Author: Ravi Shankar

MONTRÉAL, Nov. 12, 2026 (GLOBE NEWSWIRE) — Nordique Critical Metals Inc. (“Nordique” or the “Company”) (TSXV: NQC | FRA: J6K | OTCQB: JORFF) announces rare-earth leaching efficiencies exceeding 95% for neodymium, dysprosium and yttrium in samples tested from the Kwyjibo Rare Earth project. The bench-scale testing, conducted by L3 Process Development (“L3”), demonstrates that a high proportion of these elements can be extracted from Kwyjibo mineral concentrate during the leaching stage, supporting the development of an efficient rare-earth processing operation.

The latest work also points to a substantially simpler processing plant. Building on earlier metallurgical studies by Hazen Research and COREM, L3 and SMH Process Innovation (“SMH”) have developed a revised hydrometallurgical flowsheet designed to eliminate several processing stages included in the Company’s 2026 Preliminary Economic Assessment (“PEA”). Fewer processing stages could mean less equipment, lower energy requirements, as well as reduced construction and operating costs at the Kwyjibo Project. L3 and SMH are continuing to optimize the revised flowsheet, with plans to validate the process through a continuous rare-earth demonstration plant targeted to begin operations in Q1 2027.

Higher recovery could further strengthen Kwyjibo’s economics. The 2026 PEA assumed approximately 75% overall rare-earth recovery and outlined an after-tax net present value (8%) of $1.40 billion, an after-tax internal rate of return of 35.4% and an estimated two-year payback period. Based on recent testing, L3 and SMH are evaluating the potential to increase overall recovery in excess of 80%. If achieved, higher recovery could allow Kwyjibo to produce more saleable rare-earth material from the same quantity of mined ore. This recovery range remains a preliminary objective and is not included in the 2026 PEA economics.

A smaller, more efficient plant could support targeted annual production exceeding 10,000 tonnes of rare-earth oxides. Preliminary engineering discussions with L3 and SMH indicate that the simplified processing flowsheet could substantially reduce the hydrometallurgical plant’s footprint and power requirements compared with the 2026 PEA design. This could allow Kwyjibo to pursue its planned production capacity with less equipment, reduced infrastructure and potentially lower operating costs, subject to further metallurgical testing and engineering confirmation.

Kwyjibo combines an approximately 10-year mine life with a strategic location in eastern Québec. The 2026 PEA outlines an underground mining operation with a planned surface mine footprint of approximately 2.67 hectares. The Project is located approximately 125 km northeast of Sept-Îles, with its proposed processing complex near Rivière-au-Tonnerre, along Québec’s Côte-Nord transportation corridor. This location provides opportunities to connect with regional road, energy and marine transportation infrastructure and positions Kwyjibo within eastern Canada’s supply chain already serving North American, European, and Asian markets.

The underground mine design also offers an opportunity to reduce surface footprint.    Nordique is advancing a design intended to eliminate permanent surface tailings storage by returning all processing residues underground as cemented paste backfill. Arcadis Professional Services (Canada) Inc. (“Arcadis”) has been retained to evaluate this proposed approach and support the associated technical, environmental and regulatory studies.

The next step is to pilot and demonstrate that the simplified process can operate continuously. Nordique is working with L3 and SMH to prepare approximately 400 kg of nonmagnetic concentrate for a continuous rare-earth demonstration plant targeted to begin operations in Q1 2027. The program is intended to validate the revised processing flowsheet, evaluate rare-earth extraction and subsequent separation stages, and generate the operating data needed to advance Kwyjibo toward feasibility-level engineering.

Technical Disclosure and Qualified Person

The metallurgical results described in this release are based on laboratory-scale testing conducted by L3 Process Development on Kwyjibo mineral concentrate. Leaching efficiency measures the proportion of the specified elements transferred into solution during leaching and does not represent overall process recovery or recovery of finished rare-earth products. Further validation using representative material and continuous operating conditions is required.

The economic results and approximately 10-year mine life are derived from the Company’s 2026 Preliminary Economic Assessment for the Kwyjibo Rare Earth Project, filed on SEDAR+ on August 14, 2026. The PEA is preliminary in nature and includes Inferred Mineral Resources that are considered too speculative geologically to have the economic considerations applied to them that would enable them to be categorized as Mineral Reserves. There is no certainty that the PEA will be realized. Mineral Resources that are not Mineral Reserves do not have demonstrated economic viability.

Annual production exceeding 10,000 tonnes of rare-earth oxides represents a proposed production target, not a demonstrated production rate. Its precise product basis and relationship to the filed PEA require more metallurgical test work with process engineering and equipment requirements and confirmation by the Qualified Person. Potential improvements to recovery, operating costs, plant footprint and energy consumption remain preliminary development objectives and have not been incorporated into a revised economic assessment.

The economic results and mine life referenced in this news release are based on the technical report entitled « Rapport technique – Évaluation économique préliminaire – Mise à jour, Projet Kwyjibo, Québec, Canada », prepared by DRA Americas Inc. and filed on SEDAR+ on August 14, 2026.

Cautionary Note and Other Relevant Information

1. Mineral Resources are not Mineral Reserves and do not have demonstrated economic viability.
2. The Updated PEA is preliminary in nature and includes Inferred Mineral Resources that are considered too speculative geologically to have the economic considerations applied to them that would enable them to be categorized as Mineral Reserves. There is no certainty that the results of the Updated PEA will be realized.
3. The mineral resource estimate specified in the Updated PEA (the “MRE”) has been prepared in accordance with the Canadian Institute of Mining, Metallurgy and Petroleum (CIM) Definition Standards for Mineral Resources and Mineral Reserves (2014), as incorporated by reference into National Instrument 43-101 – Standards of Disclosure for Mineral Projects (“NI 43-101”).
4. The Inferred Mineral Resource has a lower level of confidence than Measured and Indicated Mineral Resources and cannot be converted directly into a Mineral Reserve. It is reasonably expected that additional drilling may upgrade portions of the Inferred Mineral Resource to the Indicated category; however, there is no certainty that such upgrading will occur.
5. The Mineral Resource Estimate specified in the Updated PEA remains subject to assumptions regarding mining, metallurgical performance, processing recoveries, commodity prices, operating costs, capital costs, environmental permitting, taxation, title, legal matters, marketing, social considerations and other modifying factors that may materially affect the estimate.
6. The MRE has an effective date of June 25, 2026, and is based on 109 surface drill holes totaling 19,168 metres, incorporating 4,962 analytical samples and 886 specific gravity measurements. The estimate was completed using three-dimensional geological modelling, inverse distance squared (ID²) interpolation, 1.5-metre composites, 10 m × 10 m × 5 m block dimensions, a density model correlated with iron grade, and a CAD $330 per tonne cut-off value.
7. Reported Mineral Resources in the Updated PEA are exclusive of Mineral Reserves, and totals may not add precisely due to rounding.
8. Readers are cautioned not to assume that all or any part of the Measured, Indicated or Inferred Mineral Resources will ever be converted into Mineral Reserves or that the Updated PEA represents, or will result in, an economically viable mining operation.

The scientific and technical information relating to the hydrometallurgical program in this news release has been reviewed and approved by Eric Larochelle, P.Eng. (OIQ #112819), President of SMH Process Innovation and an independent consulting engineer to the Company, who is a Qualified Person as defined under NI 43-101.

SMH Process Innovation specializes in hydrometallurgical process development, optimization and engineering, with expertise in translating laboratory-scale metallurgical results into practical processing circuits. At Kwyjibo, SMH is contributing to the development and simplification of the hydrometallurgical flowsheet, including rare-earth recovery, impurity management and reagent recycling. Its involvement will support the integration of metallurgical testwork with process engineering and equipment requirements, helping establish a practical technical foundation for continuous demonstration testing and subsequent feasibility-level studies.

L3 Process Development provides specialized laboratory testing and process development services, including hydrometallurgical extraction, separation and process optimization. L3 has already completed bench-scale testing on Kwyjibo material, achieving encouraging rare-earth leaching results and evaluating subsequent extraction and purification stages. Building on this work, L3 will play a central role in the planned continuous demonstration program, evaluating rare-earth extraction, individual element separation and integrated process performance. Its laboratory and process development capabilities will help generate the operating data required to advance Kwyjibo’s rare-earth processing technology toward larger-scale implementation.

Arcadis is a global engineering and environmental consulting firm with extensive expertise in environmental assessment, geochemistry, material characterization, mine residue management and regulatory compliance. Its specialists have supported projects involving complex mineral-processing residues, environmental monitoring and long-term management of mining materials. At Kwyjibo, Arcadis’ expertise is being applied to evaluate the characteristics and long-term behaviour of process residues, assess their proposed return underground as cemented paste backfill, and support the environmental and regulatory studies required as the Project advances toward feasibility and permitting. This work is an important component of Nordique’s strategy to develop Kwyjibo with a reduced surface footprint and no permanent surface tailings storage.

About Nordique Critical Metals Inc.

Nordique Critical Metals Inc. is a Canadian junior mining exploration and development company trading under the symbol “NQC” on the TSX Venture Exchange, “J6K” on the Frankfurt Stock Exchange and “JORFF” on the OTCQB^® Venture Market. The Company is focused on the exploration and development of critical mineral projects in stable jurisdictions and is committed to advancing critical mineral supply chains through responsible project development.

Contact

Nordique Critical Metals Inc.
Richard Quesnel | Chief Executive Officer
+1 (514) 249-6320 | info@nordiquecriticalmetals.com | nordiquecriticalmetals.com

Additional Cautionary Statements

This press release contains “forward-looking information” within the meaning of applicable Canadian securities laws. Forward-looking information includes, but is not limited to, statements with respect to: the plans, intentions, beliefs and current expectations of the Company with respect to Kwyjibo with a view to the information contained in the Updated PEA and the Company’s future business activities and operating performance in respect thereof. Forward-looking information is often identified by the words “may”, “would”, “could”, “should”, “will”, “intend”, “plan”, “anticipate”, “believe”, “estimate”, “expect” or similar expressions and includes information regarding the Company’s estimates, expectations, forecasts and guidance for production, waste material, capital expenditures, cost savings, project economics (including pre-tax IRR) and other information contained in the Updated PEA; as well as references to other possible events, the future price of rare earth oxides, the estimation of mineral reserves and mineral resources, the realization of mineral reserve and mineral resource estimates, the timing and amount of estimated future production, costs of production, capital expenditures, costs and timing of the development of the project and mining and processing activities, requirements for additional capital, government regulation of mining operations, environmental risks and the anticipated timing for the filing of the Updated PEA in accordance with NI 43-101.

Investors are cautioned that forward-looking information is not based on historical facts but instead reflects management’s expectations, estimates or projections concerning future results or events based on the opinions, assumptions and estimates of management considered reasonable at the date the statements are made. Although the Company believes that the expectations reflected in such forward-looking information are reasonable, such information involves risks and uncertainties, and undue reliance should not be placed on such information, as unknown or unpredictable factors could have material adverse effects on future results, performance or achievements of the Company.

This forward-looking information may be affected by risks and uncertainties in the combined business of the Company and market conditions, including (1) there being no significant disruptions affecting the Company’s operations whether due to extreme weather events and other or related natural disasters, labor disruptions, supply disruptions, power disruptions, damage to equipment or otherwise; (2) permitting, development, operations and production for the Kwyjibo being consistent with the Company’s expectations; (3) political and legal developments in Québec being consistent with current expectations; (4) certain price assumptions for rare earth oxides; (5) prices for diesel, electricity and other key supplies being approximately consistent with current levels; (6) the accuracy of the MRE; (7) labor and materials costs increasing on a basis consistent with the Company’s current expectations; and (8) environmental approvals and community engagement. This information is qualified in its entirety by cautionary statements and risk factor disclosure contained in filings made by the Company with the Canadian securities regulators, including the Company’s annual and interim financial statements and related MD&A, filed with the securities regulatory authorities in certain provinces of Canada and available at www.sedarplus.ca.

Should one or more of these risks or uncertainties materialize, or should assumptions underlying the forward-looking information prove incorrect, actual results may vary materially from those described herein as intended, planned, anticipated, believed, estimated or expected. Although the Company has attempted to identify important risks, uncertainties and factors which could cause actual results to differ materially, there may be others that cause results not to be as anticipated, estimated or intended. The Company does not intend, and does not assume any obligation, to update this forward-looking information except as otherwise required by applicable law.

The Company has included certain non-GAAP financial measures in this press release, such as AISC. These non-GAAP financial measures do not have any standardized meaning. Accordingly, these financial measures are intended to provide additional information and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with International Financial Reporting Standards (“IFRS”). AISC, as defined by the World Gold Council, is a common financial performance measure in the mining industry but has no standard definition under IFRS. AISC includes operating cash costs, net-smelter royalty, corporate costs, sustaining capital expenditure, sustaining exploration expenditure and capitalised stripping costs. Other companies may calculate these measures differently and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS.

NEITHER TSX VENTURE EXCHANGE NOR ITS REGULATION SERVICES PROVIDER (AS THAT TERM IS DEFINED IN THE POLICIES OF THE TSX VENTURE EXCHANGE) ACCEPTS RESPONSIBILITY FOR THE ADEQUACY OR ACCURACY OF THIS RELEASE.

TORONTO, Nov. 12, 2026 (GLOBE NEWSWIRE) — Northland Power Inc. (“Northland” or the “Company”) (TSX: NPI) today reported financial results for the three and nine months ended September 30, 2026. All dollar amounts set out herein are in Canadian dollars, unless otherwise stated.

Highlights

• Increased Adjusted EBITDA by 9% year-over-year, driven by new contributions from the Hai Long (1.0 GW) and Baltic Power (1.1 GW) offshore wind projects.
• Demonstrated Northland’s execution excellence by achieving commercial operations ahead of schedule and under budget on the Jurassic (80 MW / 160 MWh) Battery Energy Storage System (BESS) project in Alberta.
• Achieved full turbine installation at Hai Long, with all 73 turbines installed and now generating power, and secured incremental debt funding to support the project.
• Reached a major milestone at Baltic Power by completing the installation of all 76 turbines, over 70% generating power and the project advancing through commissioning.
• Continued construction of the Kamionka (100 MW / 400 MWh) and Mieczysławów (200 MW / 800 MWh) BESS projects in Poland and secured project financing.
• Advanced approximately 900 MW of value accretive near-term development opportunities across core markets, with planned delivery by 2030.
• Achieved 93% commercial availability, with year-to-date electricity production in line with historical averages.
• Management reaffirmed its 2026 full-year guidance.

“This quarter marks an important phase for Northland as our major offshore wind projects begin to transition from construction into operations and generating cash flow. At the Baltic Power and Hai Long offshore wind projects we have installed all turbines, with all of Hai Long’s turbines now generating power. We continued to deliver on our commitments by completing the Jurassic BESS project ahead of schedule and under budget.” said Christine Healy, President and CEO of Northland. “I am proud of our team’s continued excellence and disciplined execution. Our differentiated track record of execution, coupled with growing near-term development pipeline, position’s Northland to meet growing electricity demand across our core markets.”

Significant Events and Updates

Americas:

Jurassic BESS Project – Northland completed construction of the 80 MW / 160 MWh Jurassic BESS project in Alberta, Canada, ahead of schedule and under budget. The project has moved into commercial operations.

Midnight Alberta BESS Project – Northland converted an existing Alberta solar development project into a 200 MW / 800 MWh standalone battery project, driven by emerging storage market opportunity.

Canadian Renewable Pipeline Additions – Northland expanded its Canadian pipeline with the addition of approximately 350 MW of mid-stage development projects in Atlantic Canada and 250 MW of opportunities in central Canada.

International:

Baltic Power Offshore Wind Project – Northland continued to advance construction of the 1.1 GW Baltic Power project in Poland, with all 76 turbines installed and over 70% generating power. The project is advancing through commissioning in the fourth quarter of 2026. The project remains on track with costs aligned with original expectations.

Polish BESS Projects – Northland continued construction on its two BESS projects in Poland, totaling 300 MW / 1.2 GWh, and secured debt financing of approximately PLN 500 million (CAD 185 million) for both projects. The projects are on track with Project Kamionka’s (100 MW / 400 MWh) commercial operations expected in early 2028, and Project Mieczysławów’s (200 MW / 800 MWh) commercial operations expected in mid-2028.

Hai Long Offshore Wind Project – Northland continued to advance construction of the 1.0 GW Hai Long project in Taiwan, with all 73 turbines installed and generating power. The project remains on track, with final permitting approvals expected in the first half of 2027 and overall costs aligned with original expectations.

Gemini Co-located BESS Project – Northland advanced plans to co-locate an approximately 100 MW / 400 MWh hybridized BESS project on land occupied by the Gemini onshore substation in Eemshaven, Netherlands. The project is expected to enhance the value of Gemini’s existing offshore wind facility by reducing balancing costs and enabling participation in energy and ancillary services markets. The project is working towards a final investment decision in 2027.

Spain Co-located BESS Projects – Northland is advancing multiple opportunities, totaling approximately 250 MW / 1,000 MWh hybridized BESS projects across its existing wind and solar portfolio in Spain. The opportunities leverage Northland’s established operating platform and infrastructure across multiple sites. The projects are working towards final investment decisions in 2027.

Other Updates:

Executive Changes – In September 2026, Northland appointed Lyla Garzouzi as Executive Vice-President, Health, Safety, Security & Environment (HSSE) and Strategy Execution, strengthening the Company’s leadership team and supporting the execution of Northland’s strategy, operational initiatives, and safety culture. Chief Legal Officer, Jaime Hurtado, departed the Company to pursue another opportunity.

Financial Results for the Third Quarter

The financial results for the third quarter of 2026 were as follows:

• Revenue from energy sales of $565 million in the third quarter of 2026 is largely in line with $558 million in the corresponding quarter of 2025.
• Net income of $201 million in the third quarter of 2026 increased from a net loss of $456 million in the corresponding quarter of 2025.
• Adjusted EBITDA (a non-IFRS measure) increased to $280 million in the third quarter of 2026 compared to $257 million in the corresponding quarter of 2025.
• Free Cash Flow per share (a non-IFRS measure) decreased to $0.06 in the third quarter of 2026 compared to $0.17 in the corresponding quarter of 2025.
• Cash provided by operating activities increased to $382 million in the third quarter of 2026 compared to $325 million in the corresponding quarter of 2025.

Summary of Consolidated Results
(in thousands of dollars, except per share amounts)			Three months ended  September 30,							Nine months ended  September 30,
			2026			2025				2026			2025
FINANCIALS
	Revenue from energy sales(1)	$	564,635		$	557,597			$	1,849,074		$	1,735,116
	Operating income (loss)(1)		140,645			(393,169	)			596,143			11,862
	Net income (loss)(1)		201,089			(455,842	)			308,082			(398,174	)
	Net income (loss) attributable to shareholders of Northland		188,653			(412,672	)			215,433			(408,584	)
	Adjusted EBITDA (a non-IFRS measure)(2)		279,583			256,959				965,861			863,469
	Cash provided by operating activities(1)		381,503			325,102				1,122,767			1,198,987
	Free Cash Flow (a non-IFRS measure)(2)		15,100			44,978				219,704			260,696
	Cash dividends paid		47,070			78,451				141,211			207,557
	Total dividends declared(3)	$	47,070		$	78,451			$	141,211		$	235,195
Per Share
	Weighted average number of shares — basic and diluted (000s)		261,502			261,502				261,502			261,234
	Net income (loss) attributable to common shareholders — basic and diluted	$	0.71		$	(1.58	)		$	0.80		$	(1.58	)
	Free Cash Flow (a non-IFRS measure)(2)	$	0.06		$	0.17			$	0.84		$	1.00
	Total dividends declared	$	0.18		$	0.30			$	0.54		$	0.90
ENERGY VOLUMES
	Electricity production (GWh)(4)		2,495			2,373				7,938			7,481
	Northland’s share of electricity production (GWh)(5)		2,243			2,062				6,957			6,529
(1) Represents fully consolidated financial information on a 100% basis for all direct and indirect subsidiaries, including those partially owned by Northland. The share of profit (loss) from joint ventures has been included only in the net income measures, as required by IFRS.
(2) See Forward-Looking Statements and Non-IFRS Financial Measures below.
(3) Represents total dividends declared to common shareholders, including dividends paid in cash or in shares under Northland’s Dividend Reinvestment Plan.
(4) Represents 100% of electricity produced by Northland’s direct and indirect subsidiaries, including those partially owned by Northland, and Northland’s pro rata share of Hai Long’s and Baltic Power’s pre-completion production.
(5) Presented at Northland’s economic interest of electricity production from all direct and indirect subsidiaries, including those which are partially owned, as well as Northland’s share of pre-completion production from Hai Long and Baltic Power.

Third Quarter Highlights

International Business Unit

Northland’s international business unit comprises a portfolio of two offshore wind facilities in Germany, one offshore wind facility in the Netherlands, and a portfolio of onshore renewable (solar and wind) projects in Spain. The business unit has projects under construction, including the Hai Long offshore wind joint venture in Taiwan, the Baltic Power offshore wind joint venture, and the Kamionka and Mieczysławów BESS projects in Poland.

Offshore wind facilities

Electricity production for the three months ended September 30, 2026 decreased 14% or 120 GWh compared to the same quarter of 2025, due to lower production from Gemini and lower wind resource, across offshore wind projects.

Commercial availability for the three months ended September 30, 2026 was 92%, due to downtime at Gemini caused by an export cable failure.

Revenue from energy sales of $210 million for the three months ended September 30, 2026 decreased 17% or $43 million, compared to the same quarter of 2025, due to lower production.

Adjusted EBITDA of $94 million for the three months ended September 30, 2026 decreased 25% or $32 million compared to the same quarter of 2025, due to lower revenue, as noted above.

In September 2026, the Gemini offshore wind project’s export cable was successfully repaired and energized, bringing the project back to full operations. This outage is expected to have a minimal impact on Northland’s full-year results, net of insurance proceeds, which are anticipated to be received by the end of the year.

Onshore renewable facilities

Electricity production for the three months ended September 30, 2026 of 173 GWh was 11% or 20 GWh lower compared to the same quarter of 2025, due to lower wind and solar resources at the Spanish facilities.

Commercial availability for the three months ended September 30, 2026 was 97%.

Revenue from energy sales of $43 million for the three months ended September 30, 2026 decreased 13% or $6 million compared to the same quarter of 2025, due to lower production.

Adjusted EBITDA of $29 million for the three months ended September 30, 2026 decreased 14% or $5 million compared to the same quarter of 2025, due to lower revenue, as noted above.

Americas Business Unit

Northland’s Americas business unit comprises a portfolio of energy assets in Canada and the United States, including natural gas, onshore wind, solar, and energy storage facilities. In addition, the business unit operates regulated utility services in Colombia.

Onshore renewable & energy storage facilities

Electricity production for the three months ended September 30, 2026, was 350 GWh, up 10% or 32 GWh, compared to the same quarter of 2025, due to a higher wind resource.

Commercial availability for the three months ended September 30, 2026 was 97%.

Revenue from energy sales of $83 million for the three months ended September 30, 2026 was in line with the same quarter of 2025.

Adjusted EBITDA of $52 million for the three months ended September 30, 2026 was in line with the same quarter of 2025.

Natural gas facilities

Electricity production of 986 GWh for the three months ended September 30, 2026 was in line with the same quarter of 2025.

Commercial availability for the three months ended September 30, 2026 was 95%.

Revenue from energy sales of $93 million for the three months ended September 30, 2026 increased 14% or $11 million compared to the same quarter of 2025, due to higher gas prices.

Adjusted EBITDA of $46 million for the three months ended September 30, 2026 was in line with the same quarter of 2025.

Utility

Revenue from energy sales of $130 million for the three months ended September 30, 2026 increased 44% or $40 million compared to the same quarter of 2025, due to exchange rate movement and growth in the asset base.

Adjusted EBITDA of $56 million for the three months ended September 30, 2026 increased 39% or $16 million compared to the same quarter of 2025, due to the factors noted above.

Consolidated statements of income (loss)

Share of profit from joint ventures of $148 million was due to a gain on fair value of derivative financial instruments and pre-completion revenues from Hai Long and Baltic Power.

Finance costs of $89 million decreased $3 million compared to the same quarter of 2025, due to scheduled principal repayments on facility-level loans.

General and administrative (“G&A”) costs of $29 million were in line with the same quarter of 2025.

Development costs of $16 million were in line with the same quarter of 2025.

Foreign exchange gain of $9 million was due to fluctuations in foreign exchange rates.

Fair value loss on financial instruments was $6 million, due to net movement in the fair value of derivative financial instruments related to foreign exchange and interest rate hedge contracts.

Net income of $201 million in the third quarter of 2026 compared to a net loss of $456 million in the same period of 2025, primarily due a non-cash impairment expense of $527 million recorded during the third quarter of 2025.

Adjusted EBITDA

The following table reconciles net income (loss) to Adjusted EBITDA:

		Three months ended September 30,								Nine months ended September 30,
		2026				2025				2026				2025
Net income (loss)	$	201,089			$	(455,842	)		$	308,082			$	(398,174	)
Adjustments:
Finance costs, net		73,057				77,600				223,718				230,876
Provision for (recovery of) income taxes		50,888				(116,839	)			136,989				(126,653	)
Depreciation of property, plant and equipment		146,106				169,382				465,396				492,717
Amortization of contracts and intangible assets		11,572				16,227				42,938				46,725
Fair value (gain) loss on financial instruments		6,041				140,153				156,267				447,943
Foreign exchange (gain) loss		(8,772	)			(19,607	)			(29,096	)			(63,868	)
Impairment of non-financial assets		—				526,525				23,077				526,525
Elimination of non-controlling interests		(43,496	)			(58,243	)			(198,861	)			(192,549	)
Share of (profit) loss from joint ventures		(147,544	)			(22,329	)			(165,992	)			(75,368	)
Others(1)		(9,358	)			(68	)			3,343				(24,705	)
Adjusted EBITDA(2)	$	279,583			$	256,959			$	965,861			$	863,469
(1) “Others” includes Northland’s proportion of Adjusted EBITDA from equity-accounted investees, Gemini interest income, finance lease income, and other expenses (income).
(2) See Forward-Looking Statements and Non-IFRS Financial measures below.

Adjusted EBITDA of $280 million for the three months ended September 30, 2026 increased 9% or $23 million compared to the same quarter of 2025. The factors increasing Adjusted EBITDA include:

• $35 million due to the contribution from Hai Long and Baltic Power projects; and
• $20 million due to operating results from EBSA and natural gas facilities.

The factor partially offsetting the increase in Adjusted EBITDA was:

• $32 million in lower operating results from offshore wind facilities.

Free Cash Flow

The following table reconciles cash flow from operations to Free Cash Flow:

		Three months ended  September 30,								Nine months ended  September 30,
		2026				2025				2026				2025
Cash provided by operating activities	$	381,503			$	325,102			$	1,122,767			$	1,198,987
Adjustments:
Net change in non-cash working capital balances related to operations		(108,427	)			(24,779	)			(99,105	)			(179,311	)
Non-expansionary capital expenditures		(1,661	)			(362	)			(4,156	)			(1,254	)
Restricted funding for major maintenance, debt and decommissioning reserves		—				(100	)			(7,827	)			13,719
Interest		(66,885	)			(66,301	)			(198,616	)			(203,525	)
Scheduled principal repayments on facility debt		(37,583	)			(40,830	)			(450,596	)			(518,832	)
Funds set aside (utilized) for scheduled principal repayments		(168,190	)			(157,614	)			(136,484	)			(60,934	)
Preferred share dividends		(2,104	)			(1,377	)			(6,287	)			(4,197	)
Consolidation of non-controlling interests		6,440				(10,081	)			(60,189	)			(60,813	)
Growth expenditures		14,291				17,069				42,221				45,686
Others(1)		(2,284	)			4,251				17,976				31,170
Free Cash Flow(2)	$	15,100			$	44,978			$	219,704			$	260,696
(1) “Others” includes the effect of foreign exchange rates and hedges, interest rate hedges, Nordsee One interest on shareholder loans, acquisition costs, lease payments, interest income, Northland’s portion of Free Cash Flow from joint ventures, investment income, and other non-cash expenses adjusted in working capital excluded from Free Cash Flow in the period.
(2) See Forward-Looking Statements and Non-IFRS Financial Measures below.

The following table reconciles Adjusted EBITDA to Free Cash Flow:

		Three months ended September 30,								Nine months ended  September 30,
		2026				2025				2026				2025
Adjusted EBITDA(2)	$	279,583			$	256,959			$	965,861			$	863,469
Adjustments:
Scheduled debt repayments		(161,493	)			(157,988	)			(470,965	)			(468,010	)
Interest expense		(54,516	)			(46,545	)			(148,094	)			(150,740	)
Current taxes		(25,307	)			(22,088	)			(101,991	)			(60,649	)
Non-expansionary capital expenditure		(904	)			(362	)			(3,076	)			(965	)
Utilization (funding) of maintenance and decommissioning reserves		—				(100	)			(6,862	)			10,686
Lease payments, including principal and interest		(1,429	)			(3,137	)			(8,294	)			(9,863	)
Preferred dividends		(2,104	)			(1,377	)			(6,287	)			(4,197	)
Foreign exchange hedge gain (loss)		5,489				(7,243	)			33,235				11,079
Growth expenditures		14,291				17,069				42,221				45,686
Net pre-completion revenue from the joint ventures(3)		(34,756	)			—				(62,335	)			—
Others(1)		(3,754	)			9,790				(13,709	)			24,200
Free Cash Flow(2)	$	15,100			$	44,978			$	219,704			$	260,696
(1) Others include repayment of Gemini subordinated debt and interest rate and foreign currency hedge settlements.
(2) See Forward-Looking Statements and Non-IFRS Financial measures below.
(3) Represents Northland’s pro rata share of the net pre-completion revenues from Hai Long and Baltic Power.

Free Cash Flow of $15 million for the three months ended September 30, 2026 was 66% or $30 million lower compared to the same quarter of 2025.

The factors decreasing Free Cash Flow include:

• $15 million lower Adjusted EBITDA (net of contribution from Hai Long’s and Baltic Power’s net pre-completion revenue of $35 million and gross of growth expenditures), as noted above;
• $8 million relating to net finance costs, scheduled repayments of facility-level debt; and
• $6 million from current taxes and hedge settlements.

Outlook

Management maintains the Company’s 2026 financial outlook with Adjusted EBITDA expected in the range of $1.45 billion to $1.65 billion and Free Cash Flow per share expected in the range of $1.05 to $1.25.

The information in this Outlook constitutes forward-looking information within the meaning of applicable Canadian securities laws, is based on several assumptions and is subject to risks and uncertainties. See Forward-Looking Statements in this document as well as the Risk Factors in the 2025 AIF.

Third-Quarter Earnings Conference Call

Northland’s management will hold an earnings conference call and webcast at 9 a.m. Eastern Time (ET) on Friday November 13, 2026, to discuss the Company’s financial results, provide an update on growth and developments, and answer questions from analysts.

Participants wishing to join the call and ask questions must register using the following URL below:

https://register-conf.media-server.com/register

For all other attendees, the call will be broadcast live on the internet, in listen-only mode and can be accessed using the following link:

Webcast URL: https://edge.media-server.com/mmc

For those unable to attend the live call, an audio recording will be available on northlandpower.com starting on Monday, November 16, 2026.

Northland’s unaudited interim condensed consolidated financial statements for the nine months ended September 30, 2026, and related MD&A can be found on SEDAR+ at www.sedarplus.ca under Northland’s profile and on northlandpower.com.

ABOUT NORTHLAND POWER

Northland Power is a Canadian-headquartered global power producer delivering the electricity the world needs through offshore wind, onshore renewables, battery storage, and natural gas-fired generation. With offices in seven countries, Northland owns or has an economic interest in 3.6 GW of gross operating generating capacity, 2.4 GW under construction, and an approximately 7.4 GW development pipeline, reflecting nearly four decades of experience delivering large-scale energy infrastructure.

Publicly traded since 1997, Northland’s Common Shares, and Series 1 and Series 2 Preferred Shares trade on the Toronto Stock Exchange under the symbols NPI, NPI.PR.A and NPI.PR.B, respectively.

NON-IFRS FINANCIAL MEASURES

This news release includes references to the Company’s adjusted earnings before interest, income taxes, depreciation and amortization (“Adjusted EBITDA”), Free Cash Flow and applicable payout ratios and per share amounts, which are measures not prescribed by International Financial Reporting Standards (“IFRS”), and therefore do not have any standardized meaning under IFRS and may not be comparable to similar measures presented by other companies. Non-IFRS financial measures are presented at Northland’s share of underlying operations.

These measures should not be considered alternatives to net income (loss), cash flow from operating activities or other measures of financial performance calculated in accordance with IFRS. Instead, these measures are provided to complement IFRS measures in the analysis of Northland’s results of operations from management’s perspective. Management believes that Northland’s non-IFRS financial measures and applicable payout ratios and per share amounts are widely accepted and understood financial indicators used by investors and securities analysts to assess the performance of a company, including its ability to generate cash through operations.

FORWARD-LOOKING STATEMENTS

This news release contains statements that constitute forward-looking information within the meaning of applicable securities laws (“forward-looking statements”) that are provided for the purpose of presenting information about management’s current expectations and plans. Readers are cautioned that such statements may not be appropriate for other purposes.

Northland’s actual results could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, the events anticipated by the forward-looking statements may or may not transpire or occur. Forward-looking statements include statements that are predictive in nature, depend upon or refer to future events or conditions, or include words such as “anticipates,” “expects,” “believes,” “plans,” “targets,” “continues,” “on track,” “outlook,” or negative versions thereof and other similar expressions or future or conditional verbs such as “may,” “will,” and “could”.

These statements may include, without limitation, statements regarding Northland’s 2026 financial outlook, including expected Adjusted EBITDA and Free Cash Flow per share; Northland’s expectations for the timing of commercial operations, final permitting and cost expectations for the Baltic Power and Hai Long offshore wind projects and the Kamionka and Mieczysławów BESS projects; the expected benefits and targeted final investment decisions for the contribution of Gemini and Spain co-located BESS projects; the expected transition of Northland’s offshore wind projects into operations and their generation of cash flow; the expected timing and amount of insurance proceeds and the impact of the Gemini export cable failure on Northland’s full-year results; potential opportunities to expand Northland’s Canadian pipeline and upcoming power procurements; and the size of Northland’s development pipeline and its ability to meet growing electricity demand in Northland’s core markets, all of which may differ from the expectations stated herein.

These statements are based upon certain material factors or assumptions that were applied in developing the forward-looking statements, including the design specifications of development projects, the provisions of contracts to which Northland or a subsidiary or joint venture is a party, management’s current plans and its perception of historical trends, current conditions and expected future developments, the ability to obtain necessary approvals, satisfy any closing conditions, satisfy any project finance lender conditions to closing sell-downs or obtain adequate financing regarding contemplated construction, acquisitions, dispositions, investments or financings, as well as other factors, estimates, and assumptions that are believed to be appropriate in the circumstances.

Although these forward-looking statements are based upon management’s current reasonable expectations and assumptions, they are subject to numerous risks and uncertainties. Some of the factors that could cause results or events to differ from current expectations include, but are not limited to, those risks associated with further regulatory and policy changes which could impair current guidance and expected returns, risks associated with merchant pool pricing and revenues, risks associated with sales contracts, the emergence of widespread health emergencies or pandemics, Northland’s reliance on the performance of its offshore wind facilities at Gemini, Nordsee One and Deutsche Bucht for over 50% of its Adjusted EBITDA, counterparty and joint venture risks, contractual operating performance, variability of sales from generating facilities powered by intermittent renewable resources, wind and solar resource risk, unplanned outage or maintenance risk, offshore wind concentration, natural gas and power market risks, commodity price risks, operational risks, recovery of utility operating costs, Northland’s ability to resolve issues/delays with the relevant regulatory and/or government authorities, permitting, construction risks, project development risks, integration and acquisition risks, procurement and supply chain risks, financing risks, disposition and joint-venture risks, competition risks, interest rate and refinancing risks, liquidity risk, inflation risks, commodity availability and cost risk, construction material cost risks, impacts of regional or global conflicts, credit rating risk, currency fluctuation risk, variability of cash flow and potential impact on dividends, taxation, natural events, environmental risks, climate change, health and worker safety risks, including investigations related thereto, market compliance risk, government regulations and policy risks, utility rate regulation risks, international activities, cybersecurity, data protection and reliance on information technology, labor relations, labor shortage risk, management transition risk, geopolitical risk in and around the regions Northland operates in, large project risk, reputational risk, insurance risk, risks relating to co-ownership, bribery and corruption risk, terrorism and security, litigation risk and legal contingencies, and the other factors described in Northland’s Management’s Discussion and Analysis and Annual Information Form for the year ended December 31, 2025, which can be found at www.sedarplus.ca under Northland’s profile and on Northland’s website at northlandpower.com.

Northland has attempted to identify important factors that could cause actual results to materially differ from current expectations; however, there may be other factors that cause actual results to differ materially from such expectations. Northland’s actual results could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur, and Northland cautions you not to place undue reliance upon any such forward-looking statements.

The forward-looking statements contained in this release are, unless otherwise indicated, stated as of the date hereof and are based on assumptions that were considered reasonable as of the date hereof. Other than as specifically required by law, Northland undertakes no obligation to update any forward-looking statements to reflect events or circumstances after such date or to reflect the occurrence of unanticipated events, whether as a result of new information, future events or results, or otherwise.

Certain forward-looking information in this release and the MD&A may also constitute a “financial outlook” within the meaning of applicable securities laws. Financial outlook involves statements about Northland’s prospective financial performance, financial position or cash flows and is based on and subject to the assumptions about future economic conditions and courses of action and the risk factors described above in respect of forward-looking information generally, as well as any other specific assumptions and risk factors in relation to such financial outlook noted in this release and the MD&A. Such assumptions are based on management’s assessment of the relevant information currently available and any financial outlook included in this release and the MD&A is provided for the purpose of helping readers understand Northland’s current expectations and plans. Readers are cautioned that reliance on any financial outlook may not be appropriate for other purposes or in other circumstances and that the risk factors described above or other factors may cause actual results to differ materially from any financial outlook. The actual results of Northland’s operations will likely vary from the amounts set forth in any financial outlook and such variances may be material.

For further information, please contact:

Alison Holditch, Investor Relations
416-989-8734
investorrelations@northlandpower.com
northlandpower.com

VANCOUVER, British Columbia, Nov. 12, 2026 (GLOBE NEWSWIRE) — Tiago Sampaio Cunha is the interim CEO, President and director of South Star Battery Metals Corp. (the “Company”) whose head office is located at Suite 1507 – 1030 West Georgia St., Vancouver, British Columbia, V6E 2Y3, Canada. Mr. Cunha, together with his affiliates (the “Cunha Group”), holds common shares of the Company (the “Shares”) directly and indirectly, including through the following funds directed and controlled by Mr. Cunha: GROU SPO FUNDO DE INVESTIMENTO EM ACOES INVESTIMENTO NO EXTERIOR (“SPO”), GROU PROVENCE FUNDO DE INVESTIMENTO EM ACOES INVESTIMENTO NO EXTERIOR (“Provence”), and GROU ABSOLUTO 30.

On November 12, 2026, Mr. Cunha, through SPO and Provence, exercised an aggregate of 11,722,333 common share purchase warrants at an exercise price of C$0.20 per Share for aggregate consideration of C$2,344,466.60 (the “Transaction”), acquiring 11,722,333 Shares.

Immediately before the Transaction, Mr. Cunha, including securities held through the Cunha Group, held 39,278,419 Shares and 21,111,933 common share purchase warrants, representing 27.68% of the issued and outstanding Shares on a non-diluted basis and 37.04% on a partially diluted basis. Immediately following the Transaction, Mr. Cunha’s direct and indirect holdings totalled 51,000,752 Shares and 9,389,600 common share purchase warrants, representing 33.19% of the issued and outstanding Shares on a non-diluted basis and 37.04% on a partially diluted basis.

Mr. Cunha may acquire additional securities or dispose of securities of the Company in the future either on the open market, privately or otherwise, depending on market conditions, reformulation of plans, other available investment business opportunities and/or other relevant factors.

The address of Mr. Cunha is c/o Suite 1507 – 1030 West Georgia St., Vancouver, British Columbia, V6E 2Y3, Canada.

A copy of the Early Warning Report will be available under the Company’s profile at www.sedarplus.ca, or may be obtained by contacting Judson Culter at jculter@invictusaccounting.com or 604-343-3889.

VANCOUVER, British Columbia, Nov. 12, 2026 (GLOBE NEWSWIRE) — Madison Pacific Properties Inc. (the Company) (TSX: MPC and MPC.C), a Vancouver-based real estate company announces the results of operations for the nine months ended September 30, 2026.

The results reported are pursuant to International Financial Reporting Standards (IFRS) for public companies.

For the nine months ended September 30, 2026, the Company is reporting a net income of $17.2 million (nine months ended September 30, 2025: $20.9 million); cash flows generated from operating activities before changes in non-cash operating balances of $8.6 million (nine months ended September 30, 2025: $8.0 million); and income per share of $0.27 (nine months ended September 30, 2025: $0.27). Net income includes a net gain on the fair value adjustment on investment properties of $3.3 million (nine months ended September 30, 2025: $18.6 million), an interest recovery on tax appeals of $6.1 million (nine months ended September 30, 2025 – $nil), and a gain on fair value adjustment on interest rate swaps of $2.9 million (nine months ended September 30, 2025: losses of $1.1 million).

As at September 30, 2026, the Company owns approximately $789 million in investment properties (December 31, 2025: $768 million).

As at the date of this Press Release, the Company’s investment portfolio comprises 54 properties with approximately 2.0 million rentable sq. ft. of industrial and commercial space and a 50% interest in ten multi-family rental properties with a total of 321 units. Approximately 98.61% of available space within the industrial and commercial investment properties is currently leased and within the multi-family residential properties, 97.81% of available units are currently leased. The Company’s development properties include a 50% interest in the Silverdale Hills Limited Partnership (the “SHLP”) which currently owns approximately 1,410 acres of primarily residential designated development lands in Mission, British Columbia. The SHLP is currently constructing the first phase of a 163-unit townhome development and a 121 single family lot development on the site.

For a review of the risks and uncertainties to which the Company is subject, see its most recently filed annual and interim MD&A.

Contact:	Mr. Dino Di Marco		Ms. Bernice Yip
	President & CEO		Chief Financial Officer
Telephone:	(604) 732-6540		(604) 732-6540
Address:	389 West 6th Avenue
	Vancouver, B.C. V5Y 1L1

DENVER, Nov. 12, 2026 (GLOBE NEWSWIRE) — Intermap Technologies (TSX: IMP; OTCQB: ITMSF) (“Intermap” or the “Company”), a global leader in geospatial intelligence powered by proprietary 3D data, rapid image processing software and AI-driven analytics, today announced that it will release its third quarter 2026 financial results after market close on November 16, 2026. Intermap’s CEO Patrick A. Blott and CFO Jennifer Bakken will host a live webcast the same day at 5:00 pm ET to review the Company’s financial results and answer investor questions following the presentation.

Intermap welcomes shareholders, analysts, investors, media representatives and other stakeholders to attend the webcast to discuss third quarter 2026 results.

Conference Call Details
DATE	November 16, 2026
TIME	5:00 pm ET
WEBCAST	Register

A replay of the webcast and supporting materials will be posted on the investor relations page of the Company’s website following the event.

Intermap Reader Advisory 
Certain information provided in this news release, including statements regarding the anticipated timing of the Company’s third quarter 2026 financial results and related webcast, constitutes forward-looking information. The words “anticipate”, “expect”, “project”, “estimate”, “forecast”, “will be”, “will consider”, “intends” and similar expressions are intended to identify such forward-looking statements. Although Intermap believes that these statements are based on information and assumptions which are current, reasonable and complete, these statements are necessarily subject to a variety of known and unknown risks and uncertainties. Intermap’s forward-looking statements are subject to risks and uncertainties pertaining to, among other things, cash available to fund operations, availability of capital, revenue fluctuations, nature of government contracts, economic conditions, loss of key customers, retention and availability of executive talent, competing technologies, common share price volatility, loss of proprietary information, software functionality, internet and system infrastructure functionality, information technology security, breakdown of strategic alliances, and international and political considerations, as well as those risks and uncertainties discussed in Intermap’s Annual Information Form and other securities filings. While the Company makes these forward-looking statements in good faith, should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results may vary significantly from those expected. Accordingly, no assurances can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that the Company will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to Intermap or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements contained in this news release are made as at the date of this news release and the Company does not undertake any obligation to update publicly or to revise any of the forward-looking statements made herein, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law.

About Intermap Technologies 
Intermap Technologies is a global leader in geospatial intelligence powered by proprietary 3D data and AI-driven analytics. The Company delivers actionable intelligence to government and commercial customers through a portfolio of applications, platforms and solutions that support risk management, infrastructure planning, operational readiness and mission-critical decision-making. Intermap’s proprietary 3D data foundation spans more than 300 million square kilometers across over 150 countries and powers intelligence solutions for government, insurance, aviation, telecommunications, transportation, renewable energy, agriculture, natural resources and space markets. Through advanced analytics, automated processing and enterprise-scale data delivery, Intermap helps organizations transform complex geospatial information into decision-ready intelligence.

For more information, please visit www.intermap.com or contact:
Jennifer Bakken
Executive Vice President and CFO
CFO@intermap.com
+1 (303) 708-0955

Sean Peasgood
Investor Relations
Sean@SophicCapital.com
+1 (647) 260-9266

• .HEAL-101 achieved up to 70% in vivo APOC3 editing with liver-restricted activity and confirmed 76% triglyceride reduction in murine models (ESGCT 2026); Phase 1 IIT in China on track for initiation, with preliminary clinical data expected in H2 2027
   
• .HEAL-201 achieved >90% reduction in plasma PCSK9 in a humanized liver mouse model; preliminary clinical data expected in H1 2028
   
• Cash, cash equivalents and fixed-term deposits of $149 million as of September 30, 2026¹; realignment of the operating model targeting cash runway into H2 2028
   
• Conference call scheduled for November 13 at 8 a.m. ET / 2 p.m. CET

NEW YORK, Nov. 12, 2026 (GLOBE NEWSWIRE) — Cellectis (Euronext Growth: ALCLS – Nasdaq: CLLS), a genome engineering company developing genetic medicines for diseases that today demand a lifetime of treatment, today reported financial results for the third quarter 2026 ended September 30, 2026, and provided a business update.

« Since September, our teams have been fully committed to our new in vivo gene editing chapter, and the expanded preclinical data we presented at ESGCT for .HEAL-101 reinforce our conviction » said André Choulika, Ph.D., Co-founder and Chief Executive Officer of Cellectis. « After a single administration, .HEAL-101 edited the human APOC3 gene at rates of up to 70% in a humanized liver model, with editing restricted to the liver, and consistently reduced triglycerides by 76% in a disease model. These results support the continued development of .HEAL-101, and the initiation of an investigator-initiated trial in China is on track with the goal of delivering first clinical data for .HEAL-101 in the second half of 2027. »

___________________________________
¹ As of September 30, 2026, cash, cash equivalents and fixed-term deposits include restricted cash of $2.3 million, classified as current and non-current financial assets, and fixed-term deposits of $118.3 million, classified as current financial assets.

In Vivo Gene Editing Pipeline

.HEAL-101 – In vivo base editing of APOC3 for severe hypertriglyceridemia (sHTG)

Expanded preclinical data presented in a poster at the European Society of Gene and Cell Therapy (ESGCT) 2026 Congress support the potential of .HEAL-101 to achieve efficient and specific APOC3 editing after a single administration:

• In vitro: ~90% mean APOC3 editing in a human hepatic cell line, with no DNA double-strand breaks at the target site.
   
• In vivo: in a normolipidemic humanized liver mouse model, a single intravenous dose of .HEAL-101 (LNP-mRNA) edited human APOC3 at a mean rate of ~65%, reaching up to 70%.
   
• Disease model: in a hypertriglyceridemic human APOC3 transgenic mouse model, .HEAL-101 reduced APOC3 by 67% ± 12% and triglycerides by 75% ± 11% (mean ± standard deviation).
   
• Liver-restricted activity: editing was detected in the liver, with no significant activity in the other tissues analyzed.

The initiation of the Phase 1 investigator-initiated trial (IIT) in China is on track, with preliminary clinical data expected in the second half of 2027.

.HEAL-201 – In vivo epigenetic editing of PCSK9 for severe hypercholesterolemia (sHC)

Preclinical data support the potential of .HEAL-201 to durably silence PCSK9 without altering the DNA sequence:

• In vitro: in a human hepatic cell line, PCSK9 TALE epigenetic modulator (TALEM) mRNA achieved high on-site epigenetic editing (mean >90%), resulting in a deep and stable reduction of PCSK9 transcript levels and PCSK9 secretion, with no off-site changes in gene or protein expression detected.

• In vivo: intravenous injection of PCSK9 TALEM mRNA LNPs reduced mean plasma PCSK9 levels by more than 90% in a liver-humanized mouse model.

Cellectis plans to initiate a Phase 1 IIT in China, with preliminary clinical data expected in the first half of 2028.

Strategic Transformation Update

Cellectis continues to execute the strategic transformation announced on September 14, 2026, to become an in vivo gene editing company. As part of this transformation, Cellectis’ discontinuation of the lasme-cel and eti-cel clinical programs is proceeding as planned: enrollment has stopped, site close-out activities are underway, and treated patients will continue to be monitored in accordance with protocol-specified follow-up requirements.

The realignment of the Company’s operating model is ongoing. In connection with this initiative, the Company currently expects its global headcount to be reduced by up to 70% from its pre-transition level over the course of 2026 and 2027, subject to the completion of the applicable French works council consultation process and the compliance with applicable French and U.S. labor law requirements.

Partnerships

AstraZeneca – Joint Research and Collaboration Agreement

Activities are continuing under the Joint Research and Collaboration Agreement with AstraZeneca, which leverages Cellectis’ gene editing expertise and manufacturing capabilities to develop up to 10 novel cell and gene therapy products for areas of high unmet medical need, including oncology, immunology and rare genetic disorders.

Servier (through its sublicensee Allogene) – Anti-CD19 CAR-T

In November 2026, Allogene announced that cema-cel is being evaluated in ALPHA3, the first pivotal, randomized trial in LBCL designed to assess whether minimal residual disease (MRD)-guided treatment following first-line therapy can delay or prevent clinical relapse, and that it continues to anticipate its next clinical update in mid-2027, with trial enrollment expected to be completed by year-end 2027.

Cema-cel is a product candidate licensed to Servier under the License, Development and Commercialization Agreement signed by and between les Laboratoires Servier and Institut de Recherches Internationales Servier (“Servier”) and Cellectis (the “Servier Agreement”) and sublicensed by Servier to Allogene in certain territories.

Iovance

In November 2026, Iovance announced that a Phase 1/2 trial investigating IOV-4001, a PD-1 inactivated TIL (tumor infiltrating lymphocyte) therapy, is enrolling patients with previously treated metastatic melanoma and mNSCLC (non-squamous metastatic non-small-cell lung cancer). IOV-4001 is engineered to resist inhibitory signals and enhance the ability of TIL therapies to fight and kill cancer in the TME (tumor microenvironment).

Financial Results

Cash, cash equivalent and fixed-term deposits: As of September 30, 2026, Cellectis had $149 million in consolidated cash, cash equivalents, restricted cash and fixed-term deposits classified as current and non-current financial assets. When the Company’s realignment is fully implemented as planned, the Company believes that its existing cash and cash equivalents, together with fixed-term bank deposits, will be sufficient to fund its operations into the second half of 2028.

This compares to $211 million in consolidated cash, cash equivalents, restricted cash and fixed-term deposits classified as current financial assets as of December 31, 2025. The $62 million change was primarily driven by payments to suppliers of $37.9 million, payroll-related payments (salaries, bonuses and social charges) totaling $37.5 million, lease liability payments of $7.3 million, repayments of $4.0 million under the “PGE” loan and capital expenditures of $1.9 million, partially offset by $21.4 million of cash received from customers and $5.4 million of interest received from our financial and cash-equivalent investments.

We currently foresee focusing our cash spending at Cellectis primarily in supporting the development of our pipeline of product candidates, including .HEAL-101, .HEAL-201,  potential new product candidates, and one-off restructuring costs.

Revenues and Other Income: Consolidated revenues and other income were $19.9 million for the nine-month period ended September 30, 2026, compared to $67.4 million for the nine-month period ended September 30, 2025. The $47.5 million decrease between the nine-month periods ended September 30, 2025 and 2026 was primarily attributable to a $47.8 million decrease in revenues mainly driven by the level of activities performed under the Research Plans of the AstraZeneca Joint Research Collaboration Agreement in the nine-month period of 2026. It was partially offset by a $0.3 million increase, which was mainly attributable to a higher research tax credit resulting from increased eligible R&D expenses.

R&D Expenses: Consolidated R&D expenses were $108.8 million for the nine-month period ended September 30, 2026, compared to $69.1 million for the nine-month period ended September 30, 2025. The $39.7 million increase was primarily driven by a $34.9 million impact from the strategic transformation announced in September 2026, including a $26.6 million one-off impairment loss, $6.2 million of termination benefits and $2.1 million of costs related to the close-out of the lasme-cel and eti-cel programs. Excluding the above impacts, research and development expenses increased by $4.8 million during the nine-month period ended September 30, 2026 compared with the same period in 2025, primarily driven by (i) a $1.4 million increase in non-cash stock-based compensation expense associated with awards granted in 2026, reflecting higher grant-date fair value due to an increase in the underlying share price, and (ii) a $2.1 million increase in purchases and external expenses, mainly attributable to higher clinical development costs related to the lasme-cel and eti-cel studies incurred prior to the strategic transformation announced in September 2026, as well as the .HEAL-101 and .HEAL-201 programs.

SG&A Expenses: Consolidated SG&A expenses were $17.5 million for the nine-month period ended September 30, 2026, compared to $15.0 million for the nine-month period ended September 30, 2025. The $2.5 million increase was primarily driven by a $1.1 million impact from the strategic transformation announced in September 2026, including $0.9 million of termination benefits related to the Group’s restructuring plan in the United States and France, and a $0.3 million impairment loss on our facility assets. Excluding the above impacts, selling, general and administrative expenses increased by $1.4 million, mainly due to higher stock-based compensation expense resulting from awards granted in 2026, whose grant-date fair value increased due to a higher underlying share price and to a slight increase in purchases and external expenses.

Net financial gain (loss): The consolidated net financial gain for the nine-month period ended September 30, 2026 was $5.2 million, compared to a $25.6 million net financial loss for the nine-month period ended September 30, 2025. The $30.8 million difference reflects a $10.8 million increase in financial income and a $20.0 million decrease in financial expenses.

The $10.8 million increase in financial income was primarily attributable to (i) a $14.3 million increase in non-cash gains recognized from fair value measurements, mainly reflecting a $15.1 million gain from the fair value measurement of the Tranche A, B and C warrants issued to the European Investment Bank (“EIB”) during the period, compared with a $5.8 million fair value loss in the same period in 2025, partially offset by (ii) a $2.7 million decrease in interest income earned on cash, cash equivalents and financial assets, and (iii) a $1.0 million decrease in foreign exchange gains.

The $20 million decrease in financial expenses was primarily attributable to (i) a $23.7 million decrease in foreign exchange losses, mainly resulting from the appreciation of the US dollar against the euro, (ii) a $5.9 million decrease in losses from fair value measurements, as Tranche A, B and C warrants issued to the EIB generated a fair value gain during the period, partly offset by (iii) the recognition of a $9.4 million  Expected Credit Loss (ECL) allowance on the financial guaranty contract with Cibus’ landlord.

Net Loss Attributable to Shareholders of Cellectis: Consolidated net loss attributable to shareholders of Cellectis was $101.1 million (or a $1.00 net loss per share) for the nine-month period ended September 30, 2026, compared to a $41.3 million net loss (or a $0.41 net loss per share) for the nine-month period ended September 30, 2025. The $59.8 million increase in net loss was mainly due to (i) a $90.5 million increase in operating loss, partly offset by (ii) a $30.8 million improvement in net financial result, from a net financial loss of $25.6 million as of September 30, 2025 to a net financial gain of $5.2 million as of September 30, 2026.

Adjusted Net Loss Attributable to Shareholders of Cellectis: Consolidated adjusted net loss attributable to shareholders of Cellectis was $95.2 million (or a $0.95 net loss per share) for the nine-month period ended September 30, 2026, compared to a net loss of $37.4 million (or a $0.37 net loss per share) for the nine-month period ended September 30, 2025.

The interim condensed consolidated financial statements of Cellectis have been prepared in accordance with International Financial Reporting Standards, as issued by the International Accounting Standards Board (“IFRS”).

Please see “Note Regarding Use of Non-IFRS Financial Measures” for reconciliation of GAAP net income (loss) attributable to shareholders of Cellectis to adjusted net income (loss) attributable to shareholders of Cellectis.

CELLECTIS S.A. UNAUDITED INTERIM CONDENSED STATEMENTS OF CONSOLIDATED FINANCIAL POSITION ($ in thousands)
		As of
		December 31, 2025			September 30, 2026
ASSETS
Non-current assets
Intangible assets		535			806
Property, plant, and equipment		38,788			7,137
Right-of-use assets		23,658			12,959
Non-current financial assets		5,088			4,631
Other non-current assets		20,025			24,309
Deferred tax assets		382			382
Total non-current assets		88,476			50,223
Current assets
Trade receivables		14,398			4,125
Subsidies receivables		7,800			7,499
Other current assets		5,383			4,872
Cash, cash equivalents and current financial assets		208,663			146,705
Total current assets		236,244			163,202
TOTAL ASSETS		324,720			213,425
LIABILITIES
Shareholders’ equity
Share capital		5,903			5,926
Premiums related to the share capital		437,445			373,661
Currency translation adjustment		(33,316	)		(31,904	)
Accumulated deficit		(266,538	)		(264,257	)
Net loss		(67,593	)		(101,058	)
Total shareholders’ equity		75,901			(17,632	)
Non-current liabilities
Non-current financial liabilities		74,013			68,972
Non-current lease debts		27,725			19,518
Non-current provisions		1,329			1,258
Total non-current liabilities		103,067			89,747
Current liabilities
Current financial liabilities		10,460			7,561
Current lease debts		7,701			6,363
Trade payables		17,277			16,903
Deferred income and contract liabilities		96,803			90,371
Current provisions		1,169			8,855
Other current liabilities		12,342			11,256
Total current liabilities		145,752			141,310
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		324,720			213,425

 

Cellectis S.A. UNAUDITED INTERIM CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS For the nine-month period ended September 30, 2026   ($ in thousands, except share and per share amounts)
		For the nine-month period ended September 30,
		2025			2026
Revenues and other income
Revenues		62,552			14,771
Other income		4,834			5,120
Total revenues and other income		67,386			19,891
Operating expenses
Research and development expenses		(69,081	)		(108,797	)
Selling, general and administrative expenses		(14,988	)		(17,526	)
Other operating income		958			229
Total operating expenses and other operating income		(83,111	)		(126,093	)
Operating loss		(15,725	)		(106,202	)
Net Financial (loss) gain		(25,550	)		5,246
Income tax		–			(102	)
Net loss		(41,275	)		(101,058	)
Basic and diluted net loss per share attributable to shareholders of Cellectis ($/share)		(0.41	)		(1.00	)
Number of shares used for computing (basic and diluted)		100,262,948			100,629,644

 

UNAUDITED INTERIM CONDENSED STATEMENTS OF CONSOLIDATED OPERATIONS For the three-month period ended September 30, 2026   ($ in thousands, except share and per share amounts)
		For the three-month period ended September 30,
		2025						2026
Revenues and other income
Revenues		35,172						3,764
Other income		1,992						1,674
Total revenues and other income		37,164						5,439
Operating expenses
Research and development expenses		(24,069		)				(56,632		)
Selling, general and administrative expenses		(5,208		)				(6,197		)
Other operating income (expense)		154						(124		)
Total operating expenses and other operating income		(29,123		)				(62,953		)
Operating income (loss)		8,041						(57,514		)
Net Financial gain (loss)		(7,452		)				(3,929		)
Income tax		–						(30		)
Net income (loss)		589						(61,474		)
Basic and diluted net income (loss) per share attributable to shareholders of Cellectis ($/share)		0.01						(0.61		)
Number of shares used for computing:
Basic		100,325,229						100,712,173
Diluted		101,708,538						100,712,173

 

Note Regarding Use of Non-IFRS Financial Measures

Cellectis S.A. presents adjusted net income (loss) attributable to shareholders of Cellectis in this press release. Adjusted net income (loss) attributable to shareholders of Cellectis is not a measure calculated in accordance with IFRS® Accounting Standards. We have included in this press release a reconciliation of this figure to net income (loss) attributable to shareholders of Cellectis, which is the most directly comparable financial measure calculated in accordance with IFRS Accounting Standards.

Because adjusted net income (loss) attributable to shareholders of Cellectis excludes non-cash stock-based compensation expense – a non-cash expense, we believe that this financial measure, when considered together with our financial statements prepared in accordance with IFRS Accounting Standards, can enhance an overall understanding of Cellectis’ financial performance. Moreover, our management views the Company’s operations, and manages its business, based, in part, on this financial measure. In particular, we believe that the elimination of non-cash stock-based expenses from Net income (loss) attributable to shareholders of Cellectis can provide a useful measure for period-to-period comparisons of our core businesses. Our use of adjusted net income (loss) attributable to shareholders of Cellectis has limitations as an analytical tool, and you should not consider it in isolation or as a substitute for analysis of our financial performance as reported under IFRS Accounting Standards. Some of these limitations are: (a) other companies, including companies in our industry which use similar stock-based compensation, may address the impact of non-cash stock- based compensation expense differently; and (b) other companies may report adjusted net income (loss) attributable to shareholders or similarly titled measures but calculate them differently, which reduces their usefulness as a comparative measure. Because of these and other limitations, you should consider adjusted net income (loss) attributable to shareholders of Cellectis alongside our statements of consolidated operations prepared in accordance with IFRS Accounting Standards, including Net income (loss) attributable to shareholders of Cellectis.

RECONCILIATION OF IFRS TO NON-IFRS NET INCOME (unaudited)   For the nine-month period ended September 30, 2026 ($ in thousands, except per share data)
		For the nine-month period ended September 30,
		2025			2026
Net loss		(41,275	)		(101,058	)
Adjustment:   Non-cash stock-based compensation expense		3,860			5,815
Adjusted net loss attributable to shareholders of Cellectis		(37,415	)		(95,243	)
Basic and diluted adjusted net loss attributable to shareholders of Cellectis ($/share)		(0.37	)		(0.95	)
Weighted average number of outstanding shares, basic and diluted (units)		100,262,948			100,629,644

 

RECONCILIATION OF IFRS TO NON-IFRS NET INCOME (unaudited)   For the three-month period ended September 30, 2026 ($ in thousands, except per share data)
		For the three-month period ended September 30,
		2025			2026
Net income (loss)		589			(61,474	)
Adjustment:   Non-cash stock-based compensation expense		1,602			1,863
Adjusted net income (loss) attributable to shareholders of Cellectis		2,191			(59,611	)
Basic and diluted adjusted net loss per share attributable to shareholders of Cellectis ($/share)		0.02			(0.59	)
Weighted average number of outstanding shares, basic (units)		100,325,229			100,712,173
Weighted average number of outstanding shares, diluted (units)		101,708,538			100,712,173

About Cellectis
Cellectis is a genome engineering company developing genetic medicines for diseases that today demand a lifetime of treatment. Leveraging decades of expertise in programmable DNA-binding proteins, the Company has built a differentiated genome engineering platform spanning gene editing, base editing, epigenetic editing and transcriptional regulation. By delivering the genomic intervention each disease requires, Cellectis is advancing a new generation of genetic medicines designed to move beyond disease management and toward lasting therapeutic impact. Cellectis’ headquarters are in Paris, France, with locations in New York and Raleigh (NC). Cellectis is listed on the Nasdaq Global Market (ticker: CLLS) and on Euronext Growth (ticker: ALCLS). To find out more, visit www.cellectis.com and follow Cellectis on LinkedIn and X.

Cautionary Statement
This press release contains “forward-looking” statements within the meaning of applicable securities laws, including the Private Securities Litigation Reform Act of 1995. Forward-looking statements may be identified by words such as “anticipate,” “designed to”, “expected”, “plan”, “planned”, “potential”, “will,” “would” or similar expressions and/or the negative of these. These forward-looking statements are based on our management’s current expectations and assumptions and on information currently available to management, including information provided or otherwise publicly reported by our licensed partners. Forward-looking statements in this press release include statements regarding the anticipated initiation of clinical trials, including an IIT in China, the planned timing for the release of preliminary clinical data for the Company’s lead program, the potential of the Company’s preclinical candidate product based on pre-clinical results, the potential for success of the Company’s in vivo gene editing programs, the anticipated impact, including potential cost savings, of the Company’s decision to cease the development of lasme-cel and eti-cel and to initiate a restructuring plan, the contemplated implementation of headcount reductions and other cost-savings initiatives and their planned timeframe, and the Company’s targeted cash runway. Actual results, performance or events may differ materially from those projected in any forward-looking statement. Many important factors may adversely affect such forward-looking statements and cause actual results to differ from those in any forward-looking statement, including, without limitation, uncertainties inherent in the initiation and completion of preclinical and clinical studies; the availability and timing of results from studies, once initiated; the acceptance by global regulatory agencies of data generated from IIT in China; the potential that pre-clinical animal model data may not translate into further preclinical development or clinical setting; promising preclinical data not yielding positive further preclinical data or clinical results; the performance of the IIT in China, changes in the competitive landscape for in vivo gene editing products; expectations for regulatory approvals to conduct clinical trials. With respect to our cash runway, our operating plans, including product development plans, may change as a result of various factors, including factors currently unknown to us. Furthermore, many other important factors, including those described in our Annual Report on Form 20-F as amended and in our annual financial report (including the management report) for the year ended December 31, 2025 and subsequent filings Cellectis makes with the Securities Exchange Commission from time to time, which are available on the SEC’s website at www.sec.gov , as well as other known and unknown risks and uncertainties may adversely affect such forward-looking statements and cause our actual results, performance or achievements to be materially different from those expressed or implied by the forward-looking statements. Except as required by law, we assume no obligation to update these forward-looking statements publicly, or to update the reasons why actual results could differ materially from those anticipated in the forward-looking statements, even if new information becomes available in the future. 

For further information on Cellectis, please contact:

Media contacts:
Pascalyne Wilson, Director, Communications, +33 (0)7 76 99 14 33, media@cellectis.com 
Patricia Sosa Navarro, Chief of Staff to the CEO, +33 (0)7 76 77 46 93

Investor Relations contact:
Arthur Stril, Chief Financial Officer & Chief Business Officer, investors@cellectis.com

Attachment

• PRESS RELEASE-Q32026-earnings-ENGLISH

MARKHAM, Ontario, Nov. 12, 2026 (GLOBE NEWSWIRE) — Sienna Senior Living Inc. (“Sienna” or the “Company”) (TSX: SIA) today announced its financial results for the three and nine months ended September 30, 2026.

Highlights

• Average Same Property Occupancy in the retirement segment increases to 94.9% in Q3 2026
• Same Property Net Operating Income (“NOI”) up 8.7% year-over-year to $57.8 million in Q3 2026
  • Retirement Segment up 11.6% year-over-year in Q3 2026
  • Long-Term Care (“LTC”) Segment up 6.2% year-over-year in Q3 2026
• Operating Funds from Operations (“OFFO”) up 21.2% year-over-year, or 1.4% per share, in Q3 2026. OFFO per share includes a temporary dilutive impact of the At-The-Market Equity Distribution Program (“ATM Program”).
• Adjusted Funds from Operations (“AFFO”) up 25.7% year-over-year, or 5.2% per share, in Q3 2026. AFFO per share includes a temporary dilutive impact of the ATM Program. 
• AFFO Payout Ratio lowered to 72.0% in Q3 2026 from 75.9% in Q3 2025
• $433 million of acquisitions closed and under contract to date in 2026, with robust pipeline of further opportunities
• $150 million renewal of ATM Program to support growth

“The depth of Sienna’s operations, the Company’s growing scale and our disciplined approach to capital allocation put us in a strong position to provide more services and care to a growing number of Canadian seniors,” said Nitin Jain, President and Chief Executive Officer. “With 15 consecutive quarters of growth and $1.2 billion of assets added since the beginning of last year, our momentum is evident across the Company.”

2026 Growth through Acquisitions

The table below highlights Sienna’s portfolio expansion through acquisitions to date in 2026:

Property Name / Segment	Year Built	Location	Number of Beds/ Suites	Purchase Price ($M)(1)
Q1 2026
Glenmore Lodge / LTC (22.8%)	2016	Kelowna, British Columbia	118	$	10.1
LaSalle Park / Retirement (10.9%)	2013	Greater Toronto Area, Ontario	123	$	9.3
				$	19.4
Q2 2026
The Bartlett / Retirement	2021	Greater Toronto Area, Ontario	129	$	59.4
Rockland Manor / Retirement	2015	Greater Ottawa Area, Ontario	160	$	41.0
Ballycliffe / LTC(2)	2025	Greater Toronto Area, Ontario	224	$	68.3
				$	168.7
Q3 2026
Stonemont On The Park / Retirement(3)	2024	Ottawa, Ontario	305	$	170.7
					170.7
Q4 2026
Brighton Retirement & Active Living(4)	2024	Brighton, Ontario	165	$	73.8
					73.8
Total 2026 Acquisitions (closed and under contract)				$	432.6
Purchase price excludes working capital and other adjustments. The Company entered into a purchase agreement and expects to complete the transaction in Q4 2026 or early Q1 2027. The Company completed the acquisition on October 29, 2026. The Company entered into a purchase agreement and expects to complete the transaction in Q4 2026.

Renewal of ATM Program

On November 12, 2026, the Board of Directors approved the renewal of the ATM Program, which allows the Company to issue up to $150 million of common shares at its discretion to fund the Company’s growth initiatives. Concurrently, the ATM Program approved in May 2026 was terminated.

Financial and Operating Results

The following table represents the Key Performance Indicators for the periods ended September 30:

	Three months ended September 30,							Nine months ended September 30,
Thousands of Canadian dollars, except occupancy, share and ratio data	2026		2025		Change			2026		2025		Change
OCCUPANCY
Retirement – Average Same Property	94.9	%	94.7	%	0.2	%		94.6	%	93.5	%	1.1	%
Retirement – Average total occupancy	90.8	%	91.6	%	(0.8	)%		90.1	%	90.7	%	(0.6	)%
LTC – Average total occupancy	98.6	%	98.3	%	0.3	%		98.4	%	98.2	%	0.2	%
FINANCIAL
Revenue, Proportionate Basis1	295,676		263,066		32,610			870,170		760,676		109,494
Same Property NOI1	57,812		53,194		4,618			162,835		145,413		17,422
NOI1	65,559		55,451		10,108			189,599		151,959		37,640
Administrative expenses	13,789		9,255		4,534			35,325		29,370		5,955
Adjusted EBITDA1	57,941		47,099		10,842			165,373		125,341		40,032
OFFO1	39,786		32,824		6,962			116,466		88,118		28,348
AFFO1	36,092		28,711		7,381			106,144		76,977		29,167
AFFO Payout Ratio1	72.0	%	75.9	%	(3.9	)%		71.0	%	83.4	%	(12.4	)%
PER SHARE INFORMATION
OFFO per share1	0.358		0.353		0.005			1.094		0.974		0.120
AFFO per share1	0.325		0.309		0.016			0.997		0.851		0.146
FINANCIAL RATIOS
Net debt to Adjusted Gross Book Value at period end	34.5	%	40.8	%	(6.3	)%		34.5	%	40.8	%	(6.3	)%
Weighted Average Cost of Debt at period end	3.9	%	3.9	%	—	%		3.9	%	3.9	%	—	%
Net debt to Adjusted EBITDA at period end	5.8		7.9		(2.1	)		5.8		7.9		(2.1	)
Interest Coverage Ratio	3.7		3.4		0.3			3.7		3.4		0.3
Debt Service Coverage Ratio	2.8		2.4		0.4			2.8		2.4		0.4
Weighted Average Term to Maturity at period end	4.9		6.0		(1.1	)		4.9		6.0		(1.1	)
CHANGE IN SAME PROPERTY NOI1
Retirement1					11.6	%						14.0	%
LTC1					6.2	%						10.3	%
Total1					8.7	%						12.0	%
Note: Refer to Sienna’s Management Discussion and Analysis (“MD&A”) for the three and nine months ended September 30, 2026, published on November 12, 2026, for further details. This MD&A can be found on the Company’s website atwww.siennaliving.ca. In Q3 2025, the Company recognized retroactive funding of $1,006 ($1,371 net of $365 taxes) relating to prior years. Excluding this item, OFFO and AFFO per share for the three months ended September 30, 2025 would each be lower by $0.011. For the nine months ended September 30, 2025, the Company recognized retroactive funding of $1,006 ($1,371 net of $365 taxes) and a WSIB refund of $1,334 ($1,817 net of $483 taxes), both relating to prior years. Excluding these items, OFFO and AFFO per share for nine months ended September 30, 2025, would each have been $0.026 lower. For the nine months ended September 30, 2026, the Company recognized retroactive funding of $2,348 ($3,195 net of $847 taxes) and a WSIB refund of $256 ($348 net of $92 taxes), both relating to prior years. Excluding these items, OFFO and AFFO per share for nine months ended September 30, 2026 , would each have been $0.024 lower.

The year-over-year change in Same Property NOI, excluding retroactive adjustments in both years, for the three and nine months ended September 30, 2026 would have been as follows:

				Three months ended September 30, 2026			Nine months ended September 30, 2026
		Retirement		11.6	%		13.4	%
		LTC		11.5	%		10.8	%
		Total		11.6	%		12.0	%

Financial Performance – Q3 2026

• Revenue, Proportionate Basis increased by 12.4%, or $32.6 million, to $295.7 million, compared to Q3 2025. In the Retirement segment, the increase is primarily attributable to rental rate increases, acquisitions, as well as higher care and ancillary revenue. In the LTC segment, the increase is primarily due to acquisitions and redevelopments completed in 2025, government funding increases, and increased private accommodation revenue.
• NOI increased by 18.2% or $10.1 million to $65.6 million, compared to Q3 2025. The Retirement segment NOI increased by $7.5 million, primarily attributable to revenue growth, offset partially by higher labour, food and utility expenses, and incremental expenses from acquisitions. The LTC segment NOI increased by $2.6 million, mainly due to revenue increases, offset in part by higher direct care labour and repair and maintenance expenses, and other inflationary pressures.
• Same Property NOI increased by 8.7% to $57.8 million compared to Q3 2025, including a 6.2% increase in the LTC segment, and a 11.6% increase in the retirement segment. Excluding the one-time items of Q3 2025, Same Property NOI would have increased by 11.6% compared to Q3 2025, driven by 11.6% growth in the retirement segment and 11.5% growth in the LTC segment.
• OFFO increased by 21.2% in Q3 2026, or $7.0 million, to $39.8 million compared to Q3 2025. The increase was primarily due to higher NOI, offset partially by higher income tax expenses and higher interest expenses from increased financings as a result of growth and higher borrowing rates. OFFO per share increased by 1.4% in Q3 2026, or $0.005, to $0.358, largely driven by higher OFFO, offset by the temporary dilutive impact of the ATM Program.
• AFFO increased by 25.7% in Q3 2026, or $7.4 million, to $36.1 million compared to Q3 2025. The increase was primarily driven by higher OFFO and construction funding income received from the Government of Ontario for redevelopments completed in 2025. AFFO per share increased by 5.2% in Q3 2026, or $0.016, to $0.325, largely driven by higher AFFO, offset by the temporary dilutive impact of the ATM Program.
• AFFO Payout Ratio lowered to 72.0% from 75.9% in Q3 2025, reflecting the Company’s strong operating results, contributions from completed developments and accretive acquisitions, and the progressive deployment of capital to fund acquisitions.
• Debt – The Company’s Net Debt to Adjusted Gross Book Value decreased by 630 bps to 34.5% at the end of Q3 2026, from 40.8% at the end of Q3 2025, primarily as a result of the Company’s capital allocation strategy, including acquisitions and developments throughout 2025 and 2026, as well as equity raised under the Company’s ATM Program. Net Debt to Adjusted EBITDA decreased to 5.8 times in Q3 2026, from 7.9 times in Q3 2025 mainly driven by higher Adjusted EBITDA, as well as cash raised from the ATM Program, which was subsequently deployed to fund an acquisition announced in the quarter.

Financial Performance – Nine months ended September 30, 2026

• Revenue, Proportionate Basis increased by 14.4%, or $109.5 million, to $870.2 million, compared to nine months ended September 30, 2025. In the Retirement segment, the increase is primarily attributable to acquisitions, occupancy growth, rental rate increases, as well as higher care and ancillary revenue. In the LTC segment, the increase is primarily due to government funding increases, increased private accommodation revenue, acquisitions and redevelopments completed in 2025, and $3.2 million of retroactive funding related to the prior year.
• NOI increased by 24.8% to $189.6 million, compared to nine months ended September 30, 2025. The Retirement segment NOI increased by $23.9 million, primarily attributable to revenue increases, offset partially by higher labour, utility and maintenance expenses. The LTC segment NOI increased by $13.8 million, mainly due to revenue growth, offset in part by higher flow-through direct care labour, and repair and maintenance expenses.
• Same Property NOI increased by 12.0% to $162.8 million compared to nine months ended September 30, 2025, including a 14.0% increase in the retirement segment, and a 10.3% increase in the LTC segment. For the nine months ended September 30, 2026, the Company recognized $3.2 million of retroactive funding related to 2025 and a $0.3 million WSIB refund, compared to a $1.3 million of retroactive funding and $1.8 million WSIB refund recognized in the prior year. Excluding these items, Same Property NOI would have increased by 12.0% compared to Q3 2025, driven by 13.4% growth in the retirement segment and 10.8% growth in the LTC segment.
• OFFO increased by 32.2%, or $28.3 million, to $116.5 million compared to the nine months ended September 30, 2025. The increase was primarily driven by higher NOI and lower income tax expenses largely resulting from accelerated tax depreciation recognized in Q1 2026 on properties acquired in 2025, offset partially by higher interest expenses from increased financings as a result of growth and higher borrowing rates. OFFO per share increased by 12.3%, or $0.120, to $1.094 compared to the nine months ended September 30, 2025.
• AFFO increased by 37.9%, or $29.2 million, to $106.1 million compared to the nine months ended September 30, 2025. The increase was primarily driven by higher OFFO and construction funding income received, offset by increased maintenance capital expenditures. AFFO per share increased by 17.2% or $0.146, to $0.997 compared to the nine months ended September 30, 2025.
• AFFO Payout Ratio lowered to 71.0% from 83.4% for the nine months ended September 30, 2026, reflecting the Company’s strong operating results, contributions from completed developments and accretive acquisitions, and the progressive deployment of capital to fund acquisitions.
• $253 million of shares issued under Sienna’s ATM Program year-to-date in 2026.

Outlook

Long-term fundamentals in Canadian senior living are underpinned by growing demand, with seniors making up the fastest-growing demographic, and limited new supply of senior living accommodations.

Looking ahead, Sienna will continue to leverage these sector dynamics as we grow through portfolio optimization, and drive continued retirement NOI and margin growth.

In addition, the increasing scale of our operations, our ability to identify and execute on strategic transactions and the acceleration of our long-term care redevelopment program are positioning us well to sustain our growth momentum.

Retirement Operations – Our focus on generating strong interest in our residences, as well as continued improvements to our operations and favourable supply/demand fundamentals, supported the year-over-year occupancy and margin improvements. Same Property operating margins increased by approximately 200 bps year-over-year in Q3 2026.

Going forward, we will continue to focus on expanding the Company’s NOI with concentrated marketing and sales initiatives, operational efficiency and asset optimization efforts. We expect Same Property NOI growth in our retirement portfolio to exceed 10% in 2026 as a result of the segment’s occupancy growth, rate increases and higher care revenue.

Asset Optimization Initiatives – Sienna believes that there is a significant opportunity to create value through asset optimization initiatives at certain properties. These initiatives target a better market fit and include renovations, changes in suite mix, additional services or the alternative use of a property to reflect the evolving needs of residents. By optimizing our existing portfolio, we expect to unlock substantial NOI growth while modernizing Sienna’s asset base.

Long-Term Care Operations – Sienna’s LTC platform is benefitting from government funding increases, higher revenue from private accommodation, in addition to a growing platform.

Excluding retroactive items, we expect the year-over-year increase of our 2026 LTC Same Property NOI for the full year to be in the high-single-digit percentage range, representing an increase from our previous target in the mid- to high-single-digit percentage range.

Growth Targets – The following table summarizes Sienna’s 2026 key targets for Same Property growth, excluding One-Time Items:

Segment	Performance Indicator	Target
Retirement	2026 Occupancy	~95%
Retirement	2026 Margin Growth (YoY)	150 – 200 bps
Retirement	2026 NOI Growth (YoY)	10%+
LTC	2026 NOI Growth (YoY)	High-single-digit %

Conference Call

Sienna will host a conference call on Friday, November 13, 2026 at 9:30 a.m. (ET). The toll-free dial-in number for participants is 1-800-715-9871, conference ID: 1945631. A webcast of the call will be accessible via Sienna’s website at www.siennaliving.ca/investors/events-presentations. It will be available for replay until November 13, 2027 and archived on Sienna’s website.

About Sienna Senior Living

Sienna Senior Living Inc. (TSX:SIA) offers a full range of seniors’ living options, including independent living, assisted living and memory care under its Aspira retirement brand, long-term care, and specialized programs and services. Sienna’s approximately 15,500 employees are passionate about cultivating happiness in daily life. For more information, please visit www.siennaliving.ca.

Risk Factors

Refer to the risk factors disclosed in the Company’s MD&A for the year ended December 31, 2025, and its most recent Annual Information Form for more information.

Forward-Looking Statements

Certain of the statements contained in this news release are forward-looking statements and are provided for the purpose of presenting information about management’s current expectations and plans relating to the future. Readers are cautioned that such statements may not be appropriate for other purposes. These statements generally use forward-looking words, such as “anticipate,” “continue,” “could,” “expect,” “may,” “will,” “estimate,” “believe,” “goals”, “target” or other similar words and are based on the Company’s expectations, estimates, forecasts and projections. These statements are subject to significant known and unknown risks and uncertainties that may cause actual results or events to differ materially from those expressed or implied by such statements and, accordingly, should not be read as guarantees of future performance or results and will not necessarily be accurate indications of whether or not such results will be achieved. The forward-looking statements in this news release are based on information currently available and what management currently believes are reasonable assumptions. The Company does not undertake any obligation to publicly update or revise any forward-looking statements except as may be required by applicable law.

FOR FURTHER INFORMATION, PLEASE CONTACT:

David Hung
Chief Financial Officer and Executive Vice President, Investments
(905) 489-0258
david.hung@siennaliving.ca 

Nancy Webb
Executive Vice President, Corporate Affairs and Marketing
(905) 477-4006 ext. 3030
nancy.webb@siennaliving.ca 

CALGARY, Alberta, Nov. 12, 2026 (GLOBE NEWSWIRE) — Condor Energies Inc. (“Condor” or the “Company”) (TSX:CDR), a Canadian based, internationally focused energy transition company focused on Central Asia is pleased to announce the release of its unaudited interim condensed consolidated financial statements for the three and nine months ended September 30, 2026 (the “Financial Statements”), together with the related management’s discussion and analysis. These documents will be made available under Condor’s profile on SEDAR+ at www.sedarplus.ca and on the Condor website at www.condorenergies.ca. Readers are invited to review the latest corporate presentation available on the Condor website. All financial amounts in this news release are presented in Canadian dollars, unless otherwise stated.

HIGHLIGHTS

• Production in Uzbekistan for the third quarter of 2026 averaged 16,693 boe/d comprised of 16,240 boe/d (97.4 MMscf/d) of natural gas and 453 bopd of condensate which is a total production increase of 20% from the second quarter of 2026 and a total production increase of 67% from the third quarter of 2025.
• Uzbekistan natural gas and condensate sales for the third quarter of 2026 increased to $33.6 million or a 24% increase from the second quarter of 2026.
• During the period from November 1, 2026 through November 11, 2026, the Company achieved a new average production record of 18,631 boe/d primarily due to the completion and tie in of recently drilled wells.
• Five new wells were drilled and completed during the third quarter of 2026 and the Company has now drilled and completed eleven wells to date in 2026 and plans to drill and complete up to an additional four wells by year end.
• Initial test results from the Andakli-22 horizontal well (“A-22”) drilled in October 2026 indicate that commercially recoverable gas may be produced outside of conventionally targeted four-way structural closures.
• The Company also drilled its first deeper Jurassic clastic reservoirs well at North Syuzma (“NS-14”) in October and November 2026 and encountered 54 meters of net gas pay based on wireline logs. The drilling rig is being moved off location and completion and testing activities will commence shortly.
• In August 2026 an EPC contract was awarded to install the first phase of a field booster compressor station (the “Compressor Station”) in Uzbekistan which is expected to increase production rates by lowering the gathering system pressure.
• In October 2026 acceptance testing was completed for the Company’s first LNG facility (the “First LNG Facility”) for the Saryozek plant site (the “Saryozek Site”) and shipping to Kazakhstan is underway with an expected arrival in December 2026.
• In October 2026, the Company completed an offering of 12% unsecured convertible debentures for gross proceeds of $72.0 million. The debentures are convertible into common shares of the Company at a conversion price of $6.00 per common share and mature on October 15, 2029.

MESSAGE FROM CONDOR’S CEO

Don Streu, President and CEO of Condor commented: “2026 has been a transformational growth year for Condor as demonstrated by the recent performance accomplishments noted above. We have achieved record production rates, revenues and operating netbacks in Uzbekistan with our successful application of proven technologies while maturing new opportunities to support this trend. Our current activities in Uzbekistan are providing sustainable growth for reserves, production, and cashflow while we concurrently advance our LNG fuel substitution project and our early-stage copper and lithium critical minerals opportunities in Kazakhstan.

We are very excited and well positioned to continue building strong, near-term shareholder value from our diverse energy transition portfolio”.

Production in Uzbekistan

The Company operates under a production enhancement services contract with JSC Uzbekneftegaz (“UNG”) in Uzbekistan to increase the production, recovery, and overall system efficiency from an integrated cluster of eight conventional natural gas-condensate fields (the “PEC Project”). The cumulative license area is 282 km2 or the equivalent of 109 sections, with 78 producing wells which produce gas mainly from Jurassic carbonate reservoirs.

Production in Uzbekistan for the third quarter of 2026 averaged 16,693 boe/d comprised of 16,240 boe/d (97.4 MMscf/d) of natural gas and 453 bopd of condensate which is a 20% production increase compared to the second quarter of 2026 and a 67% increase compared to the third quarter of 2025.

The Company continues to target previously undeveloped reservoirs within its 282 km2 (~109 sections equivalent) license area with the objective of generating sustained production growth. Although most of the 2026 drilling activity has focused on the Kumli license, one of the two drilling rigs was recently relocated to the northern Andakli license and drilled A-22 outside of existing mapped structural closure boundaries. A-22 has demonstrated that commercially recoverable gas can be produced outside of conventionally targeted four-way structural closures which could become part of the Company’s next growth engine.

A-22 was drilled to a total measured depth of 3,455 meters with a lateral interval of 1,127 meters. After A-22 was acid stimulated, it was tested for an 8-hour period that yielded an average flowing rate of 6.0 MMscf/d (1,000 boepd) on a 1” choke at 444 psi average flowing tubing pressure. There was no condensate produced and the liquid rate was 667 barrels per day, which consisted primarily of drilling and completion fluids and spent acid. The well was immediately tied into the gas sales line and continues to produce while further cleaning up. The A-22 test rate is a short-term test rate and may not be indicative of long-term performance or ultimate recovery. The Company believes the A-22 test result is very impactful as it may open significant areas of prospective drilling acreage at Andakli and help derisk the commerciality of a stratigraphic horizontal well development program. Numerous Andakli follow up wells are planned as part of the 2027 drilling campaign.

After drilling the A-22 stratigraphic play, the rig moved to the Company’s North Syuzma field to drill the NS-14 vertical delineation well that targeted the deeper Jurassic clastic stacked reservoir sands. The Company previously perforated a portion of this sand package on two legacy wells in November 2025 which flowed at a combined gas rate of 13.3 MMscf/d as previously disclosed. NS-14 was drilled to 2,810 meters to evaluate the full extent of the stratigraphic column and encountered 54 meters of net gas pay based on wireline logs, with 40 meters of net gas pay in the clastic reservoirs and 14 meters in the carbonate reservoirs. Completion activities are planned to commence once the drilling rig is moved off the location and testing is expected to begin by the end of November 2026. Pending test results, up to three additional vertical and three additional horizontal follow up locations could be drilled at North Syuzma.

The Company is currently drilling the K-53 horizontal well (“K-53”) on a separate structure within the Kumli license area. K-53 was originally designed as a multilateral well with two horizontal sections (“Legs”) targeting separate carbonate reservoirs. While drilling the first leg, K-53 encountered a previously unmapped fault that resulted in the lateral penetrating both target reservoirs, effectively achieving the reservoir access originally contemplated through two horizontal legs. Given this outcome, the Company has elected to complete K-53 as a single-leg horizontal well which is expected to reduce additional drilling time and capital requirements.

Multilateral well designs remain an important option for future development, offering the potential for increased reservoir contact and production, lower drilling and tie-in costs relative to separate horizontal wells, and a reduced surface footprint. The Company intends to deploy this technology where reservoir and drilling conditions support its use.

Nine wells have been drilled in the Kumli NW structure so far in 2026, with one additional well planned in December 2026. Of the nine wells, only the Kumli-50 horizontal well (“K-50”) has yet to be tied into the gas sales pipeline. During well cleanup operations, K-50 flowed at rates estimated up to 10 MMscf/d but has not yet flowed through well testing equipment due to produced drilling fluids, completion fluids and formation water that hinder its continuous flow. The well produces when the wellbore is lifted with nitrogen but the well cannot independently lift these fluids and has been shut in to monitor pressures while alternate methods to lift the fluids are evaluated for planned implementation in the fourth quarter of 2026 in conjunction with other well workover activities.

In October 2026, the Company conducted a pre-stimulation cleanup flow test on the Kumli-51 horizontal well (“K-51”), which is another well in the Kumli NW structure. Prior to stimulation, K-51 flowed at 11.6 MMscf/d (1,933 boe/d) during a 1.5-hour test through a 1-inch choke at a stabilized tubing pressure of 703 psi. The well produced drilling and completion fluids at 356 bopd with no condensate observed. K-51 was subsequently placed on production and is expected to undergo an acid stimulation in December 2026. The K-51 test rate is a short-term test rate and may not be indicative of long-term performance or ultimate recovery.

Installation of the Compressor Station remains a top priority for the Company, and an EPC contract was awarded in August 2026. Booster compression is expected to increase gas production by lowering the gathering system pressure, mitigating liquid loading effects in wellbores, and helping to manage the impact of fluctuating and increasing downstream pipeline pressures. Simulation work conducted by an independent third-party engineering company indicates compression could yield up to 30 MMscf/d of incremental gas production and extend end-of-field life. The Compressor Station is scheduled to be commissioned in the second quarter of 2027.

LNG in Kazakhstan

The Company’s LNG initiative in Kazakhstan fully supports the government of Kazakhstan’s strategic focus on creating energy security solutions that provide viable diesel fuel alternatives to ensure the country’s transport sector functions despite worldwide fuel and energy disruptions. The Company’s First LNG Facility for the Saryozek Site completed final pressure testing of the fully assembled unit and is expected to arrive in Kazakhstan in December 2026. Although the delivery schedule has slipped due to the delayed arrival and installation of the control system components, LNG production is expected to commence in the second quarter of 2027. The Company expects to produce, distribute, and sell LNG to offset industrial diesel usage in Kazakhstan and potential end-user applications include rail locomotives, long-haul truck fleets, marine vessels, mining equipment, municipal bus fleets, and high-horsepower heavy equipment and machinery, all of which are being utilized in other countries.

The First LNG Facility is designed with an initial production capacity of 48,000 gallons (80 MT) of LNG per day, and due to its modular design, production at the Saryozek Site is expected to be subsequently expanded by two additional 48,000 gallon per day facilities to fully utilize the gas allocation awarded for this site. The Saryozek Site is one of the three natural gas allocations awarded to the Company in Kazakhstan. The Company has secured 20 hectares of land at the Saryozek Site until July 2059 under an agreement which requires the Company to construct an LNG facility at the site prior to August 2030.

The Company is reviewing third-party financing alternatives to complete the First LNG Facility, and the Company may enter one or more partnerships (or other joint venture structures) at its sites in Kazakhstan where it has already secured feed gas allocations (including the First LNG Facility).

As of September 30, 2026, the Company has incurred CAD $10.5 million of costs for the First LNG Facility, and the estimated additional remaining costs for construction and commissioning are USD $21.0 million (CAD $29.8 million) including various ancillary equipment, feed gas hookup and piping, power generation, electrical infrastructure, distribution equipment and storage tanks, LNG loading facilities and rolling stock.

Condor has received three natural gas allocations at three different locations within Kazakhstan, and the Company plans to construct modular LNG facilities at all three locations. Based on the natural gas allocations of 21,798 m3/hour, 29,110 m3/hour and 20,500 m3/hour, respectively, the total potential LNG fuel produced is estimated to have an energy-equivalent volume of 1.5 million litres of diesel daily and could reduce CO2 emissions by 390,000 MT per year, which is estimated to be equivalent to removing 85,000 cars from the road annually. See “Forward-Looking Statements” in this news release for further discussion on the risks and uncertainties related to the natural gas allocations and the Company’s LNG initiatives.

$72.0 Million Financing of Convertible Debentures

In October 2026, the Company completed an offering of convertible debentures for aggregate gross proceeds of $72.03 million which are convertible into 12,005,481 common shares (the “2026 Debentures”) and comprised a brokered public offering for gross proceeds of $28.75 million including the full exercise of the over-allotment option by the agents (the “Public Offering”) and a concurrent non-brokered private placement for gross proceeds of $43.28 million (the “Private Placement”) on the same terms and conditions except the 2026 Debentures issued under the Private Placement are subject to a statutory four-month hold period expiring on February 16, 2027.

The 2026 Debentures are unsecured, have no associated financial covenants, bear interest at 12% per annum payable quarterly in cash and in arrears, and the principal amount is convertible at any time at the option of the holder on or before the maturity date of October 15, 2029, at a conversion price of $6.00 per common share. The 2026 Debentures issued under the Public Offering are traded on the Toronto Stock Exchange under the symbol CDR.DB and those issued under the Private Placement are expected to commence trading following the four-month hold period on or about February 16, 2027.

The estimated issuance costs associated with the 2026 Debentures of $3.3 million are comprised of agent commissions, intermediary fees, legal and advisory fees, and regulatory costs. The net proceeds from the 2026 Debentures offering of $68.7 million is intended to be used to fund the Compressor Station in Uzbekistan, the First LNG Facility in Kazakhstan, working capital and general corporate purposes.

Critical Minerals Licenses in Kazakhstan

The Company holds a 100% working interest in two contiguous critical minerals mining licenses which provide subsurface exploration rights for solid minerals, including lithium and copper, for respective six-year terms. The 37,300-hectare Sayakbay license was awarded in July 2023 and the nearby 6,800-hectare Kolkuduk license was awarded in February 2025. There has been a significant increase in the number of mining licenses awarded in the areas adjacent to the Company’s license areas and active copper exploration activities are underway by major mining companies, including Rio Tinto.

The Company has advanced an integrated geophysical program at Sayakbay. Historical gravity data was digitized, reprocessed, and incorporated into a three-dimensional density model, refining the interpretation of the Sayakbay Dome, adjacent structural depressions, and a major shear zone along the Moyunkum uplift. Unmanned Aerial Vehicle (“UAV”) magnetic surveys further defined the geometry of the Sayakbay Dome, faults intersecting the structure, and other structural features that may be relevant to mineralizing fluid migration and copper deposition.

The Company is currently processing and interpreting a ground transient electromagnetic (“TEM”) survey over the central portion of Sayakbay. The survey is designed to map prospective geoelectric horizons and structural features to depths of approximately 700 meters and to improve the identification and ranking of potential mineralized targets. Preliminary results have demonstrated good correlation with historical well resistivity data and have identified several geoelectric layers and lateral resistivity variations that may reflect changes in lithology, fluid saturation, or structure.

At Kolkuduk, the Company completed a UAV-borne magnetic survey during 2026. Interpretation of magnetic data, together with historical gravity, seismic, and geological information, further defined the anticlinal structure, faults, and prospective Taskuduk and Zhezkazgan formations. These formations are recognized hosts for sandstone-hosted copper mineralization within the Chu-Sarysu Basin.

The Company continues to evaluate the lithium-brine potential of both licenses. A prior well drilled within the Kolkuduk license territory for hydrocarbon exploration encountered and tested brine deposits with lithium concentrations of up to 130 milligrams per liter as reported by the Ministry of Geology of the Republic of Kazakhstan. A 1,000-meter column of tested and untested brine reservoirs has been identified from historical wireline log and core data. At Sayakbay, a prior legacy well drilled for hydrocarbon exploration encountered and tested brine deposits with lithium concentrations of 67 milligrams per liter in Carboniferous-aged intervals as reported by the Ministry of Geology of the Republic of Kazakhstan. A 670-meter column of tested and untested brine reservoirs has been identified from historical wireline log and core data. Other critical minerals identified at the Kolkuduk and Sayakbay licenses include rubidium, strontium and cesium. Given the heavily faulted systems the Company has mapped in this geothermally active region, it appears that mineralized brines have migrated into the basin’s reservoirs, as is evident by the lithium concentrations on Condor’s blocks, as previously reported by the Ministry of Geology of the Republic of Kazakhstan.

The Company is not treating these historical estimates as current mineral resources or mineral reserves as additional drilling and testing is necessary, and a qualified person has not done sufficient work to classify the historical estimates as current mineral resources or mineral reserves. It is uncertain if further drilling will result in either area being delineated as a mineral resource or reserve. The historical lithium concentration estimates should not be relied upon as indicative of the actual lithium concentration or the likelihood that the Company will be able to achieve similar production results.

The 2027 Sayakbay capital program is expected to be determined following completion and integration of the TEM results with the gravity, magnetic, and historical geological data. Depending on the results, the Company may densify the TEM survey grid over prospective areas and/or begin preparations for a core drilling program to test the highest-priority targets. If the Sayakbay TEM program demonstrates that the method is effective and produces promising results, the Company may undertake a similar TEM survey at Kolkuduk during 2027.

The initial development plan for Sayakbay includes conducting targeted geophysical surveys, coring programs and drilling and testing two wells to verify deliverability rates, confirming the lateral extension and concentrations of lithium in the tested and untested intervals, conducting preliminary engineering for the production facilities, and preparing a mineral resource or mineral reserves report compliant with National Instrument 43-101 Standards of Disclosure for Mineral Projects. Drilling at Sayakbay is not expected to commence before 2028 and the estimated costs for the initial development plan are USD $6.7 million (CAD $9.5 million). The initial development plan for the Kolkuduk license has not been determined.

SELECTED FINANCIAL INFORMATION

Non–Controlling Interest in the PEC Project

The Company recognizes 100% of the production volumes, sales volumes, sales revenues, royalties and expenses related to the PEC Project in Uzbekistan and then allocates 49% of the comprehensive income (loss) attributable to the non-controlling interest holder. This is consistent with the accounting and disclosure in the Financial Statements. Accordingly, the production volumes, sales volumes, sales revenues, royalties, expenses and netbacks disclosed in this news release related to the PEC Project are 100% of the amounts attributable to the PEC Project, of which 51% are attributable to the Company.

Production in Uzbekistan

Total Production	Three months ended  September 30, 2026	Three months ended September 30, 2025	Change
Natural gas (Mcf)	8,964,316	5,397,457	3,566,859
Natural gas (boe)	1,494,053	899,576	594,477
Condensate (barrels)	41,706	18,401	23,305
Total (boe)	1,535,759	917,977	617,782
Daily Production
Natural gas (Mcf/d)	97,438	58,668	66%
Natural gas (boe/d)	16,240	9,778	66%
Condensate (bopd)	453	200	126%
Total (boe/d)	16,693	9,978	67%

Total Production	Nine months ended September 30, 2026	Nine months ended September 30, 2025	Change
Natural gas (Mcf)	22,510,050	16,702,386	5,807,664
Natural gas (boe)	3,751,675	2,783,731	967,944
Condensate (barrels)	109,376	73,987	35,389
Total (boe)	3,861,051	2,857,718	1,003,333
Daily Production
Natural gas (Mcf/d)	82,454	61,181	35%
Natural gas (boe/d)	13,742	10,197	35%
Condensate (bopd)	401	271	48%
Total (boe/d)	14,143	10,468	35%

Operating Netbacks in Uzbekistan

Operating Netback – Natural Gas 1,2	Natural Gas
	Three months ended September 30				Nine months ended September 30
	2026		2025		2026		2025
Sales ($000’s)	29,961		17,623		74,191		55,480
Royalties ($000’s)	(4,119)		(2,427)		(10,218)		(7,641)
Production costs ($000’s)	(10,688)		(8,324)		(29,424)		(25,305)
Transportation and selling ($000’s)	(1,047)		(634)		(2,545)		(1,948)
Operating netback ($000’s)1,2	14,107		6,238		32,004		20,586
Sales volume (Mcf)	8,400,470		5,019,603		20,988,647		15,548,613
Sales ($/Mcf)	3.56		3.51		3.53		3.57
Royalties ($/Mcf)	(0.49)		(0.48)		(0.49)		(0.49)
Production costs ($/Mcf)	(1.27)		(1.66)		(1.40)		(1.63)
Transportation and selling ($/Mcf)	(0.12)		(0.13)		(0.12)		(0.13)
Operating netback ($/Mcf)1,2	1.68		1.24		1.52		1.32

Operating Netback – Condensate 1,2	Condensate
	Three months ended September 30				Nine months ended September 30
	2026		2025		2026		2025
Sales ($000’s)	3,590		1,116		9,058		4,806
Royalties ($000’s)	(520)		(161)		(1,311)		(693)
Production costs ($000’s)	(209)		(124)		(606)		(510)
Transportation and selling ($000’s)	(16)		(7)		(40)		(28)
Operating netback ($000’s)1,2	2,845		824		7,101		3,575
Sales volume (bbl)	40,849		18,063		106,123		73,421
Sales ($/bbl)	87.88		61.78		85.35		65.46
Royalties ($/bbl)	(12.73)		(8.91)		(12.35)		(9.44)
Production costs ($/bbl)	(5.12)		(6.86)		(5.71)		(6.95)
Transportation and selling ($/bbl)	(0.39)		(0.39)		(0.38)		(0.38)
Operating netback ($/bbl)1,2	69.64		45.62		66.91		48.69

Operating netback reconciliation Uzbekistan segmented information For the three months ended September 30, 20261,2,3	Natural Gas		Condensate		Total
Sales ($000’s)	29,961		3,590		33,551
Royalties ($000’s)	(4,119)		(520)		(4,639)
Production costs ($000’s)	(10,688)		(209)		(10,897)
Transportation and selling ($000’s)	(1,047)		(16)		(1,063)
Operating netback ($000’s)1	14,107		2,845		16,952
For the three months ended September 30, 20251,2,3
Sales ($000’s)	17,623		1,116		18,739
Royalties ($000’s)	(2,427)		(161)		(2,588)
Production costs ($000’s)	(8,324)		(124)		(8,448)
Transportation and selling ($000’s)	(634)		(7)		(641)
Operating netback ($000’s)1	6,238		824		7,062

Operating netback reconciliation Uzbekistan segmented information For the nine months ended September 30, 2026 1,2,3	Natural Gas		Condensate		Total
Sales ($000’s)	74,191		9,058		83,249
Royalties ($000’s)	(10,218)		(1,311)		(11,529)
Production costs ($000’s)	(29,424)		(606)		(30,030)
Transportation and selling ($000’s)	(2,545)		(40)		(2,585)
Operating netback ($000’s)1	32,004		7,101		39,105
For the nine months ended September 30, 2025 1,2,3
Sales ($000’s)	55,480		4,806		60,286
Royalties ($000’s)	(7,641)		(693)		(8,334)
Production costs ($000’s)	(25,305)		(510)		(25,815)
Transportation and selling ($000’s)	(1,948)		(28)		(1,976)
Operating netback ($000’s)1	20,586		3,575		24,161

1	Operating netback is a non-GAAP measure and is a term with no standardized meaning as prescribed by GAAP and may not be comparable with similar measures presented by other issuers. See “Non-GAAP Financial Measures” in this news release. The calculation of operating netback is aligned with the definition found in the Canadian Oil and Gas Evaluation Handbook.
2	Amounts and per unit measures are only presented for the Uzbekistan segment.
3	Reconciliation to the respective Financial Statement amount for each netback component for the Uzbekistan segment.

NON-GAAP FINANCIAL MEASURES

The Company refers to “operating netback” in this news release, a term with no standardized meaning as prescribed by GAAP and which may not be comparable with similar measures presented by other issuers. This additional information should not be considered in isolation or as a substitute for measures prepared in accordance with GAAP. Operating netback is calculated as sales less royalties, production costs and transportation and selling costs on a dollar basis and divided by the sales volume for the period on a per Mcf basis for natural gas and per boe basis for condensate. This non-GAAP measure is commonly used in the oil and gas industry to assist in measuring operating performance against prior periods on a comparable basis and has been presented to provide an additional measure to analyze the Company’s sales on a per unit basis and the Company’s ability to generate funds.

BARRELS OF OIL EQUIVALENT ADVISORY

References herein to barrels of oil equivalent (“boe”) are derived by converting gas to oil in the ratio of six thousand standard cubic feet (“Mcf”) of gas to one barrel of oil based on an energy conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf to 1 barrel, utilizing a conversion ratio at 6 Mcf to 1 barrel may be misleading as an indication of value, particularly if used in isolation.

FORWARD-LOOKING STATEMENTS

Certain statements in this news release constitute forward-looking information under applicable securities legislation. Such statements are generally identifiable by the terminology used, such as “anticipate”, “expect”, “plan”, “believe”, “intend”, “estimate”, “may”, “will”, “could”, “would”, “should”, “potential”, “prospective”, “pending”, “ongoing”, “future”, “forecast”, “target”, “continue”, “capable”, “schedule”, “remain” or other similar wording. Forward-looking information in this news release includes, but is not limited to, information concerning: the timing and ability of the Company to execute growth and sustainability strategies including the financing for these activities; the timing and ability to realize sustainable growth for reserves, production, and cashflow; the timing and ability to build strong, near-term shareholder value; the timing and ability to conduct the planned multi-well drilling program in 2026 and 2027; the timing and ability of the identified drilling locations to be drilled and become producing wells; the timing and ability to complete, test and produce the new wells; the timing and ability to target previously undeveloped reservoirs and the timing and ability to generate sustained production growth; the timing and ability to produce commercially recoverable gas outside of conventionally targeted four-way structural closures; the timing and ability of new and stratigraphic play types to become part of the Company’s next growth engine; the timing and ability of A-22 test results to open significant areas of prospective drilling acreage at Andakli and derisk the commerciality of a stratigraphic horizontal well development program; the timing and ability to drill numerous Andakli follow up wells in 2027; the timing and ability to drill NS-14 and penetrate the deeper Jurassic clastic stacked reservoir sands; the timing and ability for NS-14 to reach the targeted depth of up to 3000 meters and the timing and ability to evaluate the full extent of the stratigraphic column; the timing and ability to drill follow up wells at North Syuzma; the timing and ability to perform an acid stimulation on K-51; the timing and ability to target separate carbonate reservoirs from a single surface location; the timing and ability to utilize proven technology to realize higher expected production rates; the timing and ability to realize increased reservoir contact, reduced well drilling and tie-in costs and a smaller environmental footprint; the timing and ability to implement alternate methods to lift fluids from K-50 and tie K-50 into the gas sales pipeline; the timing and ability to design, construct and commission the Compressor Station; the timing and ability of the Compressor Station to increase production and reduce back pressure; the timing and ability to substantially complete the MDWP under the PEC Project; the timing and ability to maintain compliance with contractual provisions that allow for termination of the PEC Project; the timing and ability to receive and utilize the natural gas allocations as feed gas for the planned modular LNG production facilities; the Company’s expectations in respect of the future uses of LNG; the timing and ability to acquire, transport and construct modular LNG production facilities; the timing and ability to obtain funding for the construction of modular LNG production facilities on favourable terms, or at all; the timing and ability to secure third-party financing for the First LNG Facility; the timing and ability to enter into one or more partnerships (or other joint venture structures) at the Company’s sites in Kazakhstan where it has already secured feed gas allocations; the timing and ability to produce and deliver LNG to displace diesel fuel usage in Central Asia; the Company’s expectations regarding reduction in CO2 emissions based on productivity of the LNG facilities; the timing and ability to transport the First LNG Facility to Kazakhstan; the timing and ability to commence LNG production; the estimated costs to complete the First LNG Facility construction and commissioning; the timing and ability to construct the First LNG Facility at the Saryozek Site prior to August 2030 as required under the related land agreement; the timing and ability to liquefy natural gas to produce LNG; the timing and ability to confirm LNG volume commitments with potential end-users; the timing and ability of the First LNG Facility to produce 48,000 gallons of LNG per day; the timing and ability of the Company to construct two additional modular LNG facilities capable of producing 48,000 gallons of LNG per day at the First LNG Facility site; the timing and ability to finalize LNG off-taker agreements; the planned use of proceeds from the 2026 Debentures offering including the Compressor Station, First LNG Facility, working capital and general corporate purposes; the potential for the Sayakbay and Kolkuduk license to contain commercial deposits; the timing and ability to integrate the aeromagnetic survey results with historical gravity data and regional geological information; the timing and ability of the Sayakbay sediment to be suitable for hosted copper mineralization; the timing and ability to advance an integrated geophysical program at Sayakbay and incorporated the data into a three-dimensional density model; the timing and ability to refine the interpretation of various license area features; the timing and ability of UAV magnetic surveys to further define the area geometries, faults, formations and other structural features; the timing and ability to complete, process and interpret the TEM survey; the timing and ability to map prospective geoelectric horizons and structural features and to improve the identification and ranking of potential mineralized targets; the timing and ability to correlate preliminary results with historical well resistivity data; the timing and ability to identify geoelectric layers and lateral resistivity variations; the timing and ability to determine and complete the 2027 Sayakbay capital program; the timing and ability to densify the TEM survey grid; the timing and ability to begin preparations and to conduct a core drilling program; the timing and ability to undertake a TEM survey at Kolkuduk during 2027; the timing and ability of the Company to fund, permit and complete planned activities at Sayakbay; the timing and estimated costs of the initial development plan for Sayakbay; the timing and ability of the Company to generate a report in compliance with National Instrument 43-101 Standards of Disclosure for Mineral Projects; the timing and ability to determine, fund, permit and execute an initial exploration or development plan for the Kolkuduk license; the timing and ability to obtain the required Government Approvals and complete the sale of the Turkish Properties; the potential consequences of failing to obtain Government Approval to complete the sale of the Turkish Properties, including the right of either party to terminate the SPA; the accuracy of the projections and timing with respect to natural gas and condensate production; expected markets, prices and costs for future natural gas and condensate sales; the timing and ability of the Company to obtain various approvals and conduct its planned exploration and development activities; the timing and ability to access natural gas pipelines; the timing and ability to access domestic and export sales markets; the accuracy of the anticipated capital expenditures; forecasted capital and operating budgets and cashflows; anticipated working capital; sources and availability of financing for potential budgeting shortfalls; the timing and ability to obtain future funding on favourable terms, if at all; the potential for additional contractual work commitments to be significant; the ability to satisfy and fund the contractual work commitments; projections relating to the adequacy of the Company’s provision for taxes; the expected reporting impacts of adopting amendments to IFRS accounting policies; and treatment under governmental regulatory regimes and tax laws.

This news release also includes forward-looking information regarding health risk management including, but not limited to: travel restrictions including shelter in place orders, curfews and lockdowns which may impact the timing and ability of Company personnel, suppliers and contractors to travel internationally, travel domestically and to access or deliver services, goods and equipment to the fields of operation; the risk of shutting in or reducing production due to travel restrictions, government orders, crew illness, and the availability of goods, works and essential services for the fields of operations; decreases in the demand for oil and gas; decreases in the prices of natural gas, condensate and crude oil; potential for gas pipeline or sales market interruptions; the risk of changes to foreign currency controls, availability of foreign currencies, availability of hard currency, and currency controls or banking restrictions which restrict or prevent the repatriation of funds from or to foreign jurisdiction in which the Company operates; the Company’s financial condition, results of operations and cash flows; access to capital and borrowings to fund operations and new business projects on terms acceptable to the Company; the timing and ability to meet financial and other reporting deadlines; and the inherent increased risk of information technology failures and cyber-attacks.

By its very nature, such forward-looking information requires Condor to make assumptions that may not materialize or that may not be accurate including, but not limited to, the assumptions that: the Company will be able to secure necessary drilling rigs, support services, and off-taker agreements in a timely manner; the Company will be able to manage its working capital deficiency; the Company will be able to drill the planned wells and install and commission the Compressor Station; the Compressor Station will perform substantially in accordance with the simulation work conducted by an independent third-party engineering company; the results of the A-22 test and other recently drilled wells will be indicative of the results of future follow up wells; the Company will be able substantially complete the MDWP and comply with the terms of the PEC Project; the Company will be able to secure third-party financing for the First LNG Facility; the Company will be able to enter into one or more partnerships (or other joint venture structures) at its sites in Kazakhstan where it has already secured feed gas allocations; the engineering design and final investment decisions for additional LNG facilities will proceed as planned; the First LNG Facility will arrive in Kazakhstan and be commissioned in accordance with the Company’s current schedule; the Company will complete construction of its LNG facilities and that the LNG feed gas for such facilities will be supplied; the Government of Kazakhstan will continue to support energy security solutions, including LNG development, that provide viable diesel fuel alternatives; the Company’s additional drilling and testing will be successful in verifying deliverability rates and confirming mineral concentrations; commodity prices, foreign currency exchange rates and interest rates will be consistent with the Company’s expectations; the Company will be able to fund its initiatives through a combination of cash on hand, increased cashflows, debt or equity financing, asset sales, or other arrangements; the Company will be able to manage liquidity and capital expenditures through budgeting and authorizations for expenditures; the Company will be able to manage health, safety, and operational risks through existing precautions and guidelines; the Company will be able to adapt to changing trade policies, tariffs, and restrictions; and the Company will be able to manage the impact of geopolitical instability and sanctions. Forward-looking information is subject to both known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such information. Such risks and uncertainties include, but are not limited to: regulatory changes including changes to environmental regulations; the timing of regulatory approvals; the risk that actual minimum work programs will exceed the initially estimated amounts; the results of exploration and development drilling and related activities; the risk that prior lithium testing results may not be indicative of future testing results or actual results; the risk of imprecision of reserves estimates and ultimate recovery of reserves; the risk that historical production and testing rates may not be indicative of future production rates, capabilities or ultimate recovery; the risk that the historical composition and quality of oil and gas does not accurately predict its future composition and quality; general economic, market and business conditions; risks relating to the uncertainty related to marketing and transportation; competitive action by other companies; fluctuations in oil and natural gas prices; the effects of weather and climate conditions; fluctuation in interest rates and foreign currency exchange rates; the ability of suppliers to meet commitments; actions by governmental authorities, including increases in taxes, tariffs, levies and fees; decisions or approvals of administrative tribunals and the possibility that government policies or laws may change or the possibility that government approvals may be delayed or withheld; risks associated with oil and gas operations, both domestic and international; and other factors, many of which are beyond the control of Condor.

These risk factors are discussed in greater detail in filings made by Condor with Canadian securities regulatory authorities including the Company’s most recent Annual Information Form, which may be accessed through SEDAR+ at www.sedarplus.ca.

Readers are cautioned that the foregoing list of factors affecting forward-looking information is not exhaustive. The forward-looking information contained in this news release is made as of the date of this news release and, except as required by applicable law, Condor does not undertake any obligation to update publicly or to revise any of the included forward-looking information, whether as a result of new information, future events or otherwise. The forward-looking information contained in this news release is expressly qualified by this cautionary statement.

ABBREVIATIONS
The following is a summary of abbreviations used in this news release:
Mcf  Mcf/d MMcf/d bbl bopd boe boe/d MT IFRS GAAP CAD USD LNG Türkiye Kazakhstan Uzbekistan 3-D EPC NE NW USGS	Thousands of standard cubic feet Thousands of standard cubic feet per day Millions of standard cubic feet per day Barrels of oil Barrels of oil per day Barrels of oil equivalent Barrels of oil equivalent per day Metric tonnes International Financial Reporting Standards Generally Accepted Accounting Principles Canadian Dollars United States Dollars Liquefied natural gas Republic of Türkiye Republic of Kazakhstan Republic of Uzbekistan Three dimensional Engineering, Procurement and Construction North-East North-West United States Geological Survey

The TSX does not accept responsibility for the adequacy or accuracy of this news release.

For further information, please contact Don Streu, President and CEO or Sandy Quilty, Vice President of Finance and CFO at 403-201-9694.

CALGARY, Alberta, Nov. 12, 2026 (GLOBE NEWSWIRE) — Atlas Energy Corp. (“Atlas” or the “Company”) (TSXV: ATLE), is pleased to announce its financial and operating results for the three and nine months ended September 30, 2026, highlighted by the completion of its first royalty acquisition and the commencement of royalty revenue.

Selected financial and operational information is outlined below and should be read in conjunction with Atlas’ unaudited condensed interim consolidated financial statements and management’s discussion and analysis (“MD&A”) for the three and nine months ended September 30, 2026, which are available on the Company’s SEDAR+ profile at www.sedarplus.ca.

Third Quarter Highlights

• Completed first royalty acquisition: On September 24, 2026, Atlas completed the acquisition of a gross overriding royalty on producing oil and gas assets in Southwest Alberta for $15.0 million, funded entirely from existing cash resources.
• Commenced royalty revenue: The Company generated $141,000 in royalty revenue during its first seven days of royalty ownership, with average royalty production of 235 barrels of oil equivalent per day (“boe/d”), excluding sulphur production of approximately 11 metric tonnes per day.
• Successfully exited the TSXV Sandbox: Following completion of the royalty acquisition, Atlas satisfied the applicable TSXV Sandbox exit conditions and commenced trading as a regular Tier 2 issuer on September 29, 2026.
• Maintained a debt-free balance sheet: Atlas ended the quarter with approximately $9.2 million in cash and cash equivalents, working capital of $8.9 million and no debt.

President’s Message

“The third quarter marked an important milestone for Atlas as we completed our first royalty acquisition, established our initial source of royalty revenue and successfully exited the TSXV Sandbox,” said Mark Hodgson, Atlas Energy’s President and Chief Executive Officer. “Our $15 million investment in producing Alberta oil and gas assets demonstrates our ability to structure and execute transactions aligned with our investment strategy and provides a revenue-generating foundation from which to pursue our international growth ambitions.”

“While our third quarter operating results reflect only seven days of royalty ownership, we enter the next stage of Atlas’s development with an established royalty revenue base, approximately $9.2 million in cash and no debt at quarter-end.”

“International royalty and streaming opportunities remain our principal growth focus. We are advancing our pipeline with the objective of converting these opportunities into completed transactions that diversify our asset base, expand our sources of long-term revenue and deliver attractive risk-adjusted returns for shareholders. Our first acquisition is an important step in building Atlas, and our priority is to build on that momentum through disciplined execution of our international strategy.”

Royalty Acquisition and Operating Results

On September 24, 2026, Atlas acquired a newly created gross overriding royalty on the working interest of Caledonian Midstream Corp., a privately held Alberta oil and gas producer in producing assets located in Southwest Alberta.

The royalty entitles Atlas to payments calculated on 9% of the producer’s working interest share of petroleum substances produced and sold from the royalty lands, including crude oil, natural gas, natural gas liquids and sulphur. The royalty is free of operating and development costs, subject only to attributable third-party transportation costs.

The 9% royalty remains in effect until cumulative royalty payments to Atlas reach $30.0 million, representing twice the initial investment, after which the royalty decreases to 4%, or 2% if the threshold is reached within five years of closing.

During the seven days following closing, Atlas generated royalty revenue of $141,000, including $87,000 from sulphur, $28,000 from natural gas liquids, $16,000 from crude oil and $10,000 from natural gas.

Average daily royalty production over this period was 235 boe/d, consisting of approximately 19 barrels per day of crude oil, 61 barrels per day of natural gas liquids and 929 Mcf per day of natural gas. Sulphur production attributable to the royalty averaged approximately 11 metric tonnes per day.

As the acquisition closed on September 24, 2026, these results reflect only seven days of royalty ownership and may not be representative of future production or revenue levels.

Financial Results and Liquidity

Atlas reported a net loss of $0.9 million for the three months ended September 30, 2026, compared with a net loss of $0.7 million in the corresponding period of 2025. The current quarter’s results primarily reflect corporate general and administrative expenses and ongoing business development activities, partially offset by the commencement of royalty revenue.

At September 30, 2026, Atlas had cash and cash equivalents of $9.2 million, working capital of $8.9 million and no outstanding debt, following the completion of its $15.0 million royalty acquisition. The Company continues to evaluate additional royalty and streaming opportunities in international markets and selectively in North America.

About Atlas Energy Corp.

Atlas Energy Corp. is an international upstream royalty and streaming company focused on the acquisition and management of a diversified portfolio of oil and gas royalty and streaming interests across key global markets.

For additional information please contact:

Mark Hodgson President & Chief Executive Officer

Travis Doupe Chief Financial Officer

www.atlas-corp.ca
info@atlas-corp.ca
1(403) 680-9626

Reader Advisories

Conversion of Natural Gas to Barrels of Oil Equivalent

Natural gas volumes have been converted to barrels of oil equivalent (“boe”) using the industry standard conversion ratio of six thousand cubic feet of natural gas to one barrel of oil (6 Mcf:1 bbl). Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. Sulphur production is excluded from boe calculations.

Non-GAAP and Other Financial Measures

This news release references working capital, a capital management measure that does not have a standardized meaning under IFRS Accounting Standards and may not be comparable to similarly named measures presented by other issuers. Working capital is calculated as total current assets less total current liabilities. At September 30, 2026, current assets were $9.564 million and current liabilities were $0.696 million, resulting in working capital of $8.868 million. Management uses working capital to assess the Company’s liquidity and its ability to fund its operating requirements. Additional information regarding this measure is contained under the heading “Non-GAAP and Other Financial Measures” in the Company’s MD&A for the three and nine months ended September 30, 2026, which is incorporated by reference into this news release and is available under the Company’s profile on SEDAR+ at www.sedarplus.ca.

Forward-Looking and Cautionary Statements

This news release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws (collectively, “forward-looking information”). Forward-looking information includes, but is not limited to, statements concerning: the Company’s business strategy and objectives, including its focus on international royalty and streaming opportunities and the selective evaluation of opportunities in North America; the anticipated benefits and future performance of the Company’s existing royalty interest, including the expectation that it provides a revenue-generating foundation for the Company’s growth; the evaluation and advancement of the Company’s pipeline of potential royalty and streaming opportunities and the Company’s objective of converting those opportunities into completed transactions that diversify its asset base, expand its sources of long-term revenue and deliver attractive risk-adjusted returns; the Company’s ability to identify, negotiate, structure, finance and complete additional royalty and streaming transactions; its capital allocation strategy; and its anticipated liquidity and financing requirements.

Forward-looking information is based on management’s current expectations, estimates and assumptions, including assumptions regarding: future commodity prices, including the price of sulphur; production volumes from, and the continued operation of, the assets underlying the Company’s royalty interest, including the completion of planned well reactivations; the performance and financial condition of operators, royalty payors and other counterparties, including the timely payment of amounts owing to the Company; the availability of suitable investment opportunities on commercially acceptable terms; the willingness of prospective counterparties to negotiate and complete transactions; the Company’s ability to access capital when required; foreign exchange rates; and prevailing regulatory, political and economic conditions. Although management believes these assumptions are reasonable as of the date of this news release, there can be no assurance that they will prove to be correct.

Forward-looking information is subject to known and unknown risks, uncertainties and other factors that could cause actual results, performance or achievements to differ materially from those expressed or implied. These include, but are not limited to: fluctuations in commodity prices and production volumes; the current concentration of the Company’s royalty revenue in a single royalty interest and a single royalty payor; operational risks affecting the assets underlying the Company’s royalty interest; dependence on third-party operators and royalty payors; counterparty credit and performance risk; the possibility that prospective transactions may not proceed, that negotiations may not result in definitive agreements or that suitable investment opportunities may not be available on acceptable terms; the availability and cost of financing and the dilution that may result from future equity financings; the risks of investing in international jurisdictions; litigation and claims; changes in regulatory, tax and fiscal regimes; geopolitical and economic uncertainty; and other risks associated with the Company’s business and operations.

Readers are cautioned not to place undue reliance on forward-looking information. Additional risks and uncertainties are described under the headings “Risks and Uncertainties” and “Cautionary Statement Regarding Forward-Looking Information” in the Company’s MD&A for the three and nine months ended September 30, 2026 and under the heading “Risk Factors” in the Company’s Annual Information Form for the year ended December 31, 2025, each of which is available under the Company’s profile on SEDAR+ at www.sedarplus.ca. The forward-looking information in this news release is made as of the date of this news release and is expressly qualified by this cautionary statement. The Company undertakes no obligation to update or revise such information, whether as a result of new information, future events or otherwise, except as required by applicable law.

All dollar amounts are expressed in Canadian dollars unless otherwise indicated.

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this news release.

PANAMA CITY, Nov. 12, 2026 (GLOBE NEWSWIRE) — Copa Holdings, S.A. (NYSE: CPA) today released preliminary passenger traffic statistics for October 2026:

Copa Holdings (Consolidated)	October 2026		October 2025		% Change
ASM (mm) (1)	3,125.3		2,803.0		11.5%
RPM (mm) (2)	2,731.8		2,443.6		11.8%
Load Factor (3)	87.4%		87.2%		0.2 p.p.

1. Available seat miles – represents the aircraft seating capacity multiplied by the number of miles the seats are flown.
2. Revenue passenger miles – represents the number of miles flown by revenue passengers
3. Load factor – represents the percentage of aircraft seating capacity that is utilized

For October 2026, Copa Holdings’ capacity (ASMs) increased by 11.5%, while system-wide passenger traffic (RPMs) increased by 11.8% compared to 2025. As a result, the system load factor for the month was 87.4%, 0.2 percentage points higher than in October 2025.

Copa Holdings is a leading Latin American provider of passenger and cargo services. The Company, through its operating subsidiaries, provides service to countries in North, Central, and South America and the Caribbean. For more information, visit ir.copaair.com.

CPA-G

Investor Relations
investor.relations@copaair.com