YE 2025 Annual Report

2025 ANNUAL REPORT

QUESTERRE ENERGY CORPORATION

QUESTERRE ENERGY CORPORATION is an energy technology and innovation company focused on responsibly developing oil and gas resources. It is leveraging its expertise gained through early exposure to low permeability reservoirs to acquire significant high-quality resources. We believe we can successfully transition our energy portfolio. With new clean technologies and innovation to responsibly produce and use energy, we can sustain both human progress and our natural environment.

Questerre is a believer that the future success of the oil and gas industry depends on a balance of economics, environment and society. We are committed to being transparent and are respectful that the public must be part of making the important choices for our energy future. Questerre's common shares are traded on the Toronto Stock Exchange and Oslo Stock Exchange under the symbol QEC.

President's Message

I have spent thirty years operating in places where the geology is difficult, the politics are complex, and the path forward is rarely straight - Turkey, Ukraine, Georgia, Quebec, and Papua New Guinea. Each of those experiences taught me something that the next one required. Looking back, I can see the thread clearly now, even when I couldn't at the time.

That thread has brought our experienced international board and team here.

Since the oil crisis of the 1970s, the industry has pursued a way to unlock oil shale - one of the largest hydrocarbon systems ever identified, with resource potential measured in trillions of barrels(1). Driven by energy security concerns that have once again come to the forefront, this effort has spanned decades. Yet oil shale has consistently resisted commercial development. The reasons are geological, technological, economic, and political - all at once. That is exactly the kind of problem we have been preparing to solve.

This year, Questerre marked a meaningful step toward solving this problem. Through the acquisition of PX Energy and the consolidation of our ownership in Red Leaf Resources, with full control of the patented HCCO® technology, we now have the assets, the platform, and the technical capabilities we believe we need to advance this resource toward commercial development.

This is more than a turnaround opportunity. It transforms Questerre into an oil shale operator with production and cash flow, extensive infrastructure, and a highly capable team experienced in oil shale development. While we optimize the existing operations and technology, the acquisition provides a unique platform to advance the next generation of technology in an operating environment rather than through stand-alone pilot projects.

Since closing the PX Energy acquisition, our focus has been on stabilizing operations, improving performance, implementing safety reporting, and reducing costs. We have identified $10 million in annual savings and are targeting a further $10 million through operational efficiencies.

Concurrently, we plan to test a key element of the new process inside the existing Petrosix retort vessel in the second quarter of this year. With success, this could improve heat and mass balance, increase product yields and reduce internal fuel consumption for the existing technology. Based on our budget, this can be funded through internally generated cash flow as we anticipate this could cost less than 10% of a field pilot. It can also be implemented much sooner than a new field pilot. This demonstration at scale would be a significant step toward transitioning to the new technology, and ultimately commercialization.

The energy shortage in Quebec is growing and public debate on local gas production has reopened(2). While development has been blocked by policy restrictions, the current energy crisis and growing focus on security of supply are reinforcing the importance of local resources. Independent studies, including a peer-reviewed assessment by CIRAIG(3) (the International Reference Center for Life Cycle Assessment and Sustainable Transition) and the Government of Quebec's Strategic Environmental Assessment, support the view that impacts can be responsibly managed. Based on this work, we believe this project could be one of the most significant opportunities to deliver a net reduction in greenhouse gas emissions in Canada.

What gives me confidence is not just the assets; it is the people. In Brazil, we inherited a team of close to one thousand people who have successfully operated one of the world's most complex oil shale processing facilities for forty years. They did not lack capability. They lacked strategic direction. We have addressed that by providing senior leadership with deep refining expertise. They will work alongside an organization that already knows this technology better than almost anyone on earth. In Quebec, we bring over thirty years of accumulated knowledge - the geology, the legal background, the political landscape -and the relationships that only come with that kind of history.

Questerre has entered a new phase. With a strengthened operational platform, growing production, and full control of our technology, we are focused on disciplined execution - delivering value from our Brazilian operations while advancing our pathway toward commercial oil shale development.

Highlights

Transformation to an Operating Platform

Completed the acquisition of PX Energy, establishing Questerre as an oil shale operator with production, infrastructure, and a technical team experienced in oil shale development.

Control of Proprietary Technology

Consolidated ownership of Red Leaf Resources and secured full control of the proprietary HCCO® technology - a low-temperature oxy-fuel process that converts organic material into liquid hydrocarbons with integrated carbon capture and minimal water use.

Quebec: Resource Position and Value Restructuring

Public debate re-opened on the Quebec Utica, one of the most significant undeveloped natural gas resources in Eastern Canada. Through a corporate reorganization, approximately 95% of the value associated with this project is now reflected in a preferred tracking share, for which we are evaluating a separate public listing.

Operational Improvements and Cost Reductions

Restructured management and cost initiatives PX Energy delivered close to $3 million in adjusted funds from operating and approximately $5 million in cash flow used in operating activities in the fourth quarter.

Production and Financial Growth

Fourth quarter production increased to 7,000 boe per day. Revenue grew to $77.1 million for the year -

$45.4 million from Canadian operations and $31.7 million from Brazil following the PX Energy acquisition with net cash from operating activities of $12.6 million and adjusted funds flow from operations of $15.7 million.

Oil Shale

Our goal is to restructure PX Energy into a cash-flowing business supported by long-life reserves and a sustainable balance sheet.

Prior to our acquisition, PX Energy was generating average monthly adjusted operating cash flows of approximately $0.3 million, a level that contributed to its financial distress. In our first quarter after closing, operational improvements drove that figure to just over $1.0 million per month. We assumed full management control on January 3, 2026, and anticipate the quarter ending March 31, 2026, will continue to show further material improvement. Strengthening oil prices, if sustained, will add to that. Fuel oil, which represents approximately 75% of our revenue, had an official posted price of US$140 per barrel as of March 24, 2026.

The PX Energy Petrosix facility in São Mateus do Sul, originally developed by Petrobras, represents hundreds of millions of dollars of invested capital. The access to an existing mine, utilities, and processing facilities creates the opportunity to demonstrate the next generation HCCO technology at a substantially lower cost than we originally planned. Utilizing the existing processing facility for this test further reduces costs. It should provide an important proof point at near-commercial scale while optimizing and improving profitability of the existing operations.

We are also pursuing opportunities to grow revenue through debottlenecking initiatives and optimizing fuel inputs. Approximately one-third of volumes are derived from processing waste oil, which takes advantage of excess heat from the retort. This is a competitive business with attractive margins and meaningful expansion potential.

Processing this waste oil reduces our overall emissions footprint. In addition, we are creating a permanent forest reserve as part of our mine reclamation plan, contributing to biodiversity in the area and creating a carbon sink. The HCCO technology embeds carbon capture and allows us to reduce our environmental footprint further. We will look at potential carbon sequestration reservoirs to support future development with this technology to operate at low net emissions.

The acquisition included legacy commercial and financial issues with vendors, creditors, and potential joint venture partners. Some matters may require litigation to resolve. We are managing these actively as part of the broader restructuring.

Quebec

Our Utica shale gas discovery remains one of the most significant undeveloped gas resources in Eastern Canada. The province has become a net importer of power for the last three months(4), reflecting increasing demand and constraints on supply.

Globally, many jurisdictions facing similar challenges have turned to natural gas as part of their policy response. Germany is increasing LNG imports. Argentina is accelerating domestic shale development to become an LNG supplier(5). Quebec has the same opportunity, and we have the resource to meet it.

We continue to advance both a legal and political pathway to development. During the year, we completed the questioning of key government witnesses, including current and former members of the government. In January, the Court approved Questerre to proceed as a test case to expedite the process. Subject to any appeals and remaining pre-trial matters, we expect a hearing date to be set this year.

During the year, we also received notice from the Government of Quebec of its intention to enforce Bill 21, including requirements related to well abandonment and demonstrating liquidity of approximately $11 million. 75% of these costs are to be covered by the Government under Bill 21. We have this liquidity and are working to meet these requirements.

Operating and Financial

Our volumes increased significantly this year. The tie-in of three (1.5 net) wells at Kakwa North and the addition of PX Energy production following the close of the acquisition at the end of the third quarter drove average production to 3,711 boe per day, compared to 1,756 boe per day last year. In the fourth quarter, production averaged over 7,000 boe per day, including over 4,400 boe per day from Brazil.

Revenue increased to $77.1 million for the year - $45.4 million from Canadian operations and $31.7 million from Brazil. Higher volumes helped offset lower Canadian commodity prices. We reported adjusted funds flow from operations of $15.7 million, excluding $3.3 million of acquisition-related costs.

Our consolidated working capital position reflects the $52 million working capital deficit and non-recourse debt assumed as part of the PX Energy acquisition. With cost reduction initiatives underway and commodity prices above US$65 per barrel, we expect this deficit to be materially reduced by year-end.

Outlook

Our near-term priorities are clear: stabilize and grow cash flow from Brazilian operations, prove up the new technology at near-commercial scale, and pursue both legal and political pathways to development in Quebec.

The HCCO® pilot, using the existing Petrosix facility, will provide a critical proof point at a substantially lower costs than a greenfield pilot. Success would represent a significant step toward converting oil shale resources into reserves and establishing the commercial case for the technology. It also improves the efficiency of our existing operations and improves our margins.

In Quebec, recent public commentary and policy discussions reflect a growing recognition that local natural gas has a role to play in addressing the province's energy needs(6). We are encouraged by that shift and continue to work toward a hearing date being set this year.

The opportunity in front of us is real. We are more committed than ever to delivering it.

Michael Binnion

President and Chief Executive Officer

Forward Looking Advisory

Please refer to the section Forward Looking Statements in the Management Discussion and Analysis regarding the forward-looking information provided in this President's Message.

Footnotes:

1. https://www.usgs.gov/centers/central-energy-resources-science-center/science/oil-shale

2. https://www.journaldemontreal.com/2026/03/21/geopolitique-de-lenergie

3. https://questerre.wpenginepowered.com/wp-content/uploads/2024/12/CIRAIG-Clean-gas-initiative-LCA-wo-appendices.pdf

4. https://www.theglobeandmail.com/business/article-hydro-quebec-electricity-net-importer-water-reservoirs-demand/

5. https://www.offshore-energy.biz/germanys-sefe-nails-down-8-year-lng-offtake-with-south-american-firm/

6. https://www.lesaffaires.com/bourse/actualites-boursieres/il-ne-faut-pas-fermer-la-porte-a-lexploitation-du-gaz-naturel-dit-le-pdg-de-la-banque-nationale/

Environmental, Social and Governance

Questerre believes the oil and gas industry can go from laggards to leaders on the global environment.

From today to 2050, the world's population is estimated to grow from 7.6 billion to almost 10 billion who will expect a better standard of living(1). We believe providing the increased energy needed tomorrow, with lower environmental impacts than today, is the challenge of our times. Transforming our energy consumption to lower emissions is essential to meeting this challenge.

Our project in Quebec was designed with a goal to significantly reduce emissions associated with the production of natural gas. We are also assessing how to reduce other environmental impacts. It is an example of the steps needed to meet this global challenge.

It requires a new way of thinking to become leaders on environmental issues. Our industry plays a vital role in today's energy systems. We have the experience, expertise, capital and technology to help address the world's energy and environmental challenges. Delivering on projects like ours in Quebec is just one example of how our industry can be leaders on transforming our global energy systems.

Questerre is proactively working with communities and First Nations for local benefits. For example, we have committed to share of our profits with them. We have also engaged with local First Nations to include them in our contracting and benefits program.

People know they need energy to maintain progress for their families and communities. They want to know the providers of that energy are being responsible and sustainable in the way it is supplied.

1. https://www.un.org/en/desa/world-population-projected-reach-98-billion-2050-and-112-billion-2100#:~:text=The%20current%20world%20population%20of,Nations%20report%20being%20launched%20today

Management's Discussion and Analysis

This Management's Discussion and Analysis ("MD&A") was prepared as of March 31, 2026, and should be read in conjunction with the audited consolidated financial statements of Questerre Energy Corporation ("Questerre" or the "Company") as at and for the years ended December 31, 2025 and 2024. Additional information relating to Questerre, including Questerre's Annual Information Form for the year ended December 31, 2025, dated March 31, 2026 ("AIF"), is available on SEDAR+ under Questerre's profile at https://www.sedarplus.ca.

Questerre is an energy technology and innovative company actively involved in the acquisition, exploration and development of oil and gas projects, and, in specific, non-conventional projects such as tight oil, oil shale, shale oil and shale gas. Questerre is committed to the economic development of its resources in an environmentally conscious and socially responsible manner. The Company's Class "A" Common voting shares ("Common Shares") are listed on the Toronto Stock Exchange and the Oslo Stock Exchange under the symbol "QEC". The Company's Series 2 Preferred Shares are not currently listed for trading.

Basis of Presentation

Questerre presents figures in the MD&A using accounting policies within the framework of International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board, representing generally accepted accounting principles ("GAAP"). All financial information is reported in Canadian dollars, unless otherwise noted.

Forward-Looking Statements

Certain statements contained within this MD&A constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified using the use of words such as "anticipate", "assume", "believe", "budget", "can", "commitment", "continue", "could", "estimate", "expect", "forecast", "foreseeable", "future", "intend", "may", "might", "plan", "potential", "project", "will" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Management believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. These statements speak only as of the date of this MD&A.

This MD&A contains forward-looking statements including, but not limited to, those pertaining to the following:

• anticipated benefits of the Acquisition to the Company and its shareholders, including any operational and economic synergies;

• the issuance of the Common Shares as consideration for the Acquisition;

• the consideration payable pursuant to the Acquisition;

• the appointment of an auditor to resolve any disputes related to the assessment of the closing working capital pursuant to the Acquisition;

• the assumption of convertible promissory notes;

• the interest payable on the senior secured callable bonds issued by FRBH and any extensions thereof;

• the use of arbitration to resolve disputes pursuant to the term sheet with the prospective joint venture partner;

• the completion of the transactions contemplated in the BCA, if closed;

• the assumption of debt in connection with the Acquisition;

• the achievement of the performance milestones attached to the contingent consideration payable pursuant to the Acquisition, and the timing thereof, if at all;

• the utilization of Red Leaf technology;

• drilling plans and the development and optimization of producing assets;

• the impact of drilling at Kakwa Central on overall well recoveries;

• the judicial plans to achieve a hearing of the Company's claim made in connection with Quebec's

  Bill 21 and the seeking of a date for the main hearing in 2026;

• working collaboratively to find a political and business solution with the Government of Quebec;

• future production of oil, natural gas and natural gas liquids;

• the enhancement of existing production through workovers and expanding the pilot secondary recovery scheme while assessing future drilling locations;

• future commodity prices in light of decisions by OPEC and its allies, including Saudi Arabia and Russia on production levels, the war in Ukraine, and the conflict in the Middle East;

• legislative and regulatory developments in the Province of Quebec;

• the transfer of wells drilled in 2025 from the proved undeveloped to the proved producing category;

• the Company plans for a carbon storage pilot project under Bill 21 and the funding thereof;

• hedging policy;

• liquidity and capital resources;

• the financial liquidity of PX Energy;

• the assessment of options to demonstrate the Red Leaf technology;

• the Company's plans to utilize the Red Leaf technology for its project in Jordan;

• discussions with the Government of Jordan for a concession agreement;

• the restructuring of the balance sheet and the optimization of the operations of PX Energy;

• the Company's compliance with the terms of its credit facility;

• timing of the next review of the Company's credit facility by its lender;

• ability of the Company to meet its foreseeable obligations;

• capital expenditures and the funding thereof;

• the finding of acquisitions;

• impacts of capital expenditures on the Company's reserves;

• commitments and Questerre's participation in future capital programs;

• risks and risk management;

• potential for equity and debt issuances and farm-out arrangements;

• counterparty creditworthiness;

• the timing of receivables from joint venture partners;

• flow-through shares and use of proceeds and renunciation and indemnity obligations associated therewith;

• insurance;

• use of financial instruments; and

• critical accounting estimates.

  The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A, the AIF, and the documents incorporated by reference into this document:

• PX Energy operations are in Brazil and may be adversely affected by changes in foreign government policies and legislation, social instability or other factors not in the control of Questerre;

• the synergies expected from the Acquisition not being realized;

• the dispute regarding the First Tranche Shares and the working capital pursuant to the Acquisition Agreement;

• the outcome of resolution of any dispute pursuant to the term sheet with a prospective joint venture partner;

• loss of key personnel of PX Energy in connection with the Acquisition;

• the impact of the senior secured callable bonds on FRBH and PX Energy;

• potential tariffs and counter tariffs on trade with the United States and other countries;

• Quebec's Bill 21, the revocation of licenses in Quebec and potential compensation;

• the impact of the convertible promissory notes and other liabilities to be assumed in connection with the Acquisition;

• the impact of transactions contemplated in the BCA;

• volatility in market prices for oil, natural gas liquids and natural gas due to, among other things, the production agreements between OPEC and its allies, including Saudi Arabia and Russia, on production levels, the war in Ukraine, and the conflict in the Middle East;

• access to capital;

• general economic conditions;

• the terms and availability of credit facilities;

• counterparty credit risk;

• changes or fluctuations in oil, natural gas liquids and natural gas production levels;

• liabilities inherent in oil and natural gas operations;

• adverse judicial rulings, regulatory rulings, orders and decisions;

• attracting, retaining and motivating skilled personnel;

• uncertainties associated with estimating oil and natural gas reserves and resources;

• insufficient advancement by Red Leaf in the engineering of its proprietary process;

• competition for, cost and availability of, among other things, capital, acquisitions of reserves, undeveloped land, equipment, skilled personnel and services;

• incorrect assessments of the value of acquisitions and targeted exploration and development assets;

• fluctuations in foreign exchange or interest rates;

• stock market volatility, market valuations and the market value of the securities of Questerre;

• failure to realize the anticipated benefits of acquisitions;

• actions by governmental or regulatory authorities, including changes in royalty structures and programs, and income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry;

• limitations on insurance;

• changes in environmental, tax, or other legislation applicable to the Company's operations, and its

  ability to comply with current and future environmental and other laws; and

• geological, technical, drilling and processing problems, and other difficulties in producing oil, natural gas liquids and natural gas reserves.

  Statements relating to reserves are by their nature deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. The discounted and undiscounted net present values of future net revenue attributable to reserves do not represent the fair market value thereof.

  Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this MD&A and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities law. Certain information set out herein with respect to forecasted results is "financial outlook" within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding the Company's reasonable expectations as to the anticipated results of its proposed business activities. Readers are cautioned that this financial outlook may not be appropriate for other purposes.

  BOE Conversions

  Barrel of oil equivalent ("boe") amounts may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil and is based on an energy equivalent conversion method application at the burner tip and

  does not necessarily represent an economic 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 equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

  Non-GAAP Measures

  This document contains certain financial measures, as described below, which do not have standardized meanings prescribed under GAAP. As these measures are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.

  This document contains the term "adjusted funds flow from operations", which is an additional non-GAAP measure. The Company uses this measure to help evaluate its performance.

  As an indicator of the Company's performance, adjusted funds flow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with GAAP. The Company's determination of adjusted funds flow from operations may not be comparable to that reported by other companies.

  Adjusted Funds Flow from Operations Reconciliation

  ($ thousands)	2025	2024
  Net cash from operating activities	$ 12,618	$ 13,673
  Transaction costs related to PX Energy	3,276	-
  Change in non-cash working capital	(214)	890
  Adjusted funds flow from operations	$ 15,680	$ 14,563

  This document also contains the terms "operating netbacks", "cash netbacks" and "working capital

  surplus/(deficit)," which are non-GAAP measures.

  Questerre considers adjusted funds flow from operations to be a key measure as it demonstrates the Company's ability to generate the cash necessary to fund operations and support activities related to its major assets.

  Operating and cash netbacks, as presented, do not have any standardized meaning prescribed by GAAP and may not be comparable with the calculation of similar measures for other entities. Operating netbacks have been defined as revenue less royalties, transportation and operating costs. Cash netbacks have been defined as operating netbacks less general and administrative costs. Netbacks are generally discussed and presented on a per boe basis.

  The Company also uses the term "working capital surplus/(deficit)". Working capital surplus/(deficit), as presented, does not have any standardized meaning prescribed by GAAP, and may not be comparable with the calculation of similar measures for other entities. Working capital surplus/(deficit), as used by the Company, is calculated as current assets less current liabilities excluding any outstanding risk management contracts and lease liabilities.

  Select Annual Information
  As at/for the years ended December 31,	2025	2024	2023
  Financial ($ thousands, except as noted) Petroleum and Natural Gas Revenue	77,136	36,927	41,701
  Adjusted Funds Flow from Operations (1)	15,680	14,563	15,855
  Cash Flow from Operations	12,618	13,673	16,317
  Basic and Diluted ($/share)	0.03	0.03	0.04
  Net Loss	(78,935)	(7,329)	(23,708)
  Basic and Diluted ($/share)	(0.18)	(0.02)	(0.06)
  Capital Expenditures	25,619	20,640	10,148
  Working Capital (Deficit) Surplus (2)	(51,971)	23,035	29,866
  Total Assets	395,262	170,723	172,346
  Shareholders' Equity	76,659	138,629	143,667
  Common Shares Outstanding (thousands)	445,764	428,516	428,516
  Weighted average - basic (thousands)	429,083	428,516	428,516
  Weighted average - diluted (thousands)	433,267	431,715	430,294
  Operations (units as noted) Average Production
  Crude Oil and Natural Gas Liquids (bbls/d)	2,337	1,021	1,056
  Natural Gas (Mcf/d)	8,243	4,411	4,749
  Total (boe/d)	3,711	1,756	1,848
  Average Sales Price (3)(5)
  Crude Oil and Natural Gas Liquids ($/bbl)	79.80	91.92	94.01
  Crude Oil - Brent ($/bbl)	85.26	-	-
  Natural Gas ($/GJ)	2.38	1.65	3.02
  Total ($/boe)	56.95	57.45	61.83
  Netback ($/boe)
  Petroleum and Natural Gas Revenue (4)	56.95	57.45	61.83
  Royalties Expense (4)	(4.71)	(4.32)	(8.89)
  Percentage	8%	8%	14%
  Operating Expense (4)	(34.97)	(23.58)	(23.84)
  Operating Netback	17.27	29.55	29.10
  General and Administrative Expense (4)	(6.67)	(8.60)	(7.54)
  Cash Netback	10.60	20.95	21.56
  Wells Drilled
  Gross	2.00	6.00	2.00
  Net	2.00	2.25	1.35

  1. Adjusted Funds Flow from Operations is a non-GAAP measure defined as cash flows from operating activities before changes in non-cash operating working capital.

  2. Refer to the Current Assets and Current Liabilities in the Balance Sheet for the years ended December 31, 2025 and 2024.

  3. Refer to Note 22 in the Consolidated Financial Statements for the years ended December 31, 2025 and 2024.

  4. Refer to Consolidated Statement of Comprehensive Loss for the years ended December 31, 2025 and 2024.

  5. Prices per boe are based on sales volumes representing produced volumes less volumes consumed in internal processes.

  Highlights

• Closed acquisition of PX Energy, an integrated oil shale company in southern Brazil with production of 4,411 boe per day in the fourth quarter and total proved and probable reserves of 12.6 MMboe with a before tax NPV-10% of $372 million

• Consolidated ownership of Red Leaf Resources

• Spin-out of economic value of Quebec assets through share reorganization

• Average daily production of 3,711 boe per day, net cash from operating activities of $12.6 million and adjusted funds flow from operations of $15.7 million

• Total proved and probable reserves for our Canadian assets declined 6% by volume to 22.4 MMboe and with lower future prices, declined 32% in value to a before tax NPV-10% of $133.3 million at December 31, 2025 resulting in an impairment expense of $49.8 million

  2025 Activities

  Oil Shale

  To advance its strategy to commercial develop oil shale, the Company completed the acquisition of Paraná Xisto S.A. ("PX Energy") (the "Acquisition") and consolidated its equity interest in Red Leaf Resources Inc. ("Red Leaf").

  PX Energy

  PX Energy is an integrated oil shale production and refining company in southern Brazil. Its assets include downstream production expertise that complement the Company's experience with upstream resource development and technology assessment. The acquisition of the remaining equity interest in Red Leaf provides ownership of its proprietary technology under development to produce oil from oil shale that incorporates carbon capture with efficient water usage.

  PX Energy has over thirty years of operations and utilizes a technology to produce oil from oil shale developed by a Brazilian integrated energy company. The Acquisition provides a platform of producing oil shale operations, including mining, processing and refining facilities as well as oil shale reserves and resources. Total proved and probable reserves as of December 31, 2025, were 12.6 MMboe with a before tax NPV-10% of $372 million. Average daily production from PX Energy for the fourth quarter was over 4,000 boe per day.

  The Acquisition

  Completed in September 2025, the Acquisition consisted of the purchase of 100% of the equity capital of PX Energy. It was concluded through the purchase of all issued and outstanding shares of its parent company, Forbes Resources Brazil Holding SA ("FRBH") from the vendors by a wholly-owned subsidiary of the Company.

  Consideration

  The consideration for the Acquisition includes the issuance of 15 million Common Shares (post the Quebec Spinout - see Corporate) subject to a lock-up and voting agreement (the "First Tranche Common Shares") with a deemed value of $5.0 million and contingent equity consideration of two additional tranches of 25 million Common Shares with an estimated fair value of $13.9 million as detailed below:

• 25 million Common Shares ("Second Tranche Common Shares") subject to the achievement of US$30 million in free cash flow within any twelve month period between the closing of the Acquisition and September 30, 2027, or the completion of an equity issue by the Company of $25 million at a price of $0.50 per Common Share no later than September 30, 2027;

• 25 million Common Shares ("Third Tranche Common Shares") subject to the achievement of US$40 million in free cash flow within any twelve month period between the closing of the Acquisition and September 30, 2028, or the completion of an equity issue by the Company of $25 million at a price of $1.00 per Common Share no later than September 30, 2028.

Pursuant to the agreement between the Company and the vendors (the "Acquisition Agreement"), the Company has notified the vendors it is seeking a purchase price adjustment of US$18.7 million, representing the difference between the closing working capital and target working capital as defined under the Acquisition Agreement. As a result, the Company's position is that no additional consideration is payable to the vendors, including the issuance of the First Tranche Shares. The Vendors have advised the Company that they are disputing this amount and are seeking issuance of the First Tranche Shares. The Company intends to follow the procedure outlined under the Acquisition Agreement including the appointment of an independent auditor to resolve any disputes related to the assessment of the closing working capital. As of December 31, 2025, the First Tranche Common Shares had not been issued. The obligation to issue the shares has been recorded as a liability.

The consideration for the Acquisition also included the assumption by the Company's subsidiary of the vendor's obligations under a business combination agreement ("BCA") as amended, with a US special purpose acquisition company ("SPAC"). Pursuant to the BCA, the Company's wholly owned subsidiary has assumed the obligation to combine with the SPAC in a go public transaction. The BCA is subject to precedent conditions including receipt of regulatory approvals, the filing of a Proxy/Registration Statement with the US Securities and Exchange Commission and the completion of this transaction prior to December 31, 2026. Under the BCA, the Company's subsidiary assumed obligations related to the SPAC, along with other liabilities, with an estimated fair value of $7.6 million.

Related to the SPAC and upon the issuance of the First Tranche Common Shares and associated transactions, the Company's subsidiary will assume convertible promissory notes originally issued by the vendor in the principal amount of $15.2 million. The notes bear interest at 12% per annum and are due on December 31, 2026. PX Energy has issued a US$5 million guarantee for these notes. Subject to conditions precedent in the BCA and the closing of the SPAC transaction, the notes are convertible into common shares of the SPAC. If the SPAC transaction does not proceed, the notes are due and payable or convertible into equity of the Company's subsidiary. Liabilities acquired under the acquisition included US$80 million

in senior secured callable bonds issued by FRBH with a maturity date of April 26, 2028. The bonds have a face value of US$80 million and an acquisition date fair value of US$64 million. The carrying amount will accrete from US$64 million to US$80 million with the accretion recognized on the income statement as finance costs at the effective interest rate. Interest will also be recognized as incurred. The bonds are secured by a fiduciary assignment of the equity of PX Energy and security over the assets of PX Energy.

In conjunction with the closing of the Acquisition, the holders of bonds representing a requisite majority agreed to amend the terms of the bonds as detailed below. These amendments may need to be formalized in an amending agreement to the Bond terms.

Interest reduced from 16% per annum to 10% per annum effective August 1, 2025. All accrued and unpaid interest up to December 31, 2025, will be payable in shares in the SPAC transaction. If the SPAC transaction does not proceed, no interest is payable in 2025. Thereafter, interest is payable quarterly based on Brent pricing ranging from 4% based on Brent pricing under US$55 per barrel to 20% based on Brent pricing greater than US$95 per barrel with interest not to exceed 16% over the term of the bonds. Interest in 2026 may be payable in cash or in kind at the issuer's election with interest in 2027 onwards payable in kind if Brent prices are below US$65 per barrel. Additionally, the tenure of the bond can be extended for two - one year terms in exchange for a fee of 2% of the nominal amount for each extension.

Interest on the bonds has accrued at 10% effective August 1, 2025 and will be subject to the terms of the amendment detailed above.

Concurrent with the Acquisition, the Company executed a binding term sheet with a prospective partner (the "Partner") for a 50/50 joint venture for the ownership and management of PX Energy (the "Joint Venture"). In January 2026, the Company was advised by the Partner that the term sheet expired in accordance with its terms. In March, the Partner notified the Company that it was seeking a penalty of US$20 million for alleged breaches by the Company pursuant to the term sheet. The Company has advised the Partner that its claim is wholly without merit and it is reserving its legal rights against the Partner and its affiliates for among other things, breach of the term sheet. Pursuant to the term sheet, the matter will be submitted for arbitration pursuant to the ICC rules should either of the parties make a formal claim thereunder.

Red Leaf Resources Inc.

In December, the Company consolidated its ownership of Red Leaf through an exchange of Red Leaf common shares for Questerre Common Shares and the acquisition of the Red Leaf preferred shares for cash. Red Leaf is a private US-based technology company whose principal assets include its patented HCCO oil shale processing technology, oil shale mineral leases in the State of Utah, title to over 7,000 acres in the Uintah Basin in the State of Utah and cash and investments of over US$9 million. Prior to the acquisition, Questerre held approximately 38% Red Leaf's common equity capital on a fully diluted basis and 17% of its preferred equity capital.

Total consideration was $8.6 million and consisted of the issuance of 20.4 million Questerre Common Shares to Red Leaf common shareholders with a deemed value of $0.31 per Common Share and $2.2

million cash to acquire Red Leaf preferred shares not held by the Company. As at December 31, 2025, the portion of consideration related to the preferred shares remains unpaid and has been recognized as a current liability of $2.2 million.

Questerre intends to utilize the Red Leaf technology for its project in Jordan. Discussions with the Government of Jordan for a demonstration of the technology and the related negotiations for the concession agreement for the project remain ongoing. Through the execution of a new agreement with the Government of Jordan, the Company seeks to renew its exclusive rights to this project which expired in May 2025.

For 2026, the Company plans to restructure the balance sheet and optimize the operations of PX Energy to improve profitability and financial liquidity. It is also assessing options to demonstrate the Red Leaf technology at scale.

Western Canada

During the year, Questerre participated in a three (1.5 net) well program at Kakwa North and elected not to participate in the three (0.75 net) well program at Kakwa Central.

Capital invested in Kakwa totaled $18.8 million for the year (2024: $19. 3 million) with daily production averaging 2,350 boe/d (2024: 1,452 boe/d) comprising of 7.3 MMcf/d of natural gas (2024: 4.4 MMcf/d) and 1,145 bbl/d of condensate and natural gas liquids (2024: 719 bbl/d). Total proved and probable reserves as of December 31, 2025, were estimated at 21.1 MMBoe (2024: 22.5 MMBoe) with a before tax NPV-10% of $124.3 million (2024: $180.6 million). The Company currently holds 40,320 (17,700 net) acres in the Kakwa area.

At Kakwa North, the operator finalized a three (1.5 net) well program during the year. The wells were brought on-stream in the second quarter. The operator is assessing a follow-up drilling program that could commence in the fall of 2026.

At Kakwa Central, the operator commenced a three well program in the fall of 2025. Questerre elected to forego participation in this entire program due to the proposed inter-well spacing that is expected to impact overall well recoveries.

The Company plans to participate in future drilling programs at Kakwa North and Kakwa Central subject to, among other things, commodity prices, and the costs and design of the proposed drilling and completion programs.

At Antler Saskatchewan, consistent with prior years, activities focused on optimizing existing production and expanding the pilot secondary recovery scheme to increase recovery of the oil in place.

$5.1 million was invested at Antler during the year to expand the pilot secondary recovery scheme and drill two 100% wells brought on production in the fourth quarter (2024: $0.8 million). Daily production averaged 207 bbl/d (2024: 250 bbl/d). Total proved and probable reserves as at December 31, 2025, were estimated at 1.2 MMBbls (2024: 1.2 MMBbls) with a before tax NPV-10% of $17.4 million (2024: $21.9 million). The Company currently holds 14,730 net acres in the area.

In 2026, the Company expects to continue its work to enhance existing production through workovers and expanding the pilot secondary recovery scheme while assessing future drilling locations.

Quebec

The Company's primary objective remains the implementation of a business and political solution for the development of its natural gas discovery in the province. Concurrently, it is protecting its legal rights following the enactment in August 2022 of Bill 21, An Act mainly to end petroleum exploration and production and the public financing of those activities in Quebec ("Bill 21").

Discussions remain ongoing with the Quebec Ministry of Economy, Innovation and Energy, for the Company's carbon storage pilot project application under Bill 21. The project includes a comprehensive program to assess the carbon storage potential including injection and monitoring wells, compression facilities and a pipeline to an adjacent industrial park. The Company is seeking Government funding for this pilot project. The Company is participating in the consultation process for new legislation proposed by the province related to carbon sequestration legislation.

Through the Quebec Energy Association, the Company participated in the public consultation for Bill 69, An Act to ensure the responsible governance of energy resources and to amend various legislative provisions ("Bill 69"). Bil 69 included the requirement for an integrated resource management plan to promote energy development in Quebec. Among other things, it established for electric power and natural gas markets, policy directions, objectives and targets regarding supply, energy infrastructure and innovation. In June 2025, the Government of Quebec enacted Bill 69 under closure.

During the third quarter, the Company was advised that the Supreme Court of Canada declined to hear its application to appeal the decision from the Quebec Court of Appeal on the stay of application of Bill 21. The ruling by the Quebec Court of Appeal in May 2025 annulled a decision by the Quebec Superior Court justice in January 2024 suspending key provisions of Bill 21. The Government of Quebec is now permitted to enforce the specific provisions related to the abandonment and reclamation of existing wells. In March 2026, the Company was advised the Government is seeking proof of solvency of $11.4 million for the estimated gross abandonment and reclamation costs for these wells. The government is responsible for 75% of these costs. The Company intends to work collaboratively with the Government to meet its obligations on a reasonable and timely basis.

The Company is proceeding with the main hearing on the merits of the case in accordance with procedural rules in Quebec, including its debate on the constitutional validity of Bill 21. The questioning of key Government representatives was completed in the fall of 2025. Subject to completion of pre-trial motions and other procedural matters, the Company is seeking a date for the main hearing in 2026.

Corporate

In January 2026, the Company completed the economic spin out of its Quebec-based assets (the "Quebec Spinout") through a reorganization of its capital. The reorganization consisted of the exchange of one old Common Share for one new Common Share and one Series 2 Preferred Share. The Preferred Shares entitle holders to the economic benefits of the Quebec assets and the Common Shares represent

ownership of the remaining assets of the Company. The Company is assessing options to have the Preferred Shares listed for trading.

The Company's facilities with a Canadian chartered bank were maintained at $16 million for the year. The credit facilities include a revolving operating demand facility of $16 million can be used for general corporate purposes, ongoing operations, and capital expenditures within Canada. Any borrowing under the credit facilities, with the exception of letters of credit, bears interest at the bank's prime interest rate and an applicable basis point margin. The facilities are secured by a debenture with a first floating charge over all Western Canadian assets of the Company and a general assignment of books debts.

Production

Note: Oil and liquids include light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.

The tie-in of three (1.5 net) new wells at Kakwa North and the Acquisition contributed to production volumes doubling over the prior year.

Production from Kakwa, Alberta continues to account for over 90% of volumes from Canada. With the addition of incremental production from Brazil in the fourth quarter, Kakwa now accounts for one third of Company volumes. Production in Canada including light oil production from the Company's assets in Saskatchewan and Manitoba, grew nearly 50% over the prior year with an approximately equal weighting between oil and liquids and natural gas. The production volumes in Brazil reflect the Acquisition that closed at the end of the third quarter and are primarily heavy crude oil. These include both volumes from the mining and processing of oil shale and the processing of refinery waste. Additional products include natural gas liquids and sulphur.

For the remainder of this year, the Company anticipates its production volumes will decline nominally with no new wells to come onstream at Kakwa offset by relatively stable production volumes from Brazil.

Note: Oil and liquids include light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.

Consistent with increased production volumes, revenue doubled over the last year. In Canada, lower realized oil prices were largely offset by the increase in production volumes. Revenue from Brazil reflects petroleum and natural gas sales in the fourth quarter following the closing of the PX Energy acquisition.

Pricing

Realized prices:

Note: Oil and liquids include light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.

Global crude oil prices declined over the prior year with the benchmark WTI and Brent prices decreasing by 12%. A bearish sentiment throughout the year reflected the potential impacts of proposed tariffs by the US administration, including a possible trade war with China, and OPEC+ unwinding their voluntary production cuts during the year.

For the year ended December 31, 2025, the Company's realized price for crude oil and natural gas liquids in Canada averaged $79.80 per barrel (2024: $91.92 per barrel) compared to the benchmark Canadian Mixed Sweet Blend that averaged $85.71 per barrel (2024: $97.54 per barrel).

In Brazil, prices for the Company's oil production, primarily a premium heavy crude oil, is based on Brent with applicable premiums. Realized prices per barrel are based on produced volumes less volumes utilized in the production process. Reflecting production for the fourth quarter since the Acquisition closed, Brazil's realized price for crude oil and natural gas liquids averaged $85.26 per barrel compared to the benchmark

Brent for the period that averaged $96.66 per barrel. Realized price for natural gas liquids is primarily based on by the price of Brent.

In North America, natural gas prices increased over the prior year with growing production in the United States being offset by increased demand including from higher LNG exports. The commissioning of Canada's first LNG export facility also contributed to optimism about improved prices in Canada. Notwithstanding, prices in Canada declined substantially in the summer and turned negative as supply exceeded takeaway capacity.

For the year ended December 31, 2025, the AECO daily spot price increased to an average of $1.40 per GJ compared to $1.38 per GJ in 2024. Including the higher heat content gas from Kakwa, the Company's realized natural gas prices averaged $2.38 per GJ (2024: $1.65 per GJ).

Royalties

Royalties on production in Canada increased commensurate with the increase in volumes. As a percentage of revenue, this remained unchanged from the prior year at 8%. The royalty rate on production from Brazil was 3% for the year reflecting a flat rate on 5% on the value of oil shale production and a 2% royalty on production volumes related to refinery waste oil processing.

Operating Costs

In Canada, operating costs increased over the prior year with higher production volumes. At Kakwa,

Approximately 75% of the increase in Canadian General & Administrative expenses ("G&A") relates to transaction costs of $3.3 million for the Acquisition. Post the Acquisition, the Company incurred $2.4 million in ongoing G&A costs related to PX Energy. Compared to last year, the Company also saw an increase in G&A expense related to its Quebec assets.

Depletion, Depreciation, and Impairment

For the year ended December 31, 2025, the Company recorded depletion, and depreciation expense of

$29.7 million (2024: $11.9 million) with depletion accounting for over 80% of this amount. Of this amount,

$17.3 million related to production from Canada and $12.4 million related to production from Brazil.

On a unit of production basis this expense increased to $21.90 per boe from $18.52 per boe last year mainly driven by a higher depletion rate on its Brazil assets. In Canada, on a unit of production basis depletion and depreciation remained largely unchanged at $18.31 per boe. In Brazil, on a unit of production basis, depletion and depreciation was $30.28 per boe.

In 2025, the Company assessed its property, plant, and equipment ("PP&E") assets for indicators of impairment or impairment reversals. With respect to the Kakwa and Antler cash generating units ("CGU") an indicator of impairment was identified as a result of a reduction in forward commodity prices. The result of the impairment test, based on a fair value less costs of disposal ("FVLCD") assessment, was an impairment expense of $44.2 million related to the Kakwa CGU and an impairment expense of $5.6 million related to the Antler CGU. The estimates of FVLCD were determined using a discount rate of 15% and forecasted after tax cash flows based on proved plus probable reserves, with escalating prices, royalties, operating costs and future development costs. No indicators of impairment or impairment reversals were identified for the other CGUs or its exploration and evaluation ("E&E") assets in 2025.

In 2024, the Company assessed the carrying value of its E&E assets. Due to the pending expiry of its exclusivity rights in the absence of a new agreement with the Government of Jordan, the Company recorded an impairment of its E&E assets in Jordan for $7.9 million. No other impairment was recorded in the prior year.

Share Based Compensation

Pursuant to the Company's share option plan, an optionee may request that the Company purchase all or any part of the then vested options of the optionee, for an amount equal to the market price of the Common Shares less the exercise price of the option shares. Notwithstanding the foregoing, the Company may, at its sole discretion, decline to accept and, accordingly, has no obligations with respect to the exercise of this put right at any time. Any cash settled options are cancelled.

The Company recorded share-based compensation expense of $1 million (2024: $1.1 million) net of $0.2 million (2024: $0.3 million) in expense that was capitalized during the year. Included in this amount is the cash settlement of 5.9 million expiring options for a payment of $0.2 million in the first quarter of 2025.

Equity Investment

Questerre previously held approximately 38% of the outstanding equity interest in Red Leaf. The Company acquired the remaining 62% equity interest, resulting in Questerre obtaining 100% ownership and control of Red Leaf during the year. Accordingly, Red Leaf has been fully consolidated from the acquisition date. As a result of remeasuring the Company's previously held equity interest to fair value at the acquisition date, a gain of $2.4 million was recognized. Further details regarding the transaction are provided in Note 6 to the Financial Statements.

Finance income and expenses

The Company earned finance income of $1.9 million (2024: $1.1 million) while expensing $14.8 million (2024: almost nil) for the year ended December 31, 2025. The income mainly relates to foreign exchange gain and expense mainly relates to interest on US $80 million secured bonds and related foreign exchange losses. See Note 24 of the Financial Statements for further details.

Other Comprehensive Income (Loss)

In 2025, the Company recorded other comprehensive loss of $3.5 million (2024: $0.9 million gain) related to the change in foreign currency translation adjustments.

Net Loss and Total Comprehensive Loss

For the year ended December 31, 2025, the Company recorded a net loss of $78.9 million compared to a net loss of $7.3 million in the prior year. The higher current year loss is mainly due to the impairment expense and higher expenses in all categories which was offset by deferred tax recovery of $2.1 million.

Including other comprehensive loss, the Company reported a total comprehensive loss of $82.5 million compared to a loss of $6.4 million last year.

Cash Flow from Operating Activities

The Company reported cash flow from operating activities of $12.6 million (2024: $13.7 million). The variance over the prior year is attributed to the lower cash flow from operations which was offset by an increase in the non-cash working capital in the current year compared to a decrease last year.

Cash Flow used in Investing Activities

The cash used in investing activities increased to $18.8 million from $16.9 million last year. Current year investing activities included capital expenditures of $25.6 million which was offset by cash acquired from the business combination and asset acquisition of $12 million.

Cash Flow used in Financing Activities

Cash used in financing activities for the current year and prior year mainly relates to principal portion of the lease payments.

Capital Expenditures

Notes: Capital expenditures exclude certain non-cash items such as share based compensation and asset retirement obligations.

For the year ended December 31, 2025, the Company incurred capital expenditures of $25.6 million as follows:

• In Canada, $24 million was incurred to finish drilling, completing and tying-in three (1.5 net) wells in Kakwa and drilling and completing two (100% net) wells in Antler; and

• In Brazil, $1.6 million was spent on debottlenecking processing facilities.

  For the year ended December 31, 2024, the Company incurred capital expenditures of $20.6 million as follows:

• In Alberta, $11.7 million for drilling, completing and tying-in three (0.75 net) wells on the Kakwa Central joint venture and $7.6 million for drilling three (1.50 net) wells at Kakwa North;

• In Saskatchewan, $0.8 million was primarily spent on the pressure maintenance scheme; and

• The remaining $0.5 million was spent on other assets including Jordan.

Fourth Quarter 2025 Results

In the fourth quarter of 2025, petroleum and natural gas revenue increased to $42.5 million from $9.6 million last year. The increase in revenue of $31.7 million is primarily attributable to the acquisition of PX Energy and its producing assets in Brazil that closed at the end of the third quarter. Petroleum and natural gas revenue attributable to assets in Canada increased $1.2 million over the prior year with higher production volumes offsetting the impact of lower prices.

The acquisition of PX Energy also contributed to the increase in operating costs for the fourth quarter. The acquired assets in Brazil accounted for $25.5 million with the remainder representing the costs attributable to its assets in Canada of $6.5 million. Operating costs in Canada increased over the prior quarter and same period last year due additional producing wells at Kakwa.

Including impairment expense of $49.8 million relating to its PP&E assets in both the Kakwa and Antler CGUs, the Company reported a net loss of $75.1 million (2024: $8.1 million loss) and total comprehensive loss of $72.9 million (2024: $8.1 million) for the quarter. In the prior year, the loss was due to the impairment expense in E&E.

In the fourth quarter, net cash from operating activities was $1.7 million (2024: $3.5 million from operation activities). This reflects the cash flow from operations of $4.2 million (2024: $3.7 million) and an increase in non-cash working capital of $2.1 million compared to $0.2 million last year. Net cash from investing activities was $5 million due to cash acquired as part of business combination compared to net use of $7.5 million in the prior year due to higher capital spending associated with Kakwa North wells. Minimal cash was used in financing with an increase in lease payments from $0.02 million to $0.2 million in the current year.

Liquidity and Capital Resources

The Company's objectives when managing its capital are firstly to maintain financial liquidity, and secondly

to optimize the cost of capital at an acceptable risk to sustain the future development of the business.

The Company continues to manage its financial liquidity through ensuring capital expenditures can be financed through a combination of cash flow from operations, existing cash and available debt facilities.

As December 31, 2025, the Company had cash and cash equivalents of $25.4 million, available undrawn credit facilities of $16 million and a working capital deficit of $52 million. Total debt of $100.8 million exceeded the Company's existing liquidity (cash plus available undrawn capacity) by approximately $59.4 million.

The amounts above include a working capital deficit of $63.6 million related to its Brazil assets. Of this amount over 44% or $27.8 million relates to the Acquisition. Subject to the terms of related agreements, this amount includes the assumption of the assumed liabilities of the vendor of $22.8 million as well as $5 million related to equity issuance, currently recorded as liability, for the Acquisition. The Company has implemented costs cutting measures in Brazil to improve profitability of its operations post the Acquisition. It is anticipated these measures will improve cash flow from operations to fund this working capital deficit.

At December 31, 2025, there were no material borrowings under its Canadian credit facility. Under the terms of the credit facilities, the Company has provided a covenant that it will maintain an Adjusted Working Capital Ratio greater than 1.0. The ratio is defined as current assets (excluding unrealized hedging gains and including undrawn Credit Facility A availability) to current liabilities (excluding bank debt outstanding and unrealized hedging losses). The Adjusted Working Capital Ratio at December 31, 2025 was 2.55 (2024: 3.92) and the covenant was met. See Note 14 of the Financial Statements. The Company's credit facility are to be used solely for its Western Canadian assets. As such, calculation of covenants above exclude any amounts related to Acquisition. The Company breached the covenant to notify the lender of the establishment of wholly owned subsidiaries for the Acquisition and the issuance of Common Shares for the remaining equity interest in Red Leaf. A waiver was granted by the lender on March 31, 2026.

In connection with the Acquisition, the Company acquired liabilities including senior secured bonds issued by FRBH with a maturity date of April 26, 2028. The bonds have a face value of US$80 million and an acquisition date fair value of US$64 million. The bonds are secured by a fiduciary assignment of the equity of PX Energy and security over the assets of PX Energy. In conjunction with the closing of the Acquisition, the holders of bonds representing a requisite majority agreed to amend the terms of the bonds related to interest and maturity with such changes taking effect on the closing of the Acquisition. The Company believes that the amendments to the secured debt terms provide sufficient flexibility under a range of commodity price environments to support the financial liquidity of PX Energy. See Note 14 of the Financial Statements.

While the credit facilities were maintained at $16 million, the facilities could be reduced at their next review scheduled during the second quarter of 2026. The credit facilities are a demand facility and can be reduced, amended or eliminated by the lender for reasons beyond the Company's control. Should the credit facilities be reduced or eliminated, the Company would need to seek alternative credit facilities or consider the issuance of equity to enhance its liquidity. In the current market, the Company may be unable to secure additional financing on acceptable terms, if at all. The Company believes that it has access to sufficient financial liquidity to meet its foreseeable obligations in the normal course of operations over the next 12 months.

The Company is committed to the 2026 future development costs associated with proved reserves in its independent reserves assessment as of December 31, 2025. It anticipates that, as a result, reserves associated with wells drilled in 2026 will be transferred from the proved undeveloped to the proved producing category.

For a detailed discussion of the risks and uncertainties associated with the Company's business and

operations, see the Risk Management section of the MD&A and the AIF.

Share Capital

The Company is authorized to issue an unlimited number of Common Shares. The Company is also authorized to issue an unlimited number of Class "B" Common voting shares and an unlimited number of preferred shares, issuable in one or more series. At December 31, 2025, there were no Class "B" common voting shares or preferred shares outstanding.

The following table provides a summary of the outstanding Common Shares and options as at the date of the MD&A and the current and preceding fiscal year end.

As part of the Acquisition, the Company is obligated to issue 15 million Class "A" common voting shares with a deemed value of $5.0 million. As at December 31, 2025, these shares had not yet been issued and the related amount has been recognized as a current liability.

The consideration also includes contingent equity consideration comprised of two additional tranches of

25 million Common Shares. At the acquisition date, these contingent shares were measured at an estimated fair value of $13.9 million and have been classified as equity and recorded in contributed surplus.

In January 2026, the Company completed the economic spin out its Quebec-based assets (the "Quebec Spinout") through a reorganization of its capital. The reorganization consisted of the exchange of one old Common Share for one new Common Share and one Series 2 Preferred Share. The Preferred Shares entitle holders to the economic benefits of the Quebec assets and the Common Shares represent ownership of the remaining assets of the Company.

A summary of the Company's stock option activity during the years ended December 31, 2025 and 2024 follows:

December 31, 2025 December 31, 2024

Commitments

A summary of the Company's net commitments at December 31, 2025 follows:

To maintain its capacity to execute its business strategy, the Company expects that it will need to continue the development of its producing assets. There will also be expenditures in relation to G&A and other operational expenses. These expenditures are not yet commitments, but Questerre expects to fund such amounts primarily out of cash flow from operations and its available cash and credit facilities.

Risk Management

Companies engaged in the petroleum and natural gas industry face a variety of risks. For Questerre, these include risks associated with commodity prices, exploration and development drilling as well as production operations, foreign exchange and interest rate fluctuations. Unforeseen significant changes in such areas as markets, prices, royalties, interest rates, government regulations and global economic conditions could have an impact on the Company's future operating results and/or financial condition. While Management realizes that all the risks may not be controllable, Questerre believes that they can be monitored and managed. For more information, please refer to the "Risk Factors" and "Industry Conditions" sections of the AIF and Note 19 to the audited consolidated financial statements for the year ended December 31, 2025.

The Company operates in an industry that is highly sensitive to commodity prices, market access, regulatory developments and the availability of capital. Questerre's financial performance and cash flow are substantially dependent on crude oil and natural gas prices, which remain volatile and are affected by factors beyond the Company's control, including global supply and demand, OPEC+ production decisions, geopolitical conflict, sanctions, trade policy, inflation, interest rates, foreign exchange movements, transportation constraints and general economic conditions. In 2025, oil markets remained sensitive to geopolitical and trade uncertainty and expectations of supply growth exceeding demand growth.

A sustained decline in commodity prices, or widening price differentials, could reduce the Company's cash flow from operations, limit funds available for capital expenditure and adversely affect the economic viability and value of its reserves and development opportunities. This may impair the Company's ability to replace production, advance projects and maintain financial flexibility.

These risks are particularly acute in Brazil, where Questerre's assets and operations are located and where current sales are derived from crude oil production. Brazilian laws and policies affecting foreign trade, the oil and gas fiscal regime and investment may change, and conducting business often entails numerous procedural requirements and formalities that can cause unexpected or lengthy delays; failure to comply

may call into question the validity of corporate acts. Management cannot predict the impact of additional corporate or regulatory formalities that may be adopted, including whether they would materially increase costs or restrict operations. Questerre's financial condition and results of operations therefore depend to a significant extent on macroeconomic, political and regulatory conditions in Brazil and on exchange rates between the Brazilian reais, the U.S. dollar, and Canadian dollar any of which-individually or in combination-could have a material adverse effect on the Company.

In Canada, the Company remains exposed to Western Canadian pricing dynamics, natural gas market conditions, infrastructure availability and evolving regulatory and environmental requirements. Although the Trans Mountain Expansion has improved crude oil market access and reduced certain export constraints, the Canadian oil and natural gas industry continues to face risks relating to transportation availability, permitting timelines and emissions-related regulation, including methane requirements.

Access to capital is also a significant risk for the Company. As a junior exploration and production company, Questerre relies on cash flow from operations, debt and equity financing and strategic arrangements to fund its activities. There can be no assurance that sufficient capital will be available when required or that it will be available on acceptable terms. If the Company is unable to obtain sufficient capital, it may be required to defer, reduce or restructure planned capital programs or other strategic initiatives. Questerre faces several financial risks over which it has no control, such as commodity prices, exchange rates, interest rates, access to credit and capital markets, as well as changes to government regulations and tax and royalty policies.

The Company uses the following guidelines to address financial exposure:

• Internally generated cash flow provides the initial source of funding on which the Company's

  annual capital expenditure program is based.

• Equity, including flow-through shares, if available on acceptable terms, may be raised to fund acquisitions and capital expenditures.

• Debt may be utilized to expand capital programs, including acquisitions, when it is deemed appropriate and where debt retirement can be controlled.

• Farm-outs of projects may be arranged if management considers that a project requires too much

capital or where the project affects the Company's risk profile.

Credit risk represents a potential financial loss to the Company if a customer or counterparty to a financial instrument fails to meet or discharge their obligation to the Company. Credit risk arises from the Company's receivables from joint venture partners and oil and gas marketers. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Credit risk also arises from the Company's cash and cash equivalents. In the past, the Company manages credit risk exposure by investing in Canadian banks and credit unions. Management does not expect any counterparty to fail to meet its obligations.

Poor credit conditions in the industry may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner if possible.

Substantially all of the accounts receivable are with oil and natural gas marketers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by entering into transactions with long-standing, reputable counterparties and partners.

Accounts receivable related to the sale of the Company's petroleum and natural gas production are paid in the following month from major oil and natural gas marketing and infrastructure companies and the Company has not experienced any credit loss relating to these sales to date. Pursuant to IFRS 9, the Company made a provision of $0.04 million at December 31, 2025, for its expected credit losses related to its accounts receivable.

Receivables from joint venture partners are typically collected within one to three months after the joint venture bill is issued. The Company mitigates this risk by obtaining pre-approval of significant capital expenditures.

The Company has issued and may continue in the future to issue flow-through shares to investors. The Company has historically used its best efforts to ensure that qualifying expenditures of Canadian Exploration Expense ("CEE") are incurred in order to meet its flow-through obligations. In 2017, the Federal Government amended the law regarding what expenses constitute CEE. Generally, oil and gas drilling expenses are now Canadian Development Expense rather than CEE. In the event that the Company has CEE expenditures reclassified under audit by the Canada Revenue Agency or fails to incur expenditures required under a flow-through share agreement, the Company may be required to liquidate certain of its assets in order to meet the indemnity obligations under flow-through share subscription agreements.

Exploration and development drilling risks are managed through the use of geological and geophysical interpretation technology, employing technical professionals and working in areas where those individuals have experience. For its non-operated properties, the Company strives to develop a good working relationship with the operator and monitors the operational activity on the property. The Company also carries appropriate insurance coverage for risks associated with its operations.

The Company may use financial instruments to reduce corporate risk in certain situations. Questerre's hedging policy is up to a maximum of 40% of total production at management's discretion.

As at December 31, 2025, the Company had no outstanding commodity risk management contract in place.

Environmental Regulation and Risk

The Company's operations are subject to extensive environmental laws and regulations in the jurisdictions in which it operates. These requirements govern, among other things, emissions, water use, waste handling, site restoration, abandonment and reclamation, and remediation of contaminated properties. Compliance with these requirements may increase capital expenditures, operating costs and

administrative obligations, and may affect the timing and economics of the Company's exploration, development and production activities. Failure to comply could result in penalties, the suspension or revocation of approvals, remediation orders or other liabilities.

In Alberta, the Company remains exposed to changing emissions and methane requirements, including the TIER regime and enhanced methane rules that will require additional compliance, monitoring and operational costs over time. In Québec, the regulatory environment remains highly restrictive for hydrocarbon development. Québec has revoked exploration and production licences and requires the permanent closure and restoration of wells drilled under those licences, which may limit the Company's ability to realize value from those assets and may increase closure and reclamation obligations.

More broadly, climate-related policy, carbon regulation, methane requirements and changing stakeholder expectations may increase the Company's costs, reduce operational flexibility and affect the competitiveness and economic viability of certain projects. These developments may also affect reserve values, access to capital and the Company's ability to advance portions of its asset base. While the Company seeks to manage these risks through compliance, operational planning and ongoing monitoring of regulatory developments, there can be no assurance that future environmental or climate-related measures will not have a material adverse effect on its business, financial condition and results of operations.

For more information, please refer to the "Risk Factors" and "Industry Conditions" sections of the AIF.

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. Following the PX Energy acquisition, the Company is exposed to variable-rate risk through the senior secured bonds acquired as part of that transaction.

Under the terms of the bonds, all accrued and unpaid interest up to December 31, 2025 converts into shares if the contemplated SPAC transaction is completed. If the SPAC transaction does not proceed, no interest is payable in 2025. Thereafter, interest is payable quarterly at variable rates determined by reference to Brent crude oil prices, ranging from 4% when Brent is below US$55 per barrel to 20% when Brent exceeds US$95 per barrel, subject to an overall cap such that interest does not exceed 16% over the term of the bonds. Interest in 2026 may be settled in cash or in kind at the issuer's election. From 2027 onward, interest is payable in kind if Brent prices are below US$65 per barrel. The maturity of the bonds may also be extended for up to two additional one-year terms for a fee equal to 2% of principal for each extension.

At December 31, 2025, the Company's exposure to variable-rate debt under these bonds was US$80 million (2024 - nil). As a result, changes in Brent pricing may affect the amount and timing of interest payable and, in certain periods, whether interest is settled in cash or in kind. The Company monitors this exposure in assessing its financing costs and expected liquidity requirements.

At December 31, 2025, and 2024, the Company's credit facilities outstanding balance was essentially nil.

Critical Accounting Estimates

The preparation of the consolidated financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. These estimates and judgments have risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.

Petroleum and Natural Gas Reserves

All of Questerre's petroleum and natural gas reserves are evaluated and reported on by independent petroleum engineering consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the COGE Handbook. For further information, please refer to "Statement of Reserves Data and Other Oil and Gas Information" in the AIF.

The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, commodity prices and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and changes in costs and commodity prices. These estimates are evaluated by independent reserve engineers at least annually.

Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the estimated proved plus probable reserves and there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

Reserve estimates impact a number of the areas, in particular, the valuation of property, plant and equipment and the calculation of depletion.

Cash Generating Units

A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations. Factors considered in the classification include geography and the way management monitors and makes decisions about its operations.

Impairment of Property, Plant and Equipment, Exploration and Evaluation Assets and Goodwill

The Company assesses its oil and natural gas properties, including exploration and evaluation assets and goodwill, for possible impairment or reversal of previously recognized impairments, other than goodwill, if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable or indications that previously recognized losses should be reversed. Determining if there are facts and circumstances present that indicate that carrying values of the assets may not be recoverable requires management's judgment and analysis of the facts and circumstances. Goodwill is tested for impairment annually.

The recoverable amounts of CGUs have been determined based on the VIU and the FVLCD. The key assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes, the discount rate, future operating and development costs and recent land transactions. Changes to these assumptions will affect the recoverable amounts of the CGUs and may require a material adjustment to their related carrying value.

Asset Retirement Obligation

Determination of the Company's asset retirement obligation is based on Government regulations, operator estimates, internal estimates using current costs and technology in accordance with existing legislation and industry practice and must also estimate timing, a risk-free rate and inflation rate in the calculation. These estimates are subject to change over time and, as such, may impact the charge against profit or loss. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a risk-free rate. The associated abandonment and retirement costs are capitalized as part of the carrying amount of the related asset. The capitalized amount is depleted on a unit of production basis in accordance with the Company's depletion policy. Changes to assumptions related to future expected costs, risk-free rates and timing may have a material impact on the amounts presented.

Share Based Compensation

The Company has a stock option plan enabling employees, officers and directors to receive Common Shares or cash at exercise prices equal to the market price or above on the date the option is granted. Under the equity settled method, compensation costs attributable to stock options granted to employees, officers or directors are measured at fair value using the Black-Scholes option pricing model. The assumptions used in the calculation are: the volatility of the stock price, risk-free rates of return and the expected lives of the options. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Changes to assumptions may have a material impact on the amounts presented.

Income Tax Accounting

Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of

existing tax laws in each jurisdiction differ significantly from the Company's estimate, the ability of the Company to realize the deferred tax assets could be impacted.

The determination of the Company's income and other tax assets or liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax asset or liability may differ significantly from that estimated and recorded by management.

Design and Evaluation of Internal Controls over Financial Reporting and Disclosure Controls and Procedures

Questerre is required to comply with National Instrument 52-109 "Certification of Disclosure in Issuers' Annual and Interim Filings" ("NI 52-109") and is required to make specific disclosures with respect to NI 52-109 as follows:

• The Company has designed and evaluated the effectiveness of Disclosure Controls and Procedures ("DC&P"). The President and Chief Executive Officer and the Chief Financial Officer have concluded that DC&P are designed appropriately and are operating effectively as at December 31, 2025.

• The Chief Executive Officer and the Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting ("ICFR"), in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of the Company's ICFR as at December 31, 2025, and have concluded that such ICFR have been designed appropriately and are operating effectively.

• The Company reports that no changes were made to ICFR during the quarter ended December 31, 2025, that have materially affected or are reasonably likely to materially affect the Company's ICFR.

It should be noted that a control system, including the Company's disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met, and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud. The Acquisition closed on September 26, 2025, and the results of the acquired companies have been included since that date and Management has identified deficiencies in preliminary assessments of their internal controls over financial reporting. Management is developing a plan to address these deficiencies in 2026.

1. Adjusted Funds Flow from Operations is a non-GAAP measure defined as cash flows from operating activities before changes in non-cash operating working capital.

2. Working capital surplus is a non-GAAP measure calculated as current assets less current liabilities excluding the current portion of risk management and lease liabilities.

Capital Expenditures, net of acquisitions and dispositions

7,543 3,433 7,034 2,630

1. Adjusted Funds Flow from Operations is a non-GAAP measure defined as cash flows from operating activities before changes in non-cash operating working capital.

2. Working capital surplus is a non-GAAP measure calculated as current assets less current liabilities excluding the current portion of risk management and lease liabilities.

   The general trends over the last eight quarters are as follows:

   • The Acquisition increased the working capital deficit, total assets & liabilities effective the end of the third quarter of 2025 and production, revenue, cash flow from operations and net profit in fourth quarter.

   • Excluding the Acquisition, petroleum and natural gas revenues and adjusted funds flow from operation in Canada have fluctuated with production volumes and realized commodity prices. Revenue has generally increased in 2025 as a result of higher production volumes despite a 7% drop in realized commodity prices last year.

   • Production volumes reflect the capital investment in wells at Kakwa in preceding quarters.

   • The level of capital expenditures over the quarters has varied largely due to the timing and number of wells drilled and completed in Canada.

   • Excluding the Acquisition, the working capital position has generally increased when capital expenditures and other investments have been lower than adjusted funds flow from operations and cash from financing activities.

   • Shareholders equity generally decreased as a result of net loss incurred by the Company.

Off-Balance Sheet Transactions

The Company did not engage in any off-balance sheet transactions during the year ended December 31, 2025.

Management's Report

The consolidated financial statements of Questerre Energy Corporation were prepared by management in accordance with International Financial Reporting Standards. The financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements.

Management has designed and maintains a system of internal accounting controls that provide reasonable assurance that all transactions are accurately recorded, that the financial statements reliably report the Company's operations and that the Company's assets are safeguarded. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. Such estimates are based on careful judgments made by management.

Ernst & Young LLP, an independent firm of Chartered Professional Accountants, has been engaged to audit the consolidated financial statements of the Company and provide an independent opinion. They have conducted an independent examination of the Company's accounting records in order to express their opinion on the consolidated financial statements.

The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility through its Audit Committee. The Audit Committee, which consists of non-management directors, has met with Ernst & Young LLP and management in order to determine that management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The Audit Committee has reported its findings to the Board of Directors, who have approved the consolidated financial statements.

Michael Binnion Jason D'Silva

President and Chief Executive Officer Chief Financial Officer

Calgary, Alberta March 31, 2026

INDEPENDENT AUDITOR'S REPORT

To the shareholders of Questerre Energy Corporation Opinion

We have audited the consolidated financial statements of Questerre Energy Corporation and its subsidiaries (the Group) which comprise the consolidated balance sheets as at December 31, 2025 and 2024, and the consolidated statements of net loss, consolidated statements of comprehensive loss, consolidated statements of changes in equity and consolidated statements of cash flows for the years then ended, and notes to the consolidated financial statements, including material accounting policy information.

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Group as at December 31, 2025 and 2024, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards (IFRSs).

Basis for opinion

We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor's responsibilities for the audit of the consolidated financial statements section of our report. We are independent of the Group in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Key audit matters

Key audit matters are those matters that, in our professional judgment, were of most significance in the audit of the consolidated financial statements of the current period. These matters were addressed in the context of the audit of the consolidated financial statements as a whole, and in forming the auditor's opinion thereon, and we do not provide a separate opinion on these matters. For each matter below, our description of how our audit addressed the matter is provided in that context.

We have fulfilled the responsibilities described in the Auditor's responsibilities for the audit of the consolidated financial statements section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial statements. The results of our audit procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on the accompanying consolidated financial statements.