound annual growth rate ("CAGR") for fee-based adjusted EBITDA are not standard measures under GAAP or are supplementary financial measures, and as a result, may not be comparable to similar measures reported by other entities. Management believes that these non-GAAP and other financial measures facilitate the understanding of Keyera's results of operations, leverage, liquidity and financial position. These measures do not have any standardized meaning under GAAP and therefore, should not be considered in isolation, or used in substitution for measures of performance prepared in accordance with GAAP. For additional information on these non-GAAP and other financial measures, including reconciliations to the most directly comparable GAAP measures for Keyera's historical non-GAAP financial measures, refer below and to Management's Discussion and Analysis ("MD&A") for the period ended June 30, 2025, which is available on SEDAR+ at and Keyera's website at Specifically, refer to the sections of the MD&A titled, "Non-GAAP and Other Financial Measures", "Forward-Looking Statements", "Segmented Results of Operations", "Dividends: Funds from Operations, Distributable Cash Flow and Payout Ratio", and "EBITDA and Adjusted EBITDA". Funds from Operations and Distributable Cash Flow ("DCF") Funds from operations is defined as cash flow from operating activities adjusted for changes in non-cash working capital. This measure is used to assess the level of cash flow generated from operating activities excluding the effect of changes in non-cash working capital, as they are primarily the result of seasonal fluctuations in product inventories or other temporary changes. Funds from operations is also a valuable measure that allows investors to compare Keyera with other infrastructure companies within the oil and gas industry. Distributable cash flow is defined as cash flow from operating activities adjusted for changes in non-cash working capital, inventory write-downs, maintenance capital expenditures and lease payments, including the periodic costs related to prepaid leases. Distributable cash flow per share is defined as distributable cash flow divided by weighted average number of shares outstanding – basic. Distributable cash flow is used to assess the level of cash flow generated from ongoing operations and to evaluate the adequacy of internally generated cash flow to fund dividends. The following is a reconciliation of funds from operations and distributable cash flow to the most directly comparable GAAP measure, cash flow from operating activities: Payout Ratio Payout ratio is calculated as dividends declared to shareholders divided by distributable cash flow. This ratio is used to assess the sustainability of the company's dividend payment program. 1 Non-GAAP measure as defined above. Realized Margin Realized margin is defined as operating margin excluding unrealized gains and losses on commodity-related risk management contracts. Management believes that this supplemental measure facilitates the understanding of the financial results for the operating segments in the period without the effect of mark-to-market changes from risk management contracts related to future periods. Fee-for-service realized margin includes realized margin for the Gathering and Processing and Liquids Infrastructure segments. The following is a reconciliation of realized margin to the most directly comparable GAAP measure, operating margin: Operating Margin and Realized Margin Three months ended June 30, 2024 (Thousands of Canadian dollars) Gathering & Processing Liquids Infrastructure Marketing Corporate and Other Total Operating margin (loss) 101,885 131,904 136,010 (50) 369,749 Unrealized loss (gain) on risk management contracts 49 1,173 (27) — 1,195 Realized margin (loss) 101,934 133,077 135,983 (50) 370,944 Operating Margin and Realized Margin Six months ended June 30, 2025 (Thousands of Canadian dollars) Gathering & Processing Liquids Infrastructure Marketing Corporate and Other Total Operating margin (loss) 221,604 296,111 199,623 (139) 717,199 Unrealized gain on risk management contracts (800) (502) (61,194) — (62,496) Realized margin (loss) 220,804 295,609 138,429 (139) 654,703 Operating Margin and Realized Margin Six months ended June 30, 2024 (Thousands of Canadian dollars) Gathering & Processing Liquids Infrastructure Marketing Corporate and Other Total Operating margin 205,652 267,049 180,066 13 652,780 Unrealized loss on risk management contracts 611 2,591 70,377 — 73,579 Realized margin 206,263 269,640 250,443 13 726,359 Fee-for-Service Realized Margin Three months ended June 30, 2025 (Thousands of Canadian dollars) Gathering & Processing Liquids Infrastructure Fee-for-Service Operating margin 109,464 140,599 250,063 Unrealized loss on risk management contracts 2,034 2,563 4,597 Realized margin 111,498 143,162 254,660 Fee-for-Service Realized Margin Three months ended June 30, 2024 (Thousands of Canadian dollars) Gathering & Processing Liquids Infrastructure Fee-for-Service Operating margin 101,885 131,904 233,789 Unrealized loss on risk management contracts 49 1,173 1,222 Realized margin 101,934 133,077 235,011 Fee-for-Service Realized Margin Six months ended June 30, 2025 (Thousands of Canadian dollars) Gathering & Processing Liquids Infrastructure Fee-for-Service Operating margin 221,604 296,111 517,715 Unrealized gain on risk management contracts (800) (502) (1,302) Realized margin 220,804 295,609 516,413 Fee-for-Service Realized Margin Six months ended June 30, 2024 (Thousands of Canadian dollars) Gathering & Processing Liquids Infrastructure Fee-for-Service Operating margin 205,652 267,049 472,701 Unrealized loss on risk management contracts 611 2,591 3,202 Realized margin 206,263 269,640 475,903 EBITDA and Adjusted EBITDA EBITDA is a measure showing earnings before finance costs, taxes, depreciation and amortization. Adjusted EBITDA is calculated as EBITDA before costs associated with non-cash items, including unrealized gains and losses on commodity-related contracts, net foreign currency gains and losses on U.S. debt and other, impairment expenses and any other non-cash items such as gains and losses on the disposal of property, plant and equipment. Management believes that these supplemental measures facilitate the understanding of Keyera's results from operations. In particular these measures are used as an indication of earnings generated from operations after consideration of administrative and overhead costs. The following is a reconciliation of EBITDA and adjusted EBITDA to the most directly comparable GAAP measure, net earnings: Compound Annual Growth Rate ("CAGR") for Fee-Based Adjusted EBITDA CAGR is calculated as follows: * Utilizes beginning and end of period fee-based adjusted EBITDA as defined below. CAGR for fee-based adjusted EBITDA is intended to provide information on a forward-looking basis (initiating a 7% to 8% fee-based adjusted EBITDA CAGR target from 2024 to 2027). This calculation utilizes beginning and end of period fee-based adjusted EBITDA, which includes the following components and assumptions: i) forecasted fee-for-service realized margin (realized margin for the Gathering and Processing and Liquids Infrastructure segments), and ii) adjustments for total forecasted general and administrative, and long-term incentive plan expense. The following includes the equivalent historical measure for fee-based adjusted EBITDA, which is the non-GAAP measure component of the related forward-looking CAGR calculation. Forward-Looking Statements In order to provide readers with information regarding Keyera, including its assessment of future plans and operations, its financial outlook and future prospects overall, this news release contains certain statements that constitute "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking information"). Forward-looking information is typically identified by words such as "anticipate", "continue", "estimate", "expect", "may", "will", "can", "project", "should", "would", "plan", "intend", "believe", "plan", "target", "outlook", "scheduled", "positioned", and similar words or expressions, including the negatives or variations thereof. All statements other than statements of historical fact contained in this document are forward-looking information, including, without limitation, statements regarding: industry, market and economic conditions and any anticipated effects on Keyera; Keyera's future financial position and operational performance and future financial contributions and margins from its business segments including, but not limited to, Keyera's Marketing guidance for 2025 annual base realized margin of between $310 million and $350 million; estimates for 2025 regarding Keyera's growth capital expenditures, maintenance capital expenditures and cash taxes; plans around the expansion of Keyera's fractionation capacity, including the cost and timing for the KFS Frac II Debottleneck and KFS Frac III, and the impact of these projects on Keyera's total fractionation capacity; the KAPS Zone 4 project, including cost and timing of the same; plans for deployment of capital and additional growth opportunities, and the impact of current and future growth projects on Keyera's growth targets; approvals and anticipated timing of closing of the acquisition of Plains' Canadian NGL business, the benefits of the acquisition, and Keyera's dividend growth and financial position post-closing of the acquisition; the expectation that demand across Keyera's integrated system will remain strong; strong outlook for volume growth in the Western Canadian Sedimentary Basin; plans around future dividends; and budgets, including future growth capital, operating and other expenditures and projected costs. All forward-looking information reflects Keyera's beliefs and assumptions based on information available at the time the applicable forward-looking information is made and in light of Keyera's current expectations with respect to such things as the outlook for general economic trends, industry trends, commodity prices, oil and gas industry exploration and development activity levels and the geographic region of such activity, Keyera's access to the capital markets and the cost of raising capital, the integrity and reliability of Keyera's assets, the governmental, regulatory and legal environment, general compliance with Keyera's plans, strategies, programs, and goals across its reporting and monitoring systems among employees, stakeholders and service providers. In some instances, this press release may also contain forward-looking information attributed to third parties. Forward-looking information does not guarantee future performance. Management believes that its assumptions and expectations reflected in the forward-looking information contained herein are reasonable based on the information available on the date such information is provided and the process used to prepare the information. However, it cannot assure readers that these expectations will prove to be correct. All forward-looking information is subject to known and unknown risks, uncertainties and other factors that may cause actual results, events, levels of activity and achievements to differ materially from those anticipated in the forward-looking information. Such risks, uncertainties and other factors include, without limitation, the following: Keyera's ability to implement its strategic priorities and business plan and achieve the expected benefits; general industry, market and economic conditions; the ability to successfully complete the acquisition of Plains' Canadian NGL business and obtain the anticipated benefits therefrom, including impacts on growth and accretion in various financial metrics; Keyera's ability to integrate the assets acquired pursuant to the Plains acquisition into Keyera's operations; activities of customers, producers and other facility owners; operational hazards and performance; the effectiveness of Keyera's risk management programs; competition; changes in commodity composition and prices, inventory levels, supply/demand trends and other market conditions and factors; disruptions to global supply chains and labour shortages; trade restrictions, trade barriers, or the imposition of tariffs or other changes to international trade arrangements; processing and marketing margins; climate change risks, including the effects of unusual weather and natural catastrophes; climate change effects and regulatory and market compliance and other costs associated with climate change; variables associated with capital projects, including the potential for increased costs, including inflationary pressures, timing, delays, cooperation of partners, and access to capital on favourable terms; fluctuations in interest, tax and foreign currency exchange rates; hedging strategy risks; counterparty performance and credit risk; changes in operating and capital costs; cost and availability of financing; ability to expand, update and adapt infrastructure on a timely and effective basis; decommissioning, abandonment and reclamation costs; reliance on key personnel and third parties; actions by joint venture partners or other partners which hold interests in certain of Keyera's assets; relationships with external stakeholders, including Indigenous stakeholders; technology, security and cybersecurity risks; potential litigation and disputes; uninsured and underinsured losses; ability to service debt and pay dividends; changes in credit ratings; reputational risks; risks related to a breach of confidentiality; changes in environmental and other laws and regulations; the ability to obtain regulatory, stakeholder and third-party approvals; actions by governmental authorities; global health crisis, such as pandemics and epidemics and the unexpected impacts related thereto; the effectiveness of Keyera's existing and planned ESG and risk management programs; and the ability of Keyera to achieve specific targets that are part of its ESG initiatives, including those relating to emissions intensity reduction targets, as well as other climate-change related initiatives; and other risks, uncertainties and other factors, many of which are beyond the control of Keyera. Further information about the factors affecting forward-looking information and management's assumptions and analysis thereof, is available in Keyera's Management's Discussion and Analysis for the year ended December 31, 2024 and in Keyera's Annual Information Form available on Keyera's profile on SEDAR+ at Readers are cautioned that the foregoing list of important factors is not exhaustive, and they should not unduly rely on the forward-looking information included in this press release. Further, readers are cautioned that the forward-looking information contained herein is made as of the date of this press release. Unless required by law, Keyera does not intend and does not assume any obligation to update any forward-looking information. All forward-looking information contained in this press release is expressly qualified by this cautionary statement.
Cision Canada
3 days ago
- Business
- Cision Canada
OceanaGold Reports Record Quarterly Net Profit
VANCOUVER, BC, Aug. 6, 2025 /CNW/ - OceanaGold Corporation (TSX: OGC) (OTCQX: OCANF) ("OceanaGold" or the "Company") reported its operational and financial results for the three and six months ended June 30, 2025. The condensed interim consolidated financial statements and Management's Discussion and Analysis ("MD&A") are available at Second Quarter Highlights On track to deliver full year production, cost and capital guidance. Safely and responsibly produced 119,500 ounces of gold and 3,700 tonnes of copper. All-In Sustaining Cost ("AISC") † of $2,027 per ounce in the quarter, resulting in $1,915 year to date, at the low-end of guidance range. Record quarterly revenue of $432 million supported by record average realized gold price of $3,293 per ounce, with no hedges or prepays. Record quarterly net profit of $118 million, record EPS of $0.49 and Adjusted EPS † of $0.51. EBITDA Margin † of 50% and Operating Cash Flow Per Share † of $0.99. Generated strong Free Cash Flow † of $120 million and $189 million year to date, resulting in a trailing 12 month Free Cash Flow † yield 1 of 18%. Cash balance increased by 31% to $299 million from the prior quarter, enhancing an already strong balance sheet with no debt. Repurchased $21 million in common shares during the quarter and $41 million year to date under the share buyback program. On track to buyback up to $100 million of shares in 2025. Declared a $0.03 per share quarterly dividend, payable in September 2025. Completed a 3-for-1 share consolidation in preparation for a planned listing on the New York Stock Exchange in the first half of 2026. Released new drill results at Wharekirauponga extending the strike length, continuing to demonstrate its upside potential. † See "Non-IFRS Financial Information" 1 Calculated as trailing 12 month Free Cash Flow† over the average trailing 12 month market capitalization in USD. Gerard Bond, President and CEO of OceanaGold, said: "We are pleased to have had another safe, responsible and strong quarter, with us being on track to deliver full year production, cost and capital guidance. Our production and cost performance, together with being a fully unhedged gold producer with no prepays, drove record quarterly net profit and earnings per share, and delivered strong Free Cash Flow. With no debt and a strengthening cash balance, our exceptional financial position continues to provide us the flexibility to invest in our exciting organic growth opportunities and deliver enhanced shareholder returns via dividends and our recently renewed and expanded share buyback program. Looking ahead, open pit waste stripping is advancing as planned at Haile in Ledbetter Phase 3 and at Macraes in Innes Mills Phase 8, setting us up for a strong fourth quarter and 2026 as we gain access to higher grade ore at our two largest sites. Permitting of our Waihi North Project, which includes the high-grade Wharekirauponga underground, is progressing and we continue to expect approval by year end. Building on the success at Wharekirauponga, where we recently announced an extension of the strike length, exploration is ongoing on promising targets at all sites as we remain focused on unlocking additional value for shareholders." Share Buyback and Dividend In the first half of 2025, the Company repurchased 3.9 million common shares for consideration of $40.6 million. The Board approved in February 2025 the repurchase in 2025 of up to $100 million of common shares under the Company's NCIB ("Normal Course Issuer Bid") program announced in July 2024. The NCIB was recently extended for another 12 months and upsized to be for up to 10% of issued capital. OceanaGold has declared a $0.03 per share dividend payable in September 2025. Shareholders of record at the close of business in each jurisdiction on August 20, 2025 (the "Record Date") will be entitled to receive payment of the dividend on September 19, 2025. The dividend payment applies to holders of record of the Company's common shares traded on the Toronto Stock Exchange. Dividends are payable in United States dollars. Shareholders in other jurisdictions can elect to participate in Computershare's international payments service if they want to receive dividends in an alternative currency. This dividend qualifies as an 'eligible dividend' for Canadian income tax purposes. Results Overview 1 Production is reported on a 100% basis as all operations are controlled by OceanaGold. 2 Attributable to the shareholders of the Company. † See "Non-IFRS Financial Information" Management Update The Company is pleased to announce that Mr. Keenan Jennings has been appointed Chief Exploration Officer effective September 29, 2025. Mr. Jennings will replace Craig Feebrey who is retiring after 10 years with OceanaGold. Mr. Jennings brings over 35 years of global experience in mineral exploration and executive leadership, having held senior roles at BHP, Rio Tinto, and Anglo American. The Company also announces that Peter Sharpe, Chief Operating Officer-Asia Pacific, is leaving OceanaGold to pursue other opportunities outside the gold industry. His last day with the Company will be October 24, 2025. Bhuvanesh Malhotra, current Chief Technical and Project Officer, will become Chief Operating Officer for all operations from September 26, 2025. Mr. Malhotra has been with the Company since early 2024 and has over 25 years of experience in operational and technical roles across multiple commodities and mining methods, driving safety performance, operational excellence and sustainable transformational change. The Company thanks Mr. Feebrey and Mr. Sharpe for their tremendous contributions to OceanaGold and wishes them both well in the future. Conference Call and Webcast: Senior management will host a conference call and webcast to discuss the quarterly results on Thursday, August 7, 2025 at 10:00 am EST (7:00 am PST). To participate in the conference call, please use one of the following methods: Webcast: Toll-free North America: +1 888-510-2154 International: +1 437-900-0527 If you are unable to attend the call, a recording will be made available on the Company's website. About OceanaGold OceanaGold is a growing intermediate gold and copper producer committed to safely and responsibly maximizing the generation of Free Cash Flow from our operations and delivering strong returns for our shareholders. We have a portfolio of four operating mines: the Haile Gold Mine in the United States of America; Didipio Mine in the Philippines; and the Macraes and Waihi operations in New Zealand. Cautionary Statement for Public Release This public release contains certain "forward-looking statements" and "forward-looking information" (collectively, "forward-looking statements") within the meaning of applicable Canadian securities laws which may include, but is not limited to, statements with respect to the future financial and operating performance of the Company, its mining projects, the future price of gold, the estimation of mineral reserves and mineral resources, the realization of mineral reserve and resource estimates, costs of production, estimates of initial capital, sustaining capital, operating and exploration expenditures, costs and timing of the development of new deposits, costs and timing of the development of new mines, costs and timing of future exploration and drilling programs, timing of filing of updated technical information, anticipated production amounts, requirements for additional capital, governmental regulation of mining operations and exploration operations, timing and receipt of approvals, consents and permits under applicable legislation, environmental risks, title disputes or claims, limitations of insurance coverage and the timing and possible outcome of pending litigation and regulatory matters. All statements in this public release that address events or developments that we expect to occur in the future are forward-looking statements. Forward-looking statements are statements that are not historical facts and are generally, although not always, identified by words such as "may", "plans", "expects", "projects", "is expected", "scheduled", "potential", "estimates", "forecasts", "intends", "targets", "aims", "anticipates" or "believes" or variations (including negative variations) of such words and phrases, or may be identified by statements to the effect that certain actions, events or results "may", "could", "would", "should", "might" or "will" be taken, occur or be achieved. Forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievements of the Company to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. Such risks include, among others: future prices of gold; general business; economic and market factors (including changes in global, national or regional financial, credit, currency or securities markets); changes or developments in global, national or regional political and social conditions; changes in laws (including tax laws) and changes in IFRS or regulatory accounting requirements; the actual results of current production, development and/or exploration activities; conclusions of economic evaluations and studies; fluctuations in the value of the United States dollar relative to the Canadian dollar, the Australian dollar, the Philippines Peso or the New Zealand dollar; changes in project parameters as plans continue to be refined; possible variations of ore grade or recovery rates; failure of plant, equipment or processes to operate as anticipated; accidents, labour disputes and other risks of the mining industry; political instability or insurrection or war; labour force availability and turnover; adverse judicial decisions, inability or delays in obtaining financing or governmental approvals; inability or delays in the completion of development or construction activities or in the re-commencement of operations; legal challenges to mining and operating permits including the FTAA as well as those factors identified and described in more detail in the section entitled "Risk Factors" contained in the Company's most recent Annual Information Form and the Company's other filings with Canadian securities regulators, which are available on SEDAR+ at under the Company's name. The list is not exhaustive of the factors that may affect the Company's forward-looking statements. The Company's forward-looking statements are based on the applicable assumptions and factors Management considers reasonable as of the date hereof, based on the information available to Management at such time. These assumptions and factors include, but are not limited to, assumptions and factors related to: the Company's ability to carry on current and future operations, including: development and exploration activities; the timing, extent, duration and economic viability of such operations, including any mineral resources or reserves identified thereby; the accuracy and reliability of estimates, projections, forecasts, studies and assessments; the Company's ability to meet or achieve estimates, projections and forecasts; the availability and cost of inputs; the price and market for outputs, including gold; foreign exchange rates; taxation levels; the timely receipt of necessary approvals or permits; the ability to meet current and future obligations; the ability to obtain timely financing on reasonable terms when required; the current and future social, economic and political conditions; and other assumptions and factors generally associated with the mining industry. The Company's forward-looking statements are based on the opinions and estimates of Management and reflect their current expectations regarding future events and operating performance and speak only as of the date hereof. The Company does not assume any obligation to update forward-looking statements if circumstances or Management's beliefs, expectations or opinions should change other than as required by applicable law. There can be no assurance that forward-looking statements will prove to be accurate, and actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements. Accordingly, no assurance can be given that any events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits or liabilities the Company will derive therefrom. For the reasons set forth above, undue reliance should not be placed on forward-looking statements. Non-IFRS Financial Information Adjusted Net Profit/(Loss) and Adjusted Earnings/(Loss) per share These are used by Management to measure the underlying operating performance of the Company. Management believes these measures provide information that is useful to investors because they are important indicators of the strength of the Company's operations and the performance of its core business. Accordingly, such measures are intended to provide additional information and should not be considered in isolation as a substitute for measures of performance prepared in accordance with IFRS. Adjusted Net Profit/(Loss) is calculated as Net Profit/(Loss) less the impact of impairment expenses, write-downs, foreign exchange (gains)/losses, gain on sale of assets, OGP listing costs and restructuring costs related to transitioning certain corporate activities from Australia to Canada. The following table provides a reconciliation of Adjusted Net Profit/(Loss) and Adjusted Earnings/(Loss) per share: $M, except per share amounts Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Net profit 117.6 101.2 34.0 218.8 28.7 Foreign exchange (gain) loss 2.4 0.8 (0.1) 3.2 6.2 Write-down of assets — 0.2 3.5 0.2 4.7 Gain on sale of Blackwater project — — (17.6) — (17.6) Tax expense on sale of Blackwater project — — 4.9 — 4.9 OGP listing costs — — 5.5 — 5.5 Restructuring costs — — 0.4 — 1.9 Adjusted net profit 120.0 102.2 30.6 222.2 34.3 Adjusted weighted average number of common shares - fully diluted 234.8 238.3 242.8 235.4 241.0 Adjusted earnings per share 0.51 0.43 0.13 0.94 0.14 EBITDA and Adjusted EBITDA Management believes that Adjusted EBITDA is a valuable indicator of its ability to generate liquidity by producing operating cash flows to fund working capital needs, service debt obligations and fund capital expenditures. EBITDA is defined as earnings before interest, tax, depreciation and amortization. Adjusted EBITDA is calculated as EBITDA less the impact of impairment expenses, write-downs, gains/losses on disposal of assets, OGP listing costs, foreign exchange gains/losses and other non-recurring costs. EBITDA Margin is calculated as EBITDA divided by revenue. Prior to the first quarter of 2024, Adjusted EBITDA was calculated using an adjustment for a specific portion of unrealized foreign exchange gains/losses rather than the total foreign exchange gain/loss. The comparative quarters have been recalculated adjusting for all foreign exchange gains/losses. The following table provides a reconciliation of EBITDA, Adjusted EBITDA and EBITDA Margin: $M Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Net profit 117.6 101.2 34.0 218.8 28.7 Depreciation and amortization 54.9 53.7 69.9 108.6 134.7 Net interest expense and finance costs 1.5 1.8 6.5 3.3 11.9 Income tax expense on earnings 43.1 35.3 2.0 78.4 9.0 EBITDA 217.1 192.0 112.4 409.1 184.3 Write-down of assets — 0.2 3.5 0.2 4.7 Gain on sale of Blackwater project — — (17.6) — (17.6) Tax expense on sale of Blackwater project — — 4.9 — 4.9 OGP listing costs — — 5.5 — 5.5 Restructuring expense — — 0.4 — 1.9 Foreign exchange (gain) loss 2.4 0.8 (0.1) 3.2 6.2 Adjusted EBITDA 219.5 193.0 109.0 412.5 189.9 Revenue 432.4 359.9 251.2 792.3 521.5 EBITDA Margin 50 % 53 % 45 % 52 % 35 % Cash Costs and AISC Cash Costs are a common financial performance measure in the gold mining industry; however, it has no standard meaning under IFRS. Management uses this measure to monitor the performance of its mining operations and its ability to generate positive cash flows, both on an individual site basis and an overall company basis. Cash Costs include mine site operating costs plus indirect taxes and selling cost net of by-product sales and are then divided by ounces sold. In calculating Cash Costs, the Company includes copper and silver by-product credits as it considers the cost to produce the gold is reduced as a result of the by-product sales incidental to the gold production process, thereby allowing Management and other stakeholders to assess the net costs of gold production. The measure is not necessarily indicative of cash flow from operations under IFRS or operating costs presented under IFRS. Management believes that the AISC measure provides additional insight into the costs of producing gold by capturing all of the expenditures required for the discovery, development and sustaining of gold production and allows the Company to assess its ability to support capital expenditures to sustain future production from the generation of operating cash flows, both on an individual site basis and an overall company basis, while maintaining current production levels. Management believes that, in addition to conventional measures prepared in accordance with IFRS, certain investors use this information to evaluate the Company's performance and ability to generate cash flow per ounce sold. AISC is calculated as the sum of Cash Costs, capital expenditures and exploration costs that are sustaining in nature and corporate G&A costs. AISC is divided by ounces sold to arrive at AISC per ounce. Prior to the first quarter of 2025, Didipio's AISC calculation excluded local corporate G&A costs which is consistent with the calculation of AISC for the other operations. In order to align the Company's reporting of AISC with local reporting requirements in the Philippines, Management has included local corporate G&A costs in Didipio's AISC calculation beginning in the first quarter of 2025. The following table provides a reconciliation of consolidated Cash Costs and AISC: 1 Excludes the Additional Government Share related to the FTAA at Didipio of $10.2 million, $7.5 million and $17.7 million for the second quarter, first quarter and year to date 2025, respectively, as it is considered in nature of an income tax. The following tables provides a reconciliation of Cash Costs and AISC for each operation: Haile $M, except per oz amounts Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Cash costs of sales 53.9 45.6 50.5 99.5 103.7 By-product credits (1.9) (1.9) (0.8) (3.8) (1.5) Inventory adjustments (2.8) (3.0) 4.0 (5.8) 16.0 Freight, treatment and refining charges 0.2 0.2 0.1 0.4 0.2 Total Cash Costs (net) 49.4 40.9 53.8 90.3 118.4 Sustaining capital and leases 16.2 10.4 7.9 26.6 16.9 Deferred stripping and capitalized mining 28.0 36.4 18.4 64.4 26.6 Onsite exploration and drilling 0.1 0.8 — 0.9 — Total AISC 93.7 88.5 80.1 182.2 161.9 Gold sales (koz) 49.5 57.2 39.8 106.7 81.0 Cash Costs ($/oz) 997 715 1,351 846 1,462 AISC ($/oz) 1,890 1,551 2,008 1,708 1,998 Didipio $M, except per oz amounts Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Cash costs of sales 38.3 32.1 35.5 70.4 71.6 By-product credits (30.9) (31.2) (23.3) (62.1) (51.5) Royalties 2.4 1.6 1.6 4.0 3.0 Indirect taxes 5.7 4.7 4.8 10.4 10.4 Inventory adjustments (0.7) 4.5 (5.4) 3.8 (0.6) Freight, treatment and refining charges 3.2 3.8 3.3 7.0 7.2 Total Cash Costs (net) 18.0 15.5 16.5 33.5 40.1 Sustaining capital and leases 7.0 2.7 5.3 9.7 9.9 Deferred stripping and capitalized mining 1.1 1.9 1.8 3.0 3.7 General and administration 1 0.2 0.1 — 0.3 — Total AISC 26.3 20.2 23.6 46.5 53.7 Gold sales (koz) 20.6 17.8 18.9 38.4 50.7 Cash Costs ($/oz) 873 871 874 872 791 AISC 1 ($/oz) 1,287 1,130 1,250 1,214 1,059 1 Excludes the Additional Government Share of FTAA at Didipio of $10.2 million, $7.5 million and $17.7 million for the second quarter, first quarter, and year to date 2025, respectively, as it is considered in nature of an income tax. Macraes $M, except per oz amounts Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Cash costs of sales 43.3 39.2 24.1 82.5 53.7 Less: by-product credits — (0.1) (0.1) (0.1) (0.1) Royalties 2.6 0.7 2.3 3.3 2.2 Inventory adjustments 5.9 (7.6) 2.2 (1.7) 5.2 Freight, treatment and refining charges 0.3 0.2 0.2 0.5 0.4 Total Cash Costs (net) 52.1 32.4 28.7 84.5 61.4 Sustaining capital and leases 8.4 9.4 6.8 17.8 13.2 Deferred stripping and capitalized mining 14.2 12.3 25.4 26.5 44.1 Onsite exploration and drilling 0.1 0.6 0.4 0.7 1.0 Total AISC 74.8 54.7 61.3 129.5 119.7 Gold sales (koz) 34.8 23.7 26.5 58.5 58.7 Cash Costs ($/oz) 1,496 1,369 1,085 1,444 1,047 AISC ($/oz) 2,146 2,313 2,319 2,213 2,041 Waihi $M, except per oz amounts Q2 2025 Q1 2025 Q2 2024 YTD 2025 YTD 2024 Cash costs of sales 30.7 26.8 18.0 57.5 37.5 By-product credits (2.6) (2.1) (1.1) (4.7) (2.1) Royalties 0.6 0.5 0.3 1.1 0.6 Inventory adjustments (1.4) (2.3) — (3.7) (0.2) Add: Freight, treatment and refining charges — 0.1 0.1 0.1 0.1 Total Cash Costs (net) 27.3 23.0 17.3 50.3 35.9 Sustaining capital and leases 2.2 4.3 1.8 6.5 4.3 Deferred stripping and capitalized mining 5.7 4.7 6.1 10.4 11.6 Onsite exploration and drilling 0.5 0.2 0.7 0.7 1.9 Total AISC 35.7 32.2 25.9 67.9 53.7 Gold sales (koz) 16.4 15.9 10.6 32.3 22.2 Cash Costs ($/oz) 1,670 1,445 1,635 1,559 1,617 AISC ($/oz) 2,190 2,019 2,434 2,106 2,418 Net Cash/(Debt) Net Cash/(Debt) has been calculated as total debt less cash and cash equivalents. Management believes this is a useful indicator to be used in conjunction with other liquidity and leverage ratios to assess the Company's financial health. Prior to 2024, lease liabilities were included in the calculation of Net Cash/(Debt). The change in respect of 2024 is consistent with the generally adopted approach to the calculation of Net Cash/(Debt). The comparative quarters have been recalculated excluding lease liabilities. The following table provides a reconciliation of Net Cash/(Debt): 1 Fleet facility arrangement for mining equipment financing was fully repaid in March 2025. There are no additional amounts available under the fleet facility. Operating Cash Flow per share Operating Cash Flow per share before working capital movements is calculated as the cash flows provided by operating activities adjusted for changes in working capital then divided by the fully diluted adjusted weighted average number of common shares issued and outstanding. The following table provides a reconciliation of total fully diluted Operating Cash Flow per share: Free Cash Flow Free Cash Flow has been calculated as cash flows from operating activities, less cash flow used in investing activities. Management believes Free Cash Flow is a useful indicator of the Company's ability to generate cash flow and operate net of all expenditures, prior to any financing cash flows. Free Cash Flow per share is calculated as the Free Cash Flow divided by the fully diluted adjusted weighted average number of common shares issued and outstanding. The following table provides a reconciliation of Free Cash Flow: SOURCE OceanaGold Corporation
Cision Canada
4 days ago
- Business
- Cision Canada
RUBELLITE ENERGY CORP. REPORTS RECORD PRODUCTION AND ADJUSTED FUNDS FLOW PER SHARE IN SECOND QUARTER 2025 FINANCIAL AND OPERATING RESULTS
CALGARY, AB, Aug. 5, 2025 /CNW/ - (TSX: RBY) - Rubellite Energy Corp. ("Rubellite" or the "Company"), is pleased to report its second quarter 2025 financial and operating results and provide an operations and guidance update. Select financial and operational information is outlined below and should be read in conjunction with Rubellite's unaudited condensed consolidated interim financial statements and related Management's Discussion and Analysis ("MD&A") for the three and six months ended June 30, 2025, which are available on the Company's website at and SEDAR+ at This news release contains certain specified financial measures that are not recognized by GAAP and used by management to evaluate the performance of the Company and its business. Since certain specified financial measures may not have a standardized meaning, securities regulations require that specified financial measures are clearly defined, qualified and, where required, reconciled with their nearest GAAP measure. See "Non GAAP and Other Financial Measures" in this news release and in the MD&A for further information on the definition, calculation and reconciliation of these measures. This news release also contains forward-looking information. See" Forward-Looking Information". Readers are also referred to the other information under the "Advisories" section in this news release for additional information. SECOND QUARTER 2025 HIGHLIGHTS Rubellite delivered record second quarter conventional heavy oil sales production of 8,637 bbl/d that exceeded the high end of guidance and was up 4% relative to the first quarter of 2025 (Q1 2025 - 8,339 bbl/d) and 92% relative to the second quarter of 2024 (Q2 2024 - 4,503 bbl/d). Second quarter total sales production of 12,425 boe/d (72% heavy oil and NGL) also exceeded the high end of guidance. Production growth quarter over quarter was driven by the successful drilling programs at Figure Lake and Frog Lake which brought eleven (10.0 net) new wells on production during the second quarter of 2025. The Figure Lake gas plant that commenced operations on January 23, 2025, added an average of 3.0 MMcf/d of solution gas sales plus associated liquids (17 boe/d) in the second quarter of 2025. Exploration and development capital expenditures (1) totaled $23.8 million for the second quarter of 2025, to drill, complete, equip and tie-in five (5.0 net) multi-lateral horizontal development wells at Figure Lake and six (4.0 net) multi-lateral horizontal development wells at Frog Lake. Included in second quarter development capital spending was $0.7 million for the Figure Lake gas conservation project and the expansion of the gas gathering system. Land and other spending totaled $7.3 million in the second quarter of 2025 and included $0.5 million of spending on seismic purchases (Q2 2024 - nominal). An additional $0.1 million (Q2 2024 - nominal) was spent on decommissioning, abandonment and reclamation activities. Adjusted funds flow (1) in the second quarter of 2025 was $37.3 million ($0.40 per share), up 81% (21% per share) from the second quarter of 2024 (Q2 2024 - $20.7 million or $0.33 per share). Cash costs (1) were $20.7 million or $18.26/boe in the second quarter of 2025, down 19% on a per boe basis from the second quarter of 2024 (Q2 2024 - $9.3 million or $22.58/boe). Net income was $16.1 million ($0.17 per share) in the second quarter of 2025 (Q2 2024 - $12.4 million net income and $0.20 per share). As at June 30, 2025, net debt (1) was $142.4 million, down 8% with the reduction of $11.7 million from $154.0 million as at December 31, 2024 driven by positive free funds flow (1) of $17.1 million in the first half of 2025 which was used to reduce net debt and other balance sheet obligations. Rubellite had available liquidity (1) at June 30, 2025 of $32.4 million, comprised of the $140.0 million borrowing limit of Rubellite's first lien credit facility, less current bank borrowings of $106.2 million and outstanding letters of credit of $1.4 million. OPERATIONS UPDATE Greater Figure Lake (Figure Lake and Edwand) Heavy oil sales production from the Greater Figure Lake area averaged 5,544 bbl/d for the second quarter as compared to 5,326 bbl/d for the first quarter of 2025, an increase of 4%. Solution gas sales contributed 3.0 MMcf/d plus associated natural gas liquids of 17 boe/d which brought total sales production at Figure Lake for the second quarter to 6,064 boe/d (92% oil and liquids). Rubellite is currently expanding the Figure Lake 1-13 Gas Plant to manage additional associated solution gas volumes and increase total throughput capacity to approximately 5.9 to 6.4 MMcf/d. Completion of the expansion is expected in August 2025. During the second quarter of 2025, Rubellite drilled and rig released three (3.0 net) development horizontal wells in the Greater Figure Lake area, all targeting the Wabiskaw Member of the Clearwater Formation, with 33 meter inter-leg spacing and typical 15,000m open hole length per the Figure Lake well design adopted in the latter half of 2024. Results from the 2025 development capital program to date across the Greater Figure Lake field have achieved an average (1) IP30 of 271 bbl/d (7 wells) and IP60 of 267 bbl/d (5 wells), as compared to the McDaniel Tier 1 Type Curve (2) rates for 33 meter inter-leg spacing of 177 bbl/d (IP30) and 169 bbl/d (2) (IP60). In addition to development drilling, two (2.0 net) step-out delineation wells were drilled in the Greater Figure Lake area with 50m inter-leg spacing and ~10,000m open hole length, to test and confirm productivity from two new pools in the Wabiskaw Member. The first well, 00/01-14-062-18W4 ("1-14 Well"), encountered the down dip limit of the first pool, yielding lower oil saturations and higher water cuts than averaged elsewhere in the field. The second well, 00/04-32-060-17W4 ("4-32 Well") has fully recovered load oil, and with early Initial Production (IP15) of 58 bbl/d is within the range of expected outcomes supporting further development of the pool in accordance with the geological model established for the field. Rubellite is actively advancing several opportunities to increase the economic recovery factor for heavy oil at Figure Lake beyond the average anticipated primary recovery factor of approximately 4.0 to 5.5 percent of the original oil in place. A waterflood pilot is currently planned for the fourth quarter of 2025 from a surface location at 9-35-63-18W4 (the "9-35 Pad"). The waterflood pilot pattern will consist of a single horizontal multi-lat well with two sets of four legs each (8 legs in total), with ~150 meters between the four-leg sets. Each 4-leg set will be drilled with 33 meter inter-leg spacing, and the waterflood producer well will have a planned total open hole length for the 8 legs of approximately 10,000 meters. A separate single leg water injection well will be drilled along the center line between the two 4-leg sets, and water injection is expected to commence in early 2026. The Company is also advancing a novel natural gas-based re-injection pilot at Figure Lake for enhanced oil recovery, with an experimental well now configured at the 01-13-063-18W4 pad (the "1-13 Pad"), on the same site as the Figure Lake 1-13 Gas Plant. Results from the waterflood pilot and gas re-injection experiment will inform future development patterns and enhanced oil recovery techniques to be implemented across the Greater Figure Lake area. Rubellite will also test larger diameter (200mm) boreholes at the 9-35 Pad in the third quarter of 2025 to determine if incremental economic returns associated with improved inflow and productivity can be realized relative to the robust economics established for the existing 159mm boreholes drilled to date at Figure Lake. 3D seismic acquired in the first quarter of 2025, imaging the northern end of Figure Lake, has now been interpreted and a Sparky exploration well is planned to be drilled in the first quarter of 2026. Separate detailed mapping work has identified an Upper Clearwater prospect in the southern part of the greater Figure Lake area. If associated exploration wells are successful, there are approximately 15.0 net follow-up Sparky locations and up to 10.0 net follow-up Upper Clearwater locations, all of which would be incremental to the existing Clearwater development inventory and secondary targets inventory at Figure Lake. Consistent production results continue to support the geologic model at Figure Lake and affirm the 243.0 net development drilling inventory locations (3) in the Wabiskaw, including 96.2 net proven and probable undeveloped (2)(3) booked locations. Under a one-rig program, which would provide for the drilling of 18 wells per year at Figure Lake, the Clearwater location count at Figure Lake represents over 13 years of low-risk development drilling inventory. Frog Lake Production at the Frog Lake property grew 5% to average 2,539 bbl/d (100% heavy oil) for the second quarter, as compared to 2,423 bbl/d (100% heavy oil) for the first quarter of 2025. Results from the 2025 capital drilling program to date at Frog Lake (all wells drilled using an oil-based mud ("OBM") drilling system and targeting the north Waseca sand) achieved an average (1) IP30 and IP60 of 140 bbl/d (9 wells) and 128 bbl/d (7 wells) respectively, as compared to the McDaniel Waseca North Type Curve (2) IP30 and IP60 of 107 bbl/d and 104 bbl/d established by McDaniel at year-end 2024 using historical data obtained from wells drilled with water-based mud systems. Rubellite switched its drilling operations at Frog Lake in December 2024 to utilize OBM. The OBM trial at Frog Lake has confirmed the benefits of using OBM fluid consistent with Rubellite's operations at Figure Lake, where the use of OBM has improved hole cleaning and stability, accelerated the time to stabilized reservoir production, and reduced drill pipe wear, water handling and disposal costs as compared to conventional water-based mud systems. The Company is continuing to utilize OBM in its ongoing drilling operations at Frog Lake as it evaluates the effects on long term production performance in different parts of the Waseca reservoir across the Frog Lake field. In addition to continued drilling of the Waseca sand as the primary development zone at Frog Lake, the Company is planning two exploration wells in the third quarter of 2025, targeting the General Petroleum ("GP") sand. The first well will be drilled using a single leg lined horizontal lateral design and the second well will be drilled using an alternative lined "fish bone" well design. Learnings from these two wells will confirm type curve assumptions, and inform mapping parameters, appropriate geological cutoffs, and the future well design for optimum economic development of both the GP and Sparky sands in the Mannville Stack at Frog Lake. The Company commenced a "bottoms up" waterflood at Marten Hills during the second quarter of 2025, with water injection initiated at its first injection well in April. Value is expected to be realized through reduced water handling costs, reduced production declines and enhanced reserve recoveries. East Edson Non-operated drilling planned at East Edson for late in the second quarter was delayed due to wet weather, shifting $3.0 million of capital from Q2 to Q3. Subsequent to the end of the second quarter, the first of four gross (2.0 net) wells was spud in early July, and drilling of the second well is now underway. A turnaround lasting 5.5 days was completed in June 2025 at the Company's primary gas processing facility at East Edson, reducing average sales by 77 boe/d during the second quarter. Other Exploration In addition to exploration activities in the General Petroleum and Sparky zones at Frog Lake and the Sparky prospect at Figure Lake, the Company is continuing to advance multiple additional new venture exploration prospects, pursuing both land capture and play concept de-risking activities while minimizing its risked capital exposure. A total of $3.4 million was invested in the second quarter of 2025 to acquire mineral rights and seismic for exploratory prospects that are expected to be evaluated in 2026. (1) No wells were excluded from the calculation of average results except the criteria for producing days. (2) Type curve assumptions for the 33m spacing well design are based on the Total Proved plus Probable Undeveloped reserves contained in the 2024 McDaniel Reserve Report as disclosed in the Company's 2024 Annual Information Form available under the Company's profile on SEDAR+ at "McDaniel" means McDaniel & Associates Consultants Ltd. independent qualified reserves evaluators. "McDaniel Reserve Report" means the independent engineering evaluation of the heavy crude oil and conventional natural gas and NGL reserves, prepared by McDaniel with an effective date of December 31, 2024 and a preparation date of March 10, 2025. See "Estimated Drilling Locations. (3) Assuming a January 1, 2025, reference date, of the 243.0 net locations described in the greater Figure Lake area, 65.6 net locations are recognized in the McDaniel Report as proved undeveloped and an additional 30.6 net locations are classified as probable undeveloped. The Company recognizes a total of 316.2 net heavy oil development locations, 93.1 of which are net proved and 45.6 are net probable and included in the McDaniel Reserve Report. OUTLOOK AND GUIDANCE For the second half of 2025, Rubellite has budgeted to spend a total of $54.0 to $64.0 million on its exploration and development drilling program, excluding expenditures on land and abandonment and reclamation activities, bringing the total for the year to a range of $100 to $110 million which compares to previous guidance of $95 to $110 million. The increase in the low end of the guidance range reflects the following drilling program changes: At Figure Lake: One (1.0 net) Clearwater waterflood injection well is now planned; Offset somewhat by lower per well costs forecast on the eleven (11.0 net) wells scheduled for H2/25. At Frog Lake: Four Waseca wells are now forecast to be at 100% working interest as Frog Lake Energy Resources Corp. ("FLERC") has elected to be in a gross overriding royalty position on these wells; A second 100% working interest exploratory GP well is now planned; Offset by one (0.5 net) fewer Waseca development well now planned for H2/25. Planned capital activity in the second half of 2025 includes: At Figure Lake: Drilling ten (10.0 net) multi-lateral development wells; Drilling and equipping one (1.0 net) waterflood injection well; Spending to cut a core and conduct several lab experiments to progress enhanced oil recovery technology ideas; and Capital to expand the Figure Lake gas conservation project, including additional plant optimization and pipeline tie-ins. At Frog Lake: Drilling eleven (7.0 net) Waseca multi-lateral development wells; and Drilling one single leg lined lateral well and one lined fish bone well (1.5 net wells) to evaluate the exploratory General Petroleum zone in the Mannville Stack. At East Edson, participation in the drilling of four (2.0 net) Wilrich development wells. Additional spending is planned to continue to advance the evaluation of several heavy oil exploration prospects, to increase gas conservation and usage at Ukalta, and to advance enhanced oil recovery in other areas. With the ongoing volatility in oil prices, the Company is currently planning to maintain its one rig drilling program at each of Figure Lake and Frog Lake for the second half of 2025. The Company will continue to strive for meaningful per well capital cost reductions to maintain attractive rates of return and payout periods, and will manage its capital spending to prioritize free funds flow generation over production growth in this current weaker oil price environment. Heavy oil sales volumes based on the current budget are expected to grow 44% to 48% year-over-year to average between 8,200 - 8,400 bbl/d in 2025, unchanged from previous guidance. Total production sales volumes, including natural gas and NGL volumes at East Edson and solution gas sales at Figure Lake, are forecast to average 12,200 - 12,400 boe/d in 2025, unchanged from previous guidance. Capital spending activity will be funded from adjusted funds flow (1), with excess free funds flow (1) applied to reduce net debt (1) and other balance sheet obligations. Aided by Rubellite's extensive commodity price risk management positions, the Company continues to forecast strong adjusted funds flow and free funds flow through the third quarter of 2025 based on the forward market for commodity prices as at August 5, 2025. Rubellite's Clearwater production continues to realize an attractive offset to WCS benchmark pricing, resulting in an improvement in our heavy oil wellhead differential guidance to a range of $4.00 to $4.50 per barrel vs $5.00 to $5.50 per barrel previously. Additionally, initiatives to improve field operating costs have improved our operating cost guidance to a range of $6.50 to $7.25 per boe versus $7.00 to $7.75 per boe previously. Rubellite will continue to address end of life ARO, with total abandonment and reclamation expenditures of approximately $0.8 million planned for the second half of 2025. In combination with the $0.9 million of asset retirement obligation spending in the first half of the year, the Company is on track to exceed its area-based mandatory spending requirement for 2025 of $1.7 million, as calculated by the Alberta Energy Regulator ("AER"). Capital spending and drilling activity for 2025 is summarized in the table below: (1) Includes one waterflood injection well. (2) Includes two (1.5 net) wells at Frog Lake targeting secondary exploration zones. (3) Excludes abandonment and reclamation spending, acquisitions and land expenditures, if any. Rubellite's capital spending, drilling and operational guidance for 2025 are presented in the table below: (1) Previous full year 2025 guidance dated May 7, 2025. (2) Liquids means oil, condensate, ethane, propane and butane. (3) Non-GAAP financial measure, non-GAAP ratio or supplementary financial measure. See "Non-GAAP and Other Financial Measures". (4) Excludes land and acquisition spending, if any. Three months ended June 30, Six months ended June 30, 2025 2024 2025 2024 Financial Oil revenue 60,542 35,798 127,149 65,621 Net income and comprehensive income 16,051 12,368 17,211 8,215 Per share – basic (1) 0.17 0.20 0.18 0.13 Per share – diluted (1) 0.17 0.19 0.18 0.13 Total Assets 561,545 281,549 561,545 281,549 Cash flow from operating activities 35,808 19,916 62,943 36,413 Adjusted funds flow (2) 37,311 20,664 73,245 39,116 Per share – basic (1)(2) 0.40 0.33 0.79 0.63 Per share – diluted (1)(2) 0.39 0.33 0.77 0.62 Q2 annualized adjusted funds flow (2)(7) 149,244 82,656 149,244 82,656 Net debt to Q2 annualized adjusted funds flow ratio (2)(7) 1.0 0.6 1.0 0.6 Net debt (2) 142,353 49,083 142,353 49,083 Capital expenditures (2) Capital expenditures, including land, corporate and other (2) 31,168 23,927 56,100 36,719 Wells Drilled (3) – gross (net) 11 / 9.0 8 / 8.0 23 / 18.8 15 / 15.0 Common shares outstanding (1) (thousands) Weighted average – basic 93,279 62,494 93,120 62,476 Weighted average – diluted 95,074 63,446 95,426 63,446 End of period 93,395 62,593 93,395 62,593 Operating Heavy Oil (bbl/d) (4) 8,637 4,503 8,489 4,509 Natural gas (Mcf/d) 20,522 — 21,276 — NGLs (bbl/d) (5) 368 — 370 — Daily average sales production (boe/d) 12,425 4,503 12,405 4,509 Average prices West Texas Intermediate ("WTI") ($US/bbl) 63.74 80.57 67.58 78.77 Western Canadian Select ("WCS") ($CAD/bbl) 73.96 91.63 79.13 84.70 AECO 5A Daily Index ($CAD/Mcf) 1.69 1.18 1.93 1.84 Rubellite average realized prices (2)(6) Oil ($/bbl) 69.98 87.35 74.89 79.97 Natural gas ($/Mcf) 1.93 — 2.05 — NGL ($/bbl) 57.92 — 62.72 — Average realized price (2) ($/boe) 53.54 87.35 56.63 79.97 Average realized price, after risk management contracts (2) ($/boe) 57.81 82.99 58.69 79.06 (1) Per share amounts are calculated using the weighted average number of basic or diluted common shares. (2) Non-GAAP measure or ratio. See "Non-GAAP and other Financial Measures" contained in this news release. (3) Well count reflects wells rig released during the period. (4) Conventional heavy oil sales production excludes tank inventory volumes. (5) Liquids means oil, condensate, ethane and butane. (6) Before risk management contracts; supplementary financial measure. See "Non-GAAP and Other Financial Measures". (7) Based on Q2 2025 and Q2 2024 annualized adjusted funds flow before transaction costs relative to period end net debt. Non-GAAP financial measure and ratio. ABOUT RUBELLITE The Company is a Canadian energy company headquartered in Calgary, Alberta which, through its operating subsidiary, Rubellite Energy Inc. is engaged in the exploration, development, production and marketing of its diversified asset portfolio which includes heavy crude oil from the Clearwater and Mannville Stack Formations in Eastern Alberta utilizing multi-lateral drilling technology, liquids-rich conventional natural gas assets in the deep basin of West Central Alberta, and undeveloped bitumen leases in Northern Alberta. The Company is pursuing a robust organic growth plan focused on superior corporate returns and funds flow generation while maintaining a conservative capital structure and prioritizing operational excellence. Additional information on the Company can be accessed on the Company's website at or on SEDAR+ at The Toronto Stock Exchange has neither approved nor disapproved the information contained herein. BOE VOLUME CONVERSIONS Barrel of oil equivalent ("boe") may be misleading, particularly if used in isolation. In accordance with NI 51-101, a conversion ratio for conventional natural gas of 6 Mcf:1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, utilizing a conversion on a 6 Mcf:1 bbl basis may be misleading as an indicator of value as the value ratio between conventional natural gas and heavy crude oil, based on the current prices of natural gas and crude oil, differ significantly from the energy equivalency of 6 Mcf:1 bbl. The following abbreviations used in this news release have the meanings set forth below: INDUSTRY METRICS This news release contains certain industry metrics which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included in this document to provide readers with additional measures to evaluate Rubellite's performance; however, such measures are not reliable indicators of Rubellite's future performance and future performance may not compare to Rubellite's performance in previous periods and therefore such metrics should not be unduly relied upon. INITIAL PRODUCTION RATES Any references in this news release to initial production rates are useful in confirming the presence of hydrocarbons; however, such rates are not determinate of the rates at which such wells will continue production and decline thereafter and are not necessarily indicative of long-term performance or ultimate recovery. Readers are cautioned not to place reliance on such rates in calculating the aggregate production for the Company. Such rates are based on field estimates and may be based on limited data available at this time. ESTIMATED DRILLING LOCATIONS Assuming a January 1, 2025 reference date, of the 316.2 net heavy oil drilling development locations disclosed in this news release, 93.1 net are proved and 45.6 net are probable undeveloped locations in the McDaniel year-end 2024 reserve report. There are 9.5 net proven natural gas locations and 4.4 net probable natural gas locations in the McDaniel year-end reserve report. Unbooked drilling locations are the internal estimates of Rubellite based on Rubellite's or the acquired assets prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by Rubellite's management as an estimation of Rubellite's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Rubellite will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and natural gas reserves, resources or production. The drilling locations on which Rubellite will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been de-risked by Rubellite drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management of Rubellite has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. NON-GAAP AND OTHER FINANCIAL MEASURES Throughout this news release and in other materials disclosed by the Company, Rubellite employs certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed under IFRS and therefore may not be comparable to similar measures presented by other entities. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss), cash flow from (used in) operating activities, and cash flow from (used in) investing activities, as indicators of Rubellite's performance. Non-GAAP Financial Measures Capital Expenditures: Rubellite uses capital expenditures related to exploration and development to measure its capital investments compared to the Company's annual capital budgeted expenditures. Rubellite's capital budget excludes acquisition and disposition activities. The most directly comparable GAAP measure for capital expenditures is cash flow used in investing activities. A summary of the reconciliation of cash flow used in investing activities to capital expenditures, is set forth below: Cash costs: Cash costs are comprised of net operating costs, transportation, general and administrative, and cash finance expense as detailed below. Cash costs per boe is calculated by dividing cash costs by total production sold in the period. Management believes that cash costs assist management and investors in assessing Rubellite's efficiency and overall cost structure. Six Months Ended June 30, ($ thousands, except per boe amounts) $/boe 2025 $/boe 2024 Net operating costs 6.85 15,387 6.51 5,344 Transportation 5.76 12,938 7.77 6,379 General and administrative 3.75 8,429 5.39 4,426 Cash finance expense 2.14 4,798 2.55 2,087 Cash costs 18.50 41,552 22.22 18,236 Operating netbacks and total operating netbacks, after risk management contracts: Operating netback is calculated by deducting royalties, net operating expenses, and transportation costs from oil and natural gas revenue. Operating netback is also calculated on a per boe basis using total production sold in the period. Total operating netbacks, after risk management contracts, is presented after adjusting for realized gains or losses from risk management contracts. Rubellite considers operating netback and operating netback after risk management contracts to be key industry performance indicators that provides investors with information that is also commonly presented by other oil and natural gas producers. Rubellite presents the operating netback at a CGU level as it provides investors with key information related to the heavy oil CGU which is the area where growth capital investment is focused. Operating netback and operating netback, after risk management contracts, evaluate operational performance as it demonstrates its profitability relative to realized and current commodity prices. Net operating costs: Net operating costs equals operating expenses net of other income, which is made up of processing revenue and other one time items from time to time. Management views net operating costs as an important measure to evaluate its operational performance. The most directly comparable IFRS measure for net operating costs is production and operating expenses. The following table reconciles net operating costs from production and operating expenses and other income in the Company's consolidated statement of income (loss) and comprehensive income (loss). Net Debt and Adjusted Working Capital Deficit: Rubellite uses net debt as an alternative measure of outstanding debt and is calculated by adding borrowings under the credit facility and term loan debt less adjusted working capital. Adjusted working capital is calculated by adding cash, accounts receivable, prepaid expenses and deposits and product inventory less accounts payable and accrued liabilities. Management considers net debt as an important measure in assessing the liquidity of the Company. Net debt is used by management to assess the Company's overall debt position and borrowing capacity. Net debt is not a standardized measure and therefore may not be comparable to similar measures presented by other entities. The following table reconciles working capital and net debt as reported in the Company's statements of financial position: (1) Calculation of current assets less current liabilities has been adjusted for the removal of the current portion of risk management contracts, decommissioning liabilities, lease liabilities, share-based compensation and other provisions. (2) Excludes decommissioning liabilities and other provisions. Adjusted funds flow: Adjusted funds flow is calculated based on net cash flows from operating activities, excluding changes in non-cash working capital and expenditures on decommissioning obligations, other provisions and share-based compensation since the Company believes the timing of collection, payment or incurrence of these items is variable. Expenditures on decommissioning and share based compensation obligations may vary from period to period and are managed as expenditures through the corporate budgeting process which considers available adjusted funds flow. Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess the ability of the Company to generate the funds necessary to finance capital expenditures, expenditures on decommissioning obligations, expenditures on share based compensation and meet its financial obligations. Adjusted funds flow is not intended to represent net cash flows from operating activities calculated in accordance with IFRS. The following table reconciles net cash flows from operating activities, as reported in the Company's statements of cash flows, to adjusted funds flow: Free funds flow: Free funds flow is an important measure that informs efficiency of capital spent and liquidity. Free funds flow is calculated as adjusted funds flow generated during the period less capital expenditures. Rubellite's capital expenditures excluded non cash items and acquisitions and dispositions. Adjusted funds flow and capital expenditures are non-GAAP financial measures which have been reconciled to its most directly comparable GAAP measure previously in this document. By removing the impact of current period capital expenditures from adjusted funds flow, Rubellite monitors its free funds flow to inform decisions such as capital allocation and debt repayment. The following table shows the calculation of the removal of capital expenditures from adjusted funds flows pre transaction costs: Available Liquidity: Available liquidity is defined as the borrowing limit under the Company's credit facility, plus any cash and cash equivalents, less any borrowings and letters of credit issued under the credit facility. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioning obligations and to meet its financial obligations. Non-GAAP Financial Ratios Rubellite calculates certain non-GAAP measures per boe as the measure divided by weighted average daily production. Management believes that per boe ratios are a key industry performance measure of operational efficiency and one that provides investors with information that is also commonly presented by other crude oil and natural gas producers. Rubellite also calculates certain non-GAAP measures per share as the measure divided by outstanding common shares. Average realized oil price after risk management contracts: are calculated as the average realized price less the realized gain or loss on risk management contracts. Adjusted funds flow per share: adjusted funds flow per share is calculated using the weighted average number of basic and diluted shares outstanding used in calculating net income (loss) per share. Adjusted funds flow per boe: Adjusted funds flow per boe is calculated as adjusted funds flow divided by total production sold in the period. Net debt to adjusted funds flow ratio: Net debt to adjusted funds flow ratios are calculated on a trailing twelve-month basis. Net debt to annualized adjusted funds flow ratio: Net debt to annualized adjusted funds flow ratios are calculated by annualizing the current quarter adjusted funds flow after transaction costs. Supplementary Financial Measures "Realized oil price" is comprised of total oil revenue, as determined in accordance with IFRS, divided by the Company's total sales oil production on a per barrel basis. "Realized natural gas price" is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company's natural gas sales production. "Realized NGL price" is comprised of NGL commodity sales from production, as determined in accordance with IFRS, divided by the Company's NGL sales production. "Royalties as a percentage of revenue" is comprised of royalties, as determined in accordance with IFRS, divided by oil revenue from sales oil production as determined in accordance with IFRS. "Net operating expense per boe" is comprised of net operating expense, divided by the Company's total sales production. "Transportation cost ($/boe)" is comprised of transportation cost, as determined in accordance with IFRS, divided by the Company's total sales oil production. "General & administrative costs ($/boe)" is comprised of G&A expense, as determined in accordance with IFRS, divided by the Company's total sales oil production. "Heavy oil wellhead differential ($/bbl)" represents the differential the Company receives for selling its heavy crude oil production relative to the Western Canadian Select reference price (Cdn$/bbl) prior to any price or risk management activities. FORWARD-LOOKING INFORMATION Certain information in this news release including management's assessment of future plans and operations, and including the information contained under the headings "Operations Update" and "Outlook and Guidance" may constitute forward-looking information or statements (together "forward-looking information") under applicable securities laws. The forward-looking information includes, without limitation, statements with respect to: future capital expenditures, production and various cost forecasts; the anticipated sources of funds to be used for capital spending; expectations as to future exploration, development and drilling activity, and the benefits to be derived from such drilling including drilling techniques and production growth; the timing for the completion of certain facilities; Rubellite's business plan; and including the forward-looking information contained under the heading "Outlook and Guidance" and "About Rubellite". Forward-looking information is based on current expectations, estimates and projections that involve a number of known and unknown risks, which could cause actual results to vary and in some instances to differ materially from those anticipated by Rubellite and described in the forward-looking information contained in this news release. In particular and without limitation of the foregoing, material factors or assumptions on which the forward-looking information in this news release is based include: the successful operation of the Company's assets, forecast commodity prices and other pricing assumptions; forecast production volumes based on business and market conditions; foreign exchange and interest rates; near-term pricing and continued volatility of the market; accounting estimates and judgments; future use and development of technology and associated expected future results; the ability to obtain regulatory approvals; the successful and timely implementation of capital projects; ability to generate sufficient cash flow to meet current and future obligations and future capital funding requirements (equity or debt); the ability of Rubellite to obtain and retain qualified staff and equipment in a timely and cost-efficient manner, as applicable; the retention of key properties; forecast inflation, supply chain access and other assumptions inherent in Rubellite's current guidance and estimates; climate change; severe weather events (including wildfires, floods and drought); the continuance of existing tax, royalty, and regulatory regimes; the accuracy of the estimates of reserves volumes; ability to access and implement technology necessary to efficiently and effectively operate assets; risk of wars or other hostilities or geopolitical events (including the ongoing war in Ukraine and conflicts in the Middle East), civil insurrection and pandemics; risks relating to Indigenous land claims and duty to consult; data breaches and cyber attacks; risks relating to the use of artificial intelligence; changes in laws and regulations, including but not limited to tax laws, royalties and environmental regulations (including greenhouse gas emission reduction requirements and other decarbonization or social policies) and including uncertainty with respect to the interpretation and impact of omnibus Bill C-59 and the related amendments to the Competition Act (Canada), and the interpretation of such changes to the Company's business); political, geopolitical and economic instability; trade policy, barriers, disputes or wars (including new tariffs or changes to existing international trade requirements and general economic and business conditions and markets, among others. Undue reliance should not be placed on forward-looking information, which is not a guarantee of performance and is subject to a number of risks or uncertainties, including without limitation those described herein and under "Risk Factors" in the Company's Annual Information Form and MD&A for the year ended December 31, 2024 and in other reports on file with Canadian securities regulatory authorities which may be accessed through the SEDAR+ website and at Rubellite's website Readers are cautioned that the foregoing list of risk factors is not exhaustive. Forward-looking information is based on the estimates and opinions of Rubellite's management at the time the information is released, and Rubellite disclaims any intent or obligation to update publicly any such forward-looking information, whether as a result of new information, future events or otherwise, other than as expressly required by applicable securities law. SOURCE Rubellite Energy Corp.
Cision Canada
4 days ago
- Business
- Cision Canada
Great-West Lifeco reports record base earnings and announces intention for additional $500 million in share buybacks Français
Great-West Lifeco Inc.'s Quarterly Report to Shareholders for the second quarter of 2025, including its Management's Discussion and Analysis (MD&A) and consolidated financial statements for the three and six months ended June 30, 2025, are available at and Readers are referred to the Basis of presentation, Cautionary note regarding Forward-Looking Information and Cautionary note regarding Non-GAAP Financial Measures and Ratios sections at the end of this release for additional information on disclosures. All figures are expressed in millions of Canadian dollars, unless otherwise noted. Base earnings of over $1.1 billion, up 11% from Q2 2024 and base EPS of $1.24, up 12% from Q2 2024 Net earnings of $894 million, or $0.96 per share, down 11% from Q2 2024 Base ROE of 17.4% and ROE of 14.9% LICAT ratio of 132% and Lifeco cash of $2.1 billion Book value per share of $27.38, up 8% year over year Repurchased 6.3 million shares in Q2 at a total cost of $321 million; intention to repurchase an additional $500 million of shares in 2025 WINNIPEG, MB, Aug. 5, 2025 /CNW/ - Great-West Lifeco Inc. (Lifeco or the Company) today announced its Q2 2025 results. "We delivered double-digit base earnings growth in the second quarter, primarily driven by strong performance in our wealth and group benefits businesses, and successfully navigated a period of elevated market volatility," said David Harney, President and CEO, Great-West Lifeco. "I am particularly pleased with the strong underlying performance at Empower, which remains well positioned to drive double-digit base earnings growth going forward. Overall, we are on track to meet or exceed all our medium-term objectives, supported by our strong capital generation, healthy balance sheet and unrelenting focus on executing against our growth strategies." Key Financial Highlights Base earnings 1 of $1,149 million ($1.24 per common share) in the second quarter, up 11% from $1,038 million a year ago. The strong result reflects double-digit base earnings growth across our Wealth and Group Benefits businesses, primarily driven by new business growth and higher equity markets, as well as improved insurance experience, and favourable currency movements, partially offset by lower earnings on surplus from lower yields. Base earnings also included a benefit for a change in certain tax estimates relating to tax matters in prior years, offset by credit-related impacts of $51 million (post-tax). Net earnings from continuing operations of $894 million ($0.96 per common share) in the second quarter, compared to $1,005 million a year ago, mainly reflect higher charges from business transformation initiatives announced earlier this year, as well as unfavourable market experience. Highlights Strong underlying performance: Base earnings reached a record $1,149 million, up 11% year-over-year, driven by double-digit base earnings growth in our Wealth and Group Benefits businesses. Base ROE of 17.4% and ROE of 14.9% remain well-positioned to expand, supported by strong growth in our more capital-efficient U.S. business and further share buybacks. Strong capital generation and $2.1 billion in cash at Lifeco continue to provide substantial flexibility. Continued repositioning of the portfolio toward higher-growth, capital-efficient businesses, particularly Retirement and Wealth: Total client assets 4 of $3.0 trillion, of which $1.0 trillion represents higher-margin assets under management or advisement 4. Strong growth in client assets of 11% in Retirement and 16% in Wealth. Double-digit base earnings growth in our Group Benefits businesses, driven by strong long-term disability experience in Canada, reflecting continued pricing discipline. U.S. segment continues to deliver strong base earnings growth: U.S. base earnings were up 13% year-over-year excluding credit-related impacts of US$37 million in Q2 2025 and US$29 million in Q2 2024, and a favourable one-time fee income adjustment to earnings of US$22 million in Q2 2024. Base earnings growth was driven by an increase in average customer account balances and the number of plan participants, as well as continued strength in Wealth net flows. Empower's Retirement business is expected to experience net plan inflows of at least US$25 billion for the second half of 2025, more than offsetting a notable termination in Q2 2025 5. Empower Wealth net flows 6 improved by 83% to US$2.9 billion compared to a year ago, primarily from strong rollover sales performance. The number of plan participants served by Empower stood at 18.5 million on June 30, 2025, up 3% from a year ago, primarily reflecting solid organic growth over the past 12 months. Empower significantly strengthened its product offering by partnering with top-tier asset management firms to provide private markets investment options for 401k plan participants. Balance sheet strength provides substantial financial flexibility: LICAT ratio 7 of 132%, up 2 percentage points from Q1 2025, driven by strong base capital generation, and lower remittances to Lifeco. Leverage ratio of 28% was unchanged from the preceding quarter, but stood at 27% on a pro forma basis, net of the scheduled repayment of US$500 million senior notes maturing on August 12, 2025. Lifeco cash of $2.1 billion reflected significant share repurchases in the quarter. The Company intends to repurchase an additional $500 million of its common shares in 2025 under its Normal Course Issuer Bid (NCIB), beyond the $500 million announced on May 7, 2025 and the purchases made to offset dilution under its share compensation plans. For reporting purposes, Lifeco's consolidated operating results are grouped into five reportable segments – United States, Canada, Europe, Capital and Risk Solutions and Corporate – reflecting the management and corporate structure of the Company. For more information, refer to the Company's second quarter 2025 interim Management's Discussion and Analysis (MD&A). 8 This is a non-GAAP financial measure. Refer to the "Non-GAAP Financial Measures and Ratios" section of this document for additional details. 9 The Company has updated segment and line of business classifications for 2025 which has resulted in the restatement of certain comparative amounts. UNITED STATES U.S. segment base earnings of US$247 million ($341 million) and net earnings from continuing operations of US$222 million ($305 million) – Base earnings were largely unchanged from Q2 2024. Higher fee income from business growth and favourable markets was offset by credit-related impacts in the quarter of US$37 million, and lower spread-based income. Base earnings in Q2 2024 included US$29 million of negative credit-related impacts and a favourable one-time fee income adjustment to earnings of US$22 million. CANADA Canada segment base earnings of $375 million and net earnings of $255 million – Base earnings increased by $15 million, or 4%, compared to the same quarter last year, reflecting solid performance across businesses, notably improved insurance experience in Group Benefits, partially offset by lower earnings on surplus. Net earnings were impacted by business transformation charges, in line with previously announced transformation initiatives. EUROPE Europe segment base earnings of $262 million and net earnings of $126 million – Base earnings increased by $26 million, or 11%, compared to the same quarter last year, primarily due to increased Wealth fee income from higher client assets, as well as the impact of currency movements. These items were partially offset by lower earnings on surplus. CAPITAL AND RISK SOLUTIONS Capital and Risk Solutions segment base earnings of $229 million and net earnings of $194 million – Base earnings increased by $30 million, or 15%, compared to the same quarter last year, primarily due to continued strength in Capital Solutions new business volumes and improved claims experience. QUARTERLY DIVIDENDS The Board of Directors approved a quarterly dividend of $0.61 per share on the common shares of Lifeco payable September 29, 2025, to shareholders of record at the close of business August 29, 2025. In addition, the Directors approved quarterly dividends on Lifeco's preferred shares, as follows: For purposes of the Income Tax Act (Canada), and any similar provincial legislation, the dividends referred to above are eligible dividends. NCIB Share Purchases The Company intends to repurchase an additional $500 million of its common shares in 2025 under its Normal Course Issuer Bid (NCIB), beyond the $500 million announced on May 7, 2025 and the purchases made to offset dilution under its share compensation plans. This is subject to market conditions, applicable regulatory approvals, the Company's ability to effect the purchases on a prudent basis, and other strategic opportunities emerging. Analysts' Estimates The average estimate of earnings per share and base earnings per share for the quarter among the analysts who follow the Company was $1.07 and $1.17, respectively. Q2 2025 Conference Call Lifeco's second quarter conference call and audio webcast will be held on Wednesday, August 6, 2025 at 8:30 a.m. ET. The live webcast of the call will be available at 2nd Quarter 2025 – Conference Call and Webcast or by calling 1-833-752-3481 (toll-free) or 1-647-846-7232 for International participants. A replay of the call will be available following the event on our website or by calling 1-855-669-9658 (Canada toll-free) or 1-412-317-0088 (U.S. toll-free) and using the access code 6604451. Selected financial information is attached. GREAT-WEST LIFECO INC. Great-West Lifeco is a financial services holding company focused on building stronger, more inclusive and financially secure futures. We operate in Canada, the United States and Europe under the brands Canada Life, Empower and Irish Life. Together we provide wealth, retirement, workplace benefits and insurance and risk solutions to our over 40 million customer relationships. As of June 30, 2025, Great-West Lifeco's total client assets were $3 trillion. Great-West Lifeco trades on the Toronto Stock Exchange (TSX) under the ticker symbol GWO and is a member of the Power Corporation group of companies. To learn more, visit Basis of presentation The condensed consolidated interim financial statements for the period ended June 30, 2025 of Lifeco, have been prepared in accordance with International Financial Reporting Standards (IFRS) unless otherwise noted and are the basis for the figures presented in this release, unless otherwise noted. Cautionary note regarding Forward-Looking Information From time to time, Lifeco makes written and/or oral forward-looking statements within the meaning of applicable securities laws, including in this release. Forward-looking information includes statements that are predictive in nature, depend upon or refer to future events or conditions, or include words such as "achieve", "ambition", "anticipate", "believe", "could", "estimate", "expect", "initiatives", "intend", "may", "objective", "opportunity", "plan", "potential", "project", "target", "will" and other similar expressions or negative versions of those words. Forward-looking information includes, without limitation, statements about the Company and its operations, business (including business mix), financial condition, expected financial performance (including revenues, earnings or growth rates, and medium-term financial objectives), strategies and prospects, expected costs and benefits of acquisitions and divestitures (including timing of integration activities and timing and extent of revenue and expense synergies), the timing and extent of expected transformation charges, expected expenditures or investments (including but not limited to investment in technology infrastructure and digital capabilities and solutions and investments in strategic partnerships), the timing and completion of the acquisition by IPC of wealth assets of De Thomas Wealth Management, value creation and realization and growth opportunities, product and service innovation, expected dividend levels, expected cost reductions and savings, expected capital management activities and use of capital, the timing and extent of possible share repurchases, market position, estimates of risk sensitivities affecting capital adequacy ratios, estimates of financial risk sensitivities (including as a result of current market conditions), expected net plan inflows, anticipated global economic conditions, potential impacts of catastrophe events, potential impacts of geopolitical events and conflicts and the impact of regulatory developments on the Company's business strategy, growth objectives and capital. Forward-looking statements are based on expectations, forecasts, estimates, predictions, projections and conclusions about future events that were current at the time of the statements and are inherently subject to, among other things, risks, uncertainties and assumptions about the Company, economic factors and the financial services industry generally, including the insurance, wealth and retirement solutions industries. They are not guarantees of future performance, and actual events and results could differ materially from those expressed or implied by forward-looking statements. Many of these assumptions are based on factors and events that are not within the control of the Company and there is no assurance that they will prove to be correct. With respect to possible share repurchases, the amount and timing of actual repurchases will depend on the earnings, cash requirements and financial condition of the Company, market conditions, our ability to effect the repurchases on a prudent basis, capital requirements, applicable law and regulations (including applicable securities laws), and other factors deemed relevant by the Company, and may be subject to regulatory approval or conditions. With respect to expected net plan inflows of Empower's Retirement business in the second half of 2025, management's estimate is based on the sum of anticipated sales (excluding stock plan services) plus anticipated institutional net flows, net of estimated plan terminations. Management has also assumed that performance of Empower's Retirement business during the second half of 2025 is consistent with its expectations, which take into account current market information, and that actual sales, the ability to maintain or improve client retention and capture rates per management's estimates, and customer behaviour (including contributions, redemptions, withdrawals and lapse rates) are consistent with management's estimates. Statements about historical credit experience are not intended to be indicators of future credit experience. In all cases, whether or not actual results differ from forward-looking information may depend on numerous factors, developments and assumptions, including, without limitation, the ability to integrate and leverage acquisitions and achieve anticipated benefits and synergies, the achievement of expense synergies and client retention targets from the acquisition of the Prudential retirement business, the Company's ability to execute strategic plans and adapt or recalibrate these plans as needed, the Company's reputation, business competition, assumptions around sales, pricing, fee rates, customer behaviour (including contributions, redemptions, withdrawals and lapse rates), mortality and morbidity experience, expense levels, reinsurance arrangements, global equity and capital markets (including continued access to equity and debt markets and credit instruments on economically feasible terms), geopolitical tensions and related economic impacts, interest and foreign exchange rates, inflation levels, liquidity requirements, investment values and asset breakdowns, hedging activities, financial condition of industry sectors and individual issuers that comprise part of the Company's investment portfolio, credit ratings, taxes, write-downs of goodwill and other intangible assets, technological changes, breaches or failure of information systems and security (including cyber attacks), assumptions around third-party suppliers, changes in local and international laws and regulations, changes in accounting policies and the effect of applying future accounting policy changes, changes in actuarial standards, unexpected judicial or regulatory proceedings, catastrophic events, continuity and availability of personnel and third-party service providers, unplanned changes to the Company's facilities, customer and employee relations, levels of administrative and operational efficiencies, and other general economic, political and market factors in North America and internationally. The above list is not exhaustive, and there may be other factors listed in the Company's filings with securities regulators, including those set out in the "Risk Management" and "Summary of Critical Accounting Estimates" sections of the Company's 2024 Annual MD&A and in the Company's annual information form dated February 5, 2025 under "Risk Factors". These, along with other filings, are available for review at The reader is cautioned to consider these and other factors, uncertainties and potential events carefully and not to place undue reliance on forward-looking information. Other than as specifically required by applicable law, the Company does not intend to update any forward-looking information whether as a result of new information, future events or otherwise. Cautionary note regarding Non-GAAP Financial Measures and Ratios This release contains some non-Generally Accepted Accounting Principles (GAAP) financial measures and non-GAAP ratios as defined in National Instrument 52-112 "Non-GAAP and Other Financial Measures Disclosure". Terms by which non-GAAP financial measures are identified include, but are not limited to, "base earnings (loss)", "base earnings (loss) (US$)", "base earnings (loss) - pre-tax", "base earnings: insurance service result", "base earnings: net investment result", "assets under management or advisement", "assets under administration", "client assets", "non-par base operating and administration expenses", and "run-rate insurance results". Terms by which non-GAAP ratios are identified include, but are not limited to, "base earnings per common share (EPS)", "base return on equity (ROE)", "base dividend payout ratio", "base capital generation", "efficiency ratio", "effective income tax rate – base earnings – common shareholders" and "pre-tax base operating margin". Non-GAAP financial measures and ratios are used to provide management and investors with additional measures of performance to help assess results where no comparable GAAP (IFRS) measure exists. However, non-GAAP financial measures and ratios do not have standard meanings prescribed by GAAP (IFRS) and are not directly comparable to similar measures used by other companies. Refer to the "Non-GAAP Financial Measures and Ratios" section in this release for the appropriate reconciliations of these non-GAAP financial measures to measures prescribed by GAAP as well as additional details on each measure and ratio. 1 This metric is a non-GAAP financial measure. Refer to the "Non-GAAP Financial Measures and Ratios" section of this document for additional details. 2 Refer to the "Glossary" section of the Company's second quarter of 2025 interim MD&A for additional details on the composition of this measure. 3 This metric is a non-GAAP ratio. Refer to the "Non-GAAP Financial Measures and Ratios" section of this document for additional details. 4 The calculation for financial leverage ratio includes the after-tax non-participating contractual service margin (CSM) balance in the denominator, excluding CSM associated with segregated fund guarantees. This reflects that the CSM represents future profit and is considered available capital under LICAT. These ratios are estimates based on available data. 5 The Life Insurance Capital Adequacy Test (LICAT) Ratio is based on the consolidated results of The Canada Life Assurance Company, Lifeco's major Canadian operating subsidiary. The LICAT Ratio is calculated in accordance with the Office of Superintendent of Financial Institutions' guideline - Life Insurance Capital Adequacy Test. Refer to the "Capital Management and Adequacy" section of the Company's second quarter of 2025 interim MD&A for additional details. BASE AND NET EARNINGS Consolidated base earnings and net earnings of Lifeco include the base earnings and net earnings of Empower, Canada Life (and its operating subsidiaries) and the Company's Corporate operating results (including PanAgora Asset Management). Net earnings for the six months ended June 30, 2024 also include the earnings from Putnam Investments reported as discontinued operations. For a further description of base earnings, refer to the "Non-GAAP Financial Measures and Ratios" section of this document and the Company's second quarter of 2025 interim Management's Discussion and Analysis. For further details on restated earnings for the first and second quarters of 2024, refer to the "Summary of Earnings Reclassification" section of the Company's second quarter of 2025 interim Management's Discussion and Analysis. Base earnings 1 and net earnings - common shareholders by segment For the three months ended For the six months ended June 30 2025 Mar. 31 2025 June 30 2024 (Restated) June 30 2025 June 30 2024 (Restated) Base earnings (loss) 1 United States $ 341 $ 365 $ 335 $ 706 $ 637 Canada 375 316 360 691 700 Europe 262 239 236 501 462 Capital and Risk Solutions 229 213 199 442 404 Corporate (58) (103) (92) (161) (187) Lifeco base earnings 1 $ 1,149 $ 1,030 $ 1,038 $ 2,179 $ 2,016 Items excluded from base earnings Market experience relative to expectations 2 $ (104) $ (91) $ 28 $ (195) $ 135 Assumption changes and management actions 2 (3) (32) 39 (35) 38 Business transformation impacts (121) (10) (29) (131) (78) Amortization of acquisition-related finite life intangibles (38) (37) (37) (75) (75) Tax legislative changes 11 — (34) 11 — Items excluded from Lifeco base earnings $ (255) $ (170) $ (33) $ (425) $ 20 Net earnings (loss) from continuing operations 2 United States $ 305 $ 338 $ 281 $ 643 $ 523 Canada 255 301 373 556 764 Europe 126 167 231 293 447 Capital and Risk Solutions 194 184 164 378 434 Corporate 14 (130) (44) (116) (132) Lifeco net earnings from continuing operations 2 $ 894 $ 860 $ 1,005 $ 1,754 $ 2,036 Net earnings (loss) from discontinued operations — — — — (115) Net gain from disposal of discontinued operations — — — — 44 Lifeco net earnings - common shareholders $ 894 $ 860 $ 1,005 $ 1,754 $ 1,965 1 This metric is a non-GAAP financial measure. Refer to the "Non-GAAP Financial Measures and Ratios" section of this document for additional details. 2 Refer to the "Glossary" section of the Company's second quarter of 2025 interim MD&A for additional details on the composition of this measure. NON-GAAP FINANCIAL MEASURES AND RATIOS Non-GAAP Financial Measures The Company uses several non-GAAP financial measures to measure overall performance of the Company and to assess each of its business units. A financial measure is considered a non-GAAP measure for Canadian securities law purposes if it is presented other than in accordance with generally accepted accounting principles (GAAP) used for the Company's consolidated financial statements. The consolidated financial statements of the Company have been prepared in compliance with IFRS as issued by the IASB. Non-GAAP financial measures do not have a standardized meaning under GAAP and may not be comparable to similar financial measures presented by other issuers. Investors may find these financial measures useful in understanding how management views the underlying business performance of the Company. Base earnings (loss) Base earnings (loss) reflect management's view of the underlying business performance of the Company and provides an alternate measure to understand the underlying business performance compared to IFRS net earnings. Base earnings (loss) exclude the following items from IFRS reported net earnings: Market-related impacts, where actual market returns in the current period are different than longer-term expected returns; Assumption changes and management actions that impact the measurement of assets and liabilities; Business transformation impacts which include acquisition and divestiture costs and restructuring and integration costs; Material legal settlements, material impairment charges related to goodwill and intangible assets, impacts of income tax rate changes on the remeasurement of deferred tax assets and liabilities and other tax impairments, net gains, losses or costs related to the disposition or acquisition of a business; net earnings (loss) from discontinued operations; The direct equity and interest rate impacts on the measurement of surplus assets and liabilities; Amortization of acquisition related finite life intangible assets; and Other items that, when removed, assist in explaining the Company's underlying business performance. United States For the three months ended For the six months ended June 30 2025 Mar. 31 2025 June 30 2024 (Restated) June 30 2025 June 30 2024 (Restated) Base earnings $ 341 $ 365 $ 335 $ 706 $ 637 Items excluded from base earnings Market experience relative to expectations (pre-tax) $ (3) $ 2 $ (7) $ (1) $ (10) Income tax (expense) benefit — — 1 — 2 Business transformation impacts (pre-tax) (9) (1) (26) (10) (70) Income tax (expense) benefit 3 — 4 3 16 Amortization of acquisition-related finite life intangibles (pre-tax) (36) (38) (37) (74) (71) Income tax (expense) benefit 9 10 11 19 19 Net earnings from continuing operations $ 305 $ 338 $ 281 $ 643 $ 523 Net earnings (loss) from discontinued operations (post-tax) — — — — (115) Net gain from disposal of discontinued operations (post-tax) — — — — 44 Net earnings - common shareholders $ 305 $ 338 $ 281 $ 643 $ 452 Canada For the three months ended For the six months ended June 30 2025 Mar. 31 2025 June 30 2024 (Restated) June 30 2025 June 30 2024 (Restated) Base earnings $ 375 $ 316 $ 360 $ 691 $ 700 Items excluded from base earnings Market experience relative to expectations (pre-tax) $ 44 $ (9) $ 35 $ 35 $ 128 Income tax (expense) benefit (19) (1) (10) (20) (36) Assumption changes and management actions (pre-tax) (1) — 1 (1) 10 Income tax (expense) benefit — — — — (3) Business transformation impacts (pre-tax) (192) (2) (9) (194) (32) Income tax (expense) benefit 53 1 2 54 8 Amortization of acquisition-related finite life intangibles (pre-tax) (7) (6) (8) (13) (15) Income tax (expense) benefit 2 2 2 4 4 Net earnings - common shareholders $ 255 $ 301 $ 373 $ 556 $ 764 Europe For the three months ended For the six months ended June 30 2025 Mar. 31 2025 June 30 2024 (Restated) June 30 2025 June 30 2024 (Restated) Base earnings $ 262 $ 239 $ 236 $ 501 $ 462 Items excluded from base earnings Market experience relative to expectations (pre-tax) $ (139) $ (47) $ 13 $ (186) $ (2) Income tax (expense) benefit 29 11 (5) 40 (2) Assumption changes and management actions (pre-tax) (1) (32) (2) (33) (2) Income tax (expense) benefit 1 8 — 9 — Business transformation impacts (pre-tax) (42) (10) — (52) — Income tax (expense) benefit 10 2 — 12 — Amortization of acquisition-related finite life intangibles (pre-tax) (6) (5) (5) (11) (11) Income tax (expense) benefit 1 1 1 2 2 Tax legislative changes impact (pre-tax) — — — — — Income tax (expense) benefit 11 — (7) 11 — Net earnings - common shareholders $ 126 $ 167 $ 231 $ 293 $ 447 Capital and Risk Solutions For the three months ended For the six months ended June 30 2025 Mar. 31 2025 June 30 2024 (Restated) June 30 2025 June 30 2024 (Restated) Base earnings $ 229 $ 213 $ 199 $ 442 $ 404 Items excluded from base earnings Market experience relative to expectations (pre-tax) $ (31) $ (35) $ (6) $ (66) $ 43 Income tax (expense) benefit 4 7 (2) 11 (6) Assumption changes and management actions (pre-tax) (3) (1) (1) (4) (7) Income tax (expense) benefit 1 — 1 1 — Business transformation impacts (9) — — (9) — Income tax expense (benefit) 3 — — 3 — Tax legislative changes impact (pre-tax) — — — — — Income tax (expense) benefit — — (27) — — Net earnings - common shareholders $ 194 $ 184 $ 164 $ 378 $ 434 Corporate For the three months ended For the six months ended June 30 2025 Mar. 31 2025 June 30 2024 (Restated) June 30 2025 June 30 2024 (Restated) Base earnings (loss) $ (58) $ (103) $ (92) $ (161) $ (187) Items excluded from base earnings (loss) Market experience relative to expectations (pre-tax) $ 13 $ (24) $ 10 $ (11) $ 22 Income tax (expense) benefit (2) 5 (1) 3 (4) Assumption changes and management actions (pre-tax) — (9) 3 (9) 3 Income tax (expense) benefit — 2 37 2 37 Business transformation impacts (pre-tax) 71 — — 71 — Income tax (expense) benefit (9) — — (9) — Amortization of acquisition-related finite life intangibles (pre-tax) (2) (2) (2) (4) (5) Income tax (expense) benefit 1 1 1 2 2 Net earnings (loss) - common shareholders $ 14 $ (130) $ (44) $ (116) $ (132) Assets under administration (AUA), assets under management or advisement (AUMA), and client assets Assets under administration, assets under management or advisement and client assets are non-GAAP financial measures. These measures provide an indication of the size and volume of the Company's overall business. Administrative services are an important aspect of the overall business of the Company and should be considered when comparing volumes, size and trends. Total assets under administration includes assets under management or advisement (AUMA), assets under administration only (AUAO), the total of which is total client assets, and other balance sheet assets. Client assets represents the total client assets under management or advisement plus assets under administration only for the Company's Retirement and Wealth lines of business. Client assets are classified as AUMA where the Company earns a fee for one or more of the following services: investment management services for proprietary funds or institutional assets, discretionary portfolio management on behalf of clients, and/or the provision of financial advice. AUMA relate to the Company's Retirement and Wealth lines of business only. Refer to the "Glossary" section of the Company's second quarter of 2025 interim MD&A for the definition of AUAO. Other balance sheet assets include insurance contract assets, reinsurance contract assets, goodwill and intangible assets, other assets, as well as the portion of invested assets and investments on account of segregated fund policyholders not included within total client assets. 1 Total Lifeco assets under administration includes assets under management related to PanAgora Asset Management included in the Corporate segment. 2 Refer to the "Glossary" section of the Company's second quarter of 2025 interim MD&A for additional details on the composition of this measure. NON-GAAP RATIOS A non-GAAP ratio is a financial measure in the form of a ratio, fraction, percentage or similar representation that is not disclosed in the financial statements of the Company and has a non-GAAP financial measure as one or more of its components. These financial measures do not have a standardized definition under IFRS and might not be comparable to similar financial measures disclosed by other issuers. The non-GAAP ratios disclosed by the Company each use base earnings (loss) as the non-GAAP component. Base earnings (loss) reflect management's view of the underlying business performance of the Company and provides an alternate measure to understand the underlying business performance compared to IFRS net earnings. Base dividend payout ratio - Dividends paid to common shareholders are divided by base earnings (loss). Base earnings per share - Base earnings (loss) for the period is divided by the number of average common shares outstanding for the period. Base return on equity - Base earnings (loss) for the trailing four quarters are divided by the average common shareholders' equity over the trailing four quarters. This measure provides an indicator of business unit profitability. Efficiency ratio - Calculated on a trailing four quarter basis as pre-tax non-par base operating and administrative expenses divided by the sum of pre-tax base earnings and pre-tax non-par base operating and administrative expenses. SOURCE Great-West Lifeco Inc.
