MERK:QGAS ESEF Annual Report
QUESTERRE EN PREF (MERK:QGAS)
ESEF Annual Report
2026-05-01
For: 2025-12-31
View Original
Added on
September 24, 2026
2025 ANNUAL REPORT
QUESTERRE ENERGY CORPORATION
CONTENTS
President’s Message
Page
1
Management’s Discussion & Analysis
Page
7
Consolidated Financial Statements
Page
43
Notes to the Consolidated
Financial Statements
Page
48
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
.
2025 Annual Report
1
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.
2
Questerre Energy Corporation
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.
2025 Annual Report
3
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.
4
Questerre Energy Corporation
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
2025 Annual Report
5
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/
6
Questerre Energy Corporation
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
2025 Annual Report
7
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
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;
8
Questerre Energy Corporation
•
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;
2025 Annual Report
9
•
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;
10
Questerre Energy Corporation
•
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
2025 Annual Report
11
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.
12
Questerre Energy Corporation
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.
2025 Annual Report
13
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.
14
Questerre Energy Corporation
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
2025 Annual Report
15
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
16
Questerre Energy Corporation
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.
2025 Annual Report
17
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
18
Questerre Energy Corporation
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
2025
2024
Oil and
Natural
Oil and
Natural
Liquids
Gas
Total
Liquids
Gas
Total
(bbls/d)
(Mcf/d)
(boe/d)
(bbls/d)
(Mcf/d)
(boe/d)
Canada
1,387
7,266
2,598
1,021
4,411
1,756
Brazil
950
977
1,113
–
–
–
2,337
8,243
3,711
1,021
4,411
1,756
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.
2025 Annual Report
19
2025 Financial Results
Petroleum and Natural Gas Revenue
2025
2024
Oil and
Natural
Oil and
Natural
($ thousands)
Liquids
Gas
Total
Liquids
Gas
Total
Canada
$
40,411
$
5,052
$
45,463
$
34,191
$
2,736
$
36,927
Brazil
29,554
2,119
31,673
–
–
–
$
69,965
$
7,171
$
77,136
$
34,191
$
2,736
$
36,927
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
2025
2024
Benchmark prices:
Natural Gas - AECO 5A, daily spot ($/GJ)
1.40
1.38
Crude Oil - Canadian Light Sweet Blend ($/bbl)
85.71
97.54
Crude Oil - Brent Crude ($/bbl)
96.66
110.35
Realized prices:
Natural Gas ($/GJ)
2.38
1.65
Crude Oil and Natural Gas Liquids ($/bbl) - Canada
79.80
91.92
Crude Oil and Natural Gas Liquids ($/bbl) - Brazil
85.26
–
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
20
Questerre Energy Corporation
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: $1.65 per GJ).
Royalties
($ thousands)
2025
2024
Canada
$
5,475
$
2,776
Brazil
908
–
$
6,383
$
2,776
% of Revenue:
Canada
8%
8%
Brazil
3%
0%
Total Company
8%
8%
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
($ thousands)
2025
2024
Canada
$
21,822
$
15,158
Brazil
25,544
–
Total Company
$
47,366
$
15,158
$/boe:
Canada
$
23.01
$
23.58
Brazil
62.90
–
Total Company
$
34.97
$
23.58
2025 Annual Report
21
In Canada, operating costs increased over the prior year with higher production volumes. At Kakwa,
Alberta, specifically transportation and disposal of produced water increased by $1.9 million with
production from new wells.
In Brazil, operating costs are largely fixed and include mining, refining and energy costs.
General and Administrative Expenses
($ thousands)
2025
2024
Canada general and administrative expenses
$
9,912
$
5,530
Brazil general and administrative expenses
2,393
–
Transaction costs from acquisition
(3,276)
–
General and administrative expenses, net
$
9,029
$
5,530
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.
22
Questerre Energy Corporation
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.
2025 Annual Report
23
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 $12 million.
Cash Flow used in Financing Activities
Cash used in financing activities for the current year and prior year mainly relates to principal portion of the
lease payments.
Capital Expenditures
($ thousands)
2025
2024
Canada
$
24,068
$
20,640
Brazil
1,551
–
Total
$
25,619
$
20,640
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.
24
Questerre Energy Corporation
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.
2025 Annual Report
25
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.
26
Questerre Energy Corporation
March 31,
December 31,
December 31,
(thousands)
2026
2025
2024
Common Shares
452,213
445,764
428,516
Series 2 Preferred Shares
452,213
–
–
Stock Options
40,110
35,790
38,295
Weighted average Common Shares
Basic
429,083
428,516
Diluted
433,267
431,715
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
Weighted
Weighted
Number of
Average
Number of
Average
Options
Exercise
Options
Exercise
(thousands)
Price
(thousands)
Price
Outstanding, beginning of period
38,295
$
0.25
38,140
$
0.26
Granted
6,675
0.23
6,950
0.25
Forfeited
(2,880)
0.22
(620)
0.27
Expired
(325)
0.16
(6,175)
0.29
Exercised
(5,975)
0.20
–
–
Outstanding, end of period
35,790
$
0.25
38,295
$
0.25
Exercisable, end of period
28,288
$
0.26
29,704
$
0.25
2025 Annual Report
27
Commitments
A summary of the Company’s net commitments at December 31, 2025 follows:
($ thousands)
2026
2027
Total
Transportation and Processing
$
2,153
$
1,043
$
3,196
Refinery maintenance contract
$
15,897
$
1,199
$
17,096
Supply contracts
$
6,149
$
–
$
6,149
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
1
9 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
28
Questerre Energy Corporation
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.
2025 Annual Report
29
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
30
Questerre Energy Corporation
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.
2025 Annual Report
31
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.
32
Questerre Energy Corporation
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
2025 Annual Report
33
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.
34
Questerre Energy Corporation
Quarterly Financial Information
December 31,
September 30,
June 30,
March 31,
($ thousands, except as noted)
2025
2025
2025
2025
Production (boe/d)
7,046
2,926
3,091
1,729
Average Realized Price ($/boe)
65.61
44.32
48.62
58.66
Petroleum and Natural Gas Revenue
42,530
11,801
13,675
9,130
Adjusted Funds Flow from Operations
(1)
4,322
2,813
5,005
3,543
Cash Flow from Operations
1,680
1,294
6,288
3,359
Net Profit (Loss)
(75,066)
(5,334)
(677)
4
Basic and Diluted ($/share)
(0.17)
–
–
–
Capital Expenditures, net of acquisitions and
dispositions
4,459
2,248
1,048
17,864
Working Capital Surplus (Deficit)
(2)
(51,971)
(40,330)
13,157
9,202
Total Assets
395,262
384,853
169,976
181,519
Shareholders' Equity
76,659
135,053
138,355
139,006
Weighted
Average
Common
Shares
Outstanding
Basic (thousands)
429,083
428,516
428,516
428,516
Diluted (thousands)
434,968
434,523
431,505
431,700
(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.
2025 Annual Report
35
December 31,
September 30,
June 30,
March 31,
($ thousands, except as noted)
2024
2024
2024
2024
Production (boe/d)
1,887
1,913
1,559
1,664
Average Realized Price ($/boe)
55.43
53.75
62.36
59.43
Petroleum and Natural Gas Revenue
9,622
9,460
8,847
8,998
Adjusted Funds Flow from Operations
(1)
3,703
3,428
4,455
2,973
Cash Flow from Operations
3,844
4,060
3,141
2,628
Net Profit (Loss)
(8,143)
(273)
1,262
(175)
Basic and Diluted ($/share)
(0.02)
–
–
–
Capital Expenditures, net of acquisitions and
dispositions
7,543
3,433
7,034
2,630
Working Capital Surplus
23,035
27,608
27,620
30,211
Total Assets
170,723
178,731
179,248
172,968
Shareholders' Equity
138,629
145,887
145,941
144,148
Weighted
Average
Common
Shares
Outstanding
Basic (thousands)
428,516
428,516
428,516
428,516
Diluted (thousands)
432,473
431,804
431,327
429,270
(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.
36
Questerre Energy Corporation
•
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.
2025 Annual Report
37
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
38
Questerre Energy Corporation
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.
2025 Annual Report
39
Key Audit Matter
How our audit addressed the key audit matter
Acquisition of Forbes Resources Brazil
As described in Note 5 to the consolidated financial
statements, on September 26, 2025, the Group
acquired 100% of the issued and outstanding
shares of Forbes Resources Brazil Holdings SA
(“FRBH”) for a total consideration of $41.7 million.
The cost of the acquisition was allocated to the fair
values of the assets acquired and liabilities
assumed as at the acquisition date. The preliminary
purchase price allocation included property, plant &
equipment (“PP&E”) of $209.2 million at the
acquisition date.
The estimated acquisition-date fair value of the
PP&E involves significant estimates, including the
estimate of reserves and the related cash flows
(including revenue growth rates, operating margins
and capital expenditures) and the discount rate.
Additionally, the acquisition involved contingent
consideration which has to be fair valued.
Significant auditor judgment was required to
evaluate the results of our audit procedures
regarding the cash flows and the related discount
rate.
To test the Group’s determination of consideration
and preliminary estimates of fair values of the PP&E
we performed the following procedures, among
others:
•
Read the purchase agreement to obtain an
understanding of the key terms and
conditions and to identify the necessary
accounting considerations.
•
Involved our valuation specialists to assess
the Group’s methodology for calculating the
contingent consideration.
•
Compared
projections
to
historical
performance and to available external data
for
revenue
growth
rates,
operating
margins and capital expenditures and
performed sensitivity analysis on significant
assumptions used.
•
With
assistance
of
our
valuations
specialists,
we
evaluated
the
appropriateness of the Group’s discount
rate by comparing to market and other data
and assessed the reasonableness of the
Group’s estimate of the acquisition-date fair
value of PP&E by comparing the Group’s
estimate to market metrics and other
external data.
Evaluated
the
adequacy
of
the
business
combinations note disclosure included in Notes 3
and 5 of the consolidated financial statement in
relation to this matter.
The impact of estimated proved and probable reserves on property, plant and equipment
We draw attention to notes 3 and 9 to the
consolidated financial statements. Producing oil
shale and oil and gas producing assets included in
property, plant and equipment (“PP&E”) are
Our approach to addressing the matter included
the following procedures:
40
Questerre Energy Corporation
depleted on a unit-of-production basis over a
combination of proved and probable reserves taking
into account estimated future development costs
necessary to bring those reserves into production.
The Group had $275.9 million of PP&E at December
31, 2025. Depletion and depreciation expense was
$29.7 million for the year ended December 31,
2025.
Proved and probable reserves were evaluated by
the Group’s independent petroleum engineers
(management’s
expert).
Key
assumptions
developed by management used to determine
reserves
include
forward
commodity
price
estimates, expected future rates of production,
royalty costs and future development expenditures.
We considered this a key audit matter due to the
significant judgments by management, including
the use of management’s expert, and a high degree
of auditor judgment, subjectivity and effort in
performing
procedures
relating
to
the
key
assumptions.
•
Tested
how
management
determined
reserves, which included the following:
•
The
competence,
capabilities
and
objectivity of management’s expert was
evaluated,
the
work
performed
was
understood and the appropriateness of the
work as audit evidence was evaluated. The
procedures
performed
also
included
evaluation of the methods and assumptions
used by management’s expert, tests of
data used by management’s expert and an
evaluation of their findings.
•
Evaluated
the
reasonableness
of
key
assumptions
used,
including
expected
future rates of production, royalty costs and
future
development
expenditures
by
considering current and past performance
of
the
Group
and
whether
these
assumptions
were
consistent
with
evidence obtained in other areas of the
audit, as applicable.
•
Evaluated the reasonableness of forward
commodity price estimates by comparing
those forecasts with third party industry
forecasts.
•
Recalculated the unit-of-production rates
used to calculate depletion and depreciation
expense.
Other information
Management is responsible for the other information. The other information comprises:
•
Management’s discussion and analysis
•
Annual report, other than the financial statements and our auditor’s report thereon
Our opinion on the consolidated financial statements does not cover the other information and we do not
express any form of assurance conclusion thereon.
In connection with our audit of the consolidated financial statements, our responsibility is to read the other
information, and in doing so, consider whether the other information is materially inconsistent with the
consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be
materially misstated.
2025 Annual Report
41
We obtained Management’s discussion and analysis and the Annual Report prior to the date of this
auditor’s report. If, based on the work we have performed, we conclude that there is a material
misstatement of this other information, we are required to report that fact in this auditor’s report. We have
nothing to report in this regard.
Responsibilities of management and those charged with governance for the consolidated
financial statements
Management is responsible for the preparation and fair presentation of the consolidated financial
statements in accordance with IFRSs, and for such internal control as management determines is
necessary to enable the preparation of consolidated financial statements that are free from material
misstatement, whether due to fraud or error.
In preparing the consolidated financial statements, management is responsible for assessing the Group’s
ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using
the going concern basis of accounting unless management either intends to liquidate the Group or to cease
operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Group’s financial reporting process.
Auditor’s responsibilities for the audit of the consolidated financial statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as
a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report
that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an
audit conducted in accordance with Canadian generally accepted auditing standards will always detect a
material misstatement when it exists. Misstatements can arise from fraud or error and are considered
material if, individually or in the aggregate, they could reasonably be expected to influence the economic
decisions of users taken on the basis of these consolidated financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise
professional judgment and maintain professional skepticism throughout the audit. We also:
•
Identify and assess the risks of material misstatement of the consolidated financial statements,
whether due to fraud or error, design and perform audit procedures responsive to those risks, and
obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk
of not detecting a material misstatement resulting from fraud is higher than for one resulting from
error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the
override of internal control.
•
Obtain an understanding of internal control relevant to the audit in order to design audit procedures
that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the
effectiveness of the Group’s internal control.
•
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting
estimates and related disclosures made by management.
42
Questerre Energy Corporation
•
Conclude on the appropriateness of management’s use of the going concern basis of accounting
and, based on the audit evidence obtained, whether a material uncertainty exists related to events
or conditions that may cast significant doubt on the Group’s ability to continue as a going concern.
If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s
report to the related disclosures in the consolidated financial statements or, if such disclosures are
inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up
to the date of our auditor’s report. However, future events or conditions may cause the Group to
cease to continue as a going concern.
•
Evaluate the overall presentation, structure and content of the consolidated financial statements,
including the disclosures, and whether the consolidated financial statements represent the
underlying transactions and events in a manner that achieves fair presentation.
•
Plan and perform the group audit to obtain sufficient appropriate audit evidence regarding the
financial information of the entities or business units within the Group as a basis for forming an
opinion on the consolidated financial statements. We are responsible for the direction, supervision
and review of the audit work performed for the purposes of the group audit. We remain solely
responsible for our audit opinion.
We communicate with those charged with governance regarding, among other matters, the planned scope
and timing of the audit and significant audit findings, including any significant deficiencies in internal control
that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant
ethical requirements regarding independence, and to communicate with them all relationships and other
matters that may reasonably be thought to bear on our independence, and where applicable, related
safeguards.
From the matters communicated with those charged with governance, we determine those matters that
were of most significance in the audit of the consolidated financial statements of the current period and
are therefore the key audit matters. We describe these matters in our auditor’s report unless law or
regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we
determine that a matter should not be communicated in our report because the adverse consequences of
doing so would reasonably be expected to outweigh the public interest benefits of such communication.
The engagement partner on the audit resulting in this independent auditor’s report is Robert Mitchell.
Chartered Professional Accountants
Calgary, Canada
March 31, 2026
2025 Annual Report
43
Consolidated Balance Sheets
December 31,
December 31,
($ thousands)
Notes
2025
2024
Assets
Current Assets
Cash and cash equivalents
7
$
$
Accounts receivable
19
Inventory
8
Deposits and prepaid expenses
Investments
6
Property, plant and equipment
9
Exploration and evaluation assets
10
Intangible assets
11
Right-of-use assets
16
Restricted cash
7
Other non current assets
13
Goodwill
5
$
$
Liabilities
Current Liabilities
Accounts payable and accrued liabilities
19
$
$
Advances from customers
19
Contingent consideration for original acquisition of PX Energy
17,19
Share issuance liability for acquisitions
5,6,19
Current liabilities related to business combination
5
Lease liabilities
16
Asset retirement obligations
15
Other current liabilities
18
Lease liabilities
16
Contingent consideration for original acquisition of PX Energy
17
Secured debt
14
Other long term liabilities
18
Asset retirement obligation
15
Deferred tax liability
12
Shareholders' Equity
Share capital
21
Contributed surplus
21
Accumulated other comprehensive income (loss)
(2,630 )
Deficit
(400,363 )
(321,428 )
$
$
The notes are an integral part of these consolidated financial statements.
Signed on behalf of the Board of Directors
Signed
(Signed) Bjorn Inge Tonnessen, Director
(Signed) Dennis Sykora, Director
44
Questerre Energy Corporation
Consolidated Statements of Net Loss
For the year ended December 31,
($ thousands, except per share amounts
)
Notes
2025
2024
Revenue
Petroleum and natural gas revenue
22
$
$
Royalties
(6,383 )
(2,776 )
Petroleum and natural gas revenue, net of royalties
$
$
Expenses
Operating
General and administrative
Depletion and depreciation
9,11,16
Impairment
9
Accretion
15
(Gain) loss on equity investment
6
(2,388 )
Transaction costs
5
Share based compensation
20
Other gains
23
(1,613 )
$
$
Finance income
24
Finance expense
24
(14,780 )
(4 )
Loss before taxes
$
(81,076 )
$
(7,329 )
Deferred tax recovery
12
(2,141 )
Net loss
$
(78,935 )
$
(7,329 )
Net Loss per Share
Basic and diluted
21
$
(0.18
$
(0.02
The notes are an integral part of these consolidated financial statements.
2025 Annual Report
45
Consolidated Statements of Comprehensive Loss
For the year ended December 31,
($ thousands, except per share amounts
)
Notes
2025
2024
Net loss
$
(78,935 )
$
(7,329 )
Other Comprehensive (loss) Income, Net of Tax
Items that may be reclassified subsequently to profit or loss:
Foreign currency translation adjustment
$
(3,526 )
$
Income on foreign exchange on investment
(3,526 )
Total Comprehensive Loss
$
(82,461 )
$
(6,413 )
The notes are an integral part of these consolidated financial statements.
46
Questerre Energy Corporation
Consolidated Statements of Changes in Equity
For the year ended December 31,
($ thousands)
2025
2024
Share Capital
Balance, beginning of year
$
$
Shares issued for acquisition (Note 6)
Balance, beginning and end of year
Contributed Surplus
Balance, beginning of year
$
$
Contingent consideration for business combination classified as equity
(Note 5)
Share based compensation
Balance, end of year
Accumulated Other Comprehensive (Loss) Income
Balance, beginning of year
$
$
(20 )
Other comprehensive (loss) income
(3,526 )
Balance, end of year
(2,630 )
Deficit
Balance, beginning of year
$
(321,428 )
$
(314,099 )
Net loss
(78,935 )
(7,329 )
Balance, end of year
(400,363 )
(321,428 )
Total Shareholders' Equity
$
$
The notes are an integral part of these consolidated financial statements.
2025 Annual Report
47
Consolidated Statements of Cash Flows
For the year ended December 31,
($ thousands)
Notes
2025
2024
Operating Activities
Net loss
$
(78,935 )
$
(7,329 )
Adjustments for:
Depletion and depreciation
9,11,16
Accretion of asset retirement
15
Impairment
9,10
(Gain) loss on equity investment
6
(2,388 )
Share based compensation
20
Net finance expense
24
(1,149 )
Deferred tax recovery
12
(2,141 )
Other items not involving cash
27
Cash taxes paid
(473 )
Cash interest (paid) received
(339 )
Abandonment expenditures
15
(1,072 )
(49 )
Change in non-cash working capital
27
(890 )
Net cash from operating activities
$
$
Investing Activities
Property, plant and equipment expenditures
9
(9,611 )
(4,046 )
Exploration and evaluation expenditures
10
(16,008 )
(16,594 )
Cash acquired from asset acquisition
6
Cash acquired through business combination
5
Payment made by subsidiary for contingent consideration
17
(2,160 )
Restricted cash
Change in non-cash working capital
27
(3,266 )
Net cash used in investing activities
(18,848 )
(16,855 )
Financing Activities
Principal portion of lease payments
16
(243 )
(65 )
Net cash used in financing activities
(243 )
(65 )
Effect of foreign exchange on cash and cash equivalents
Change in cash and cash equivalents
(6,473 )
(3,251 )
Cash and cash equivalents, beginning of year
Cash and cash equivalents, end of year
$
$
The notes are an integral part of these consolidated financial statements
.
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025, and 2024
48
Questerre Energy Corporation
company actively engaged in the acquisition, exploration and development of oil and gas projects,
incorporated under the laws of the Province of Alberta and is domiciled in Canada
and its wholly-owned subsidiaries including Questerre Energy Corporation/Jordan, which holds interests
in Jordan, Paraná Xisto S.A. (“PX Energy”), based in Brazil that owns the integrated oil shale assets in the
country and Red Leaf Resources Inc. (Red Leaf”), a technology company in the USA focused on
Management has determined the operating segments based on information regularly reviewed for the
purposes of decision making, allocating resources, and assessing operational performance by Questerre’s
chief operating decision makers comprising of the Chief Executive Officer and other members of executive
management. The operating segments have been aggregated based on several factors including
geographic location and stage of development as well as the assignment of reserves and resources.
The accounting policies applied by the segments are the same as those applied by the Company.
The Company’s operating segments at year-end are as follows:
•
Brazil – Integrated oil shale operations include, mining, refining, processing, and distribution
•
Western Canada – Exploration and development activities in Western Canada including Alberta,
Saskatchewan and Manitoba with existing production of natural gas, crude oil and natural gas
liquids
•
Quebec – Claim against the Government of Quebec for an attempted revocation of licenses for a
significant natural gas discovery in the province
•
Corporate & other – General and administrative resources to manage the respective operating
Segmented assets are those assets associated with each operating segment as recorded on the
consolidated balance sheets.
2025 Annual Report
49
The table below details the breakdown of assets by operating segment to the consolidated balance sheets
and the reconciliation of loss by operating segment to the consolidated statements of net loss and
comprehensive loss.
| Western |
Corporate |
||||
($ thousands ) |
Brazil |
Canada |
Quebec |
& other |
Consolidated |
Assets by operating segment |
|||||
Exploration and Evaluation |
$ – |
$ 5,599 |
$ – |
$ – |
$ 5,599 |
Property, Plant & Equipment |
190,765 |
81,589 |
– |
3,570 |
275,924 |
Other |
35,004 |
51,456 |
– |
27,278 |
113,739 |
Total Assets, December 31, 2025 |
$ 225,770 |
$ 138,644 |
$ – |
$ 30,848 |
$ 395,262 |
Exploration and Evaluation |
$ – |
$ 13,106 |
$ – |
$ – |
$ 13,106 |
Property, Plant & Equipment |
– |
116,695 |
– |
– |
116,695 |
Other |
– |
4,644 |
7,551 |
28,727 |
40,922 |
Total Assets, December 31, 2024 |
$ – |
$ 134,445 |
$ 7,551 |
$ 28,727 |
$ 170,723 |
Results by operating segment |
|||||
Revenues |
$ 31,673 |
$ 45,463 |
$ – |
$ – |
$ 77,136 |
Operating costs including royalties |
(26,452) |
(26,575) |
(722) |
– |
(53,749) |
General and administrative |
(2,393) |
(5,143) |
(1,493) |
– |
(9,029) |
Depletion, depreciation, impairment and accretion |
(14,556) |
(67,716) |
– |
– |
(82,272) |
Other income (expenses) |
(11,128) |
– |
– |
(2,034) |
(13,162) |
Loss before taxes |
$ (22,856) |
$ (53,971) |
$ (2,215) |
$ (2,034) |
$ (81,076) |
Deferred tax recovery |
2,141 |
||||
Net Loss, December 31, 2025 |
$ |
(78,935) |
|||
Revenues |
$ – |
$ 36,927 |
$ – |
$ – |
$ 36,927 |
Operating costs including royalties |
– |
(17,262) |
(671) |
– |
(17,933) |
General and administrative |
– |
(5,530) |
– |
– |
(5,530) |
Depletion, depreciation, impairment and accretion |
– |
(20,348) |
– |
– |
(20,348) |
Other income (expenses) |
– |
– |
– |
(445) |
(445) |
Loss before taxes |
$ – |
$ (6,213) |
$ (671) |
$ (445) |
$ (7,329) |
Deferred tax recovery |
– |
||||
Net Loss, December 31, 2024 |
$ |
(7,329) |
50
Questerre Energy Corporation
The Company prepares its consolidated financial statements in accordance with International Financial
Reporting Standards (“IFRS”) as issued by the International Accounting Standards Boards (“IASB”). The
policies applied in these consolidated financial statements are based on IFRS issued and outstanding as at
b) Basis of measurement
The consolidated financial statements have been prepared on the historical cost basis except for financial
assets classified as fair value through profit and loss which are measured at fair value with changes in fair
value recorded in profit or loss and changes due to currency translation adjustments recorded through
other comprehensive income or loss as disclosed in Note
The functional currency of the Company’s subsidiary in Brazil is the Brazilian real, Jordanian dinar for
The Company conducts many of its oil and gas production activities through jointly controlled operations.
Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the
rights and obligations of the parties to the arrangement. Joint operations arise when the Company has
rights to the assets and obligations for the liabilities of the arrangement. The Company recognizes its share
of assets, liabilities, revenues and expenses of a joint operation. Joint ventures arise when the Company
The timely preparation of 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.
Petroleum and natural gas reserves
All of Questerre’s petroleum and natural gas reserves are evaluated and reported on by independent
reserve engineers in accordance with the COGE Handbook and Canadian Securities Administrators’
National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities
. The estimation of reserves
is a subjective process. Forecasts are based on engineering data, anticipated future commodity prices,
expected production volumes, future operating and development costs, all of which are subject to
2025 Annual Report
51
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 areas, in particular, the valuation of property, plant, and equipment (“PP&E”), and the
calculation of depletion. All reserves have been evaluated at December 31, 2025, by an independent
qualified reserves evaluators.
Identification of cash-generating units
The Company’s assets are aggregated into cash-generating units (“CGU”) for the purpose of calculating
depletion and impairment. 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 gas properties, including exploration and evaluation assets (“E&E”) 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.
The recoverable amounts of CGUs have been determined based on the higher of value in use (“VIU”) and
the fair value less costs of disposal (“FVLCD”). The net book value of PP&E recognized is based on
historical cost until tested for impairment using market values. The market value of PP&E is the estimated
amount for which PP&E could be exchanged on the acquisition date between a willing buyer and a willing
seller in an arm’s length transaction after proper marketing wherein the parties had each acted
knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests
(included in PP&E) are generally estimated with reference to the discounted cash flows expected to be
derived from oil and natural gas production based on internally and externally prepared reserve reports.
The significant assumptions are based on Level 3 unobservable information with the primary inputs being
forecasted production, escalated pricing, royalties, operating costs, future development costs. The after-
52
Questerre Energy Corporation
tax discount rate is specific to the asset with reference to general market conditions. The market value of
E&E assets is estimated with reference to the market values of current arm’s length transactions in
comparable locations.
Exploration and evaluation assets
The application of the Company's accounting policy for E&E requires judgement in determining whether it
is likely that future economic benefit exists when activities have not reached a stage where technical
feasibility and commercial viability can be reasonably determined. In addition, Management uses
judgement to determine when E&E assets are reclassified to PP&E assets.
Exploration and evaluation assets are subject to ongoing management review to confirm the continued
intent to establish the technical feasibility and commercial viability of the assets. In making this
determination, various factors are considered such as drilling results, future capital and operating
expenditures, including judgement over the amount of economically recoverable resources, and whether
the appropriate government, regulatory, or internal approvals are likely to be received.
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.
In a business combination, management makes estimates of the acquisition-date fair value of assets
acquired and liabilities assumed which includes assessing the estimated fair value of petroleum and natural
Asset retirement obligation
Determination of the Company’s asset retirement obligation is based on Government regulations, operator
estimates and 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.
2025 Annual Report
53
Share based compensation
The Company has a stock option plan enabling employees, officers and directors to receive Class
“A”
Common voting shares (“Common Shares”) or cash at exercise prices equal to the market price or above
on the date the option is granted. The Company has the right and full discretion to settle any exercised
options by issuing shares and accordingly uses the equity settled method of accounting. 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
The accounting policies set out below have been applied consistently to all periods presented in these
consolidated financial statements.
Subsidiaries
Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to
govern the financial and operating policies of an entity to obtain benefits from its activities. In assessing
ii)
Transactions eliminated on consolidation
Intercompany balances and transactions, and any unrealized income and expenses arising from
i)
Foreign currency transactions
Transactions in foreign currencies are translated into the respective entity's functional currency at the
exchange rates at the dates of the transactions. Monetary assets and liabilities denominated in foreign
currencies are translated into the functional currency at the exchange rate at the reporting date. Non-
monetary assets that are measured in a foreign currency at historical cost are translated using the exchange
rate at the date of the transaction. Translation gains and losses are included in earnings in the period in
which they arise.
ii)
Foreign Operations
In preparing the Company's consolidated financial statements, the financial statements of each entity are
translated into Canadian dollars. The assets and liabilities of foreign operations are translated at the
exchange rates at the reporting date. The revenues and expenses of foreign operations are translated at
the exchange rates that approximate those dates of the transactions.
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Questerre Energy Corporation
Foreign currency differences are recognized in other comprehensive income ("OCI") and accumulated in
The purchase method of accounting is used to account for acquisitions of businesses and assets that meet
the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the
assets given up, equity instruments issued and liabilities incurred or assumed at the date of exchange.
Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are
measured initially at their acquisition date fair values. If the consideration of acquisition given up is less
than the fair value of the net assets received, the difference is recognized immediately in the income
statement. If the consideration of acquisition is greater than the fair value of the net assets received, the
difference is recognized as goodwill on the statement of financial position. Acquisition costs incurred are
expensed.
There is an option to apply a concentration test that permits a simplified assessment of whether an
acquired set of activities and assets is in fact a business. The optional concentration test is met if
substantially all of the fair value of the assets acquired is concentrated in a single identifiable asset or group
of similar identifiable assets. An entity may make such an election separately for each transaction or other
event. If the concentration test is met, the set of activities and assets is determined not to be a business
Financial assets and liabilities are recognized when the Company becomes a party to the contractual
provisions of the instrument. Financial assets are derecognized when the rights to receive cash flows from
the assets have expired or have been transferred and the Company has transferred substantially all risks
and rewards of ownership. Financial liabilities are derecognized when the obligation specified in the
is a legally enforceable right to offset the recognized amounts and there is an intention to settle on a net
The Company classifies its financial instruments in the following categories, at initial recognition,
depending on the purpose for which the instruments were acquired.
A financial asset or liability is classified in this category if it is held for trading. Derivatives are also included
in this category unless they are designated as hedges. The Company has designated its risk management
Financial assets at amortized cost are non-derivative financial assets with fixed or determinable payments
that are not quoted in an active market. They include accounts receivable and deposits. These assets are
2025 Annual Report
55
included in current assets due to their short-term nature. They are recognized initially at the amount
expected to be received, less, when material, a discount to reduce to fair value. Subsequently, they are
deposits with original maturities of one
Financial liabilities at amortized cost comprise credit facilities and accounts payable and accrued liabilities.
Financial liabilities are initially recognized at the amount required to be paid, less, when material, a discount
to reduce the payables to fair value. Subsequently, financial liabilities are measured at amortized cost using
the effective interest method.
Financial liabilities are classified as current liabilities if payment is due within twelve
The Company had investment in certain private companies including its investment in Red Leaf. The
Company acquired remainder of Red Leaf in December 2025. Thereafter, Red Leaf is a wholly owned
Common Shares are classified as equity. Incremental costs directly attributable to the issue of Common
Exploration and evaluation costs, including the costs of acquiring licenses, exploratory well expenditures,
costs to evaluate the commercial potential of underlying resources and directly attributable general and
administrative costs, are capitalized as E&E assets. The costs are accumulated in cost centres by
exploration area pending determination of technical feasibility and commercial viability. Gains and losses
on E&E assets are recognized on disposal through the income statement.
The technical feasibility and commercial viability of extracting a mineral resource is considered to be
determinable based on several factors including the assignment of reserves. A review of each exploration
license or field is carried out, at each reporting date, to ascertain whether technical feasibility and
commercial viability has been achieved. Upon determination of technical feasibility and commercial
viability, intangible exploration and evaluation assets attributable to those reserves are first tested for
impairment and then reclassified from exploration and evaluation assets to property, plant and equipment.
Every reporting period, the Company evaluates individually significant exploration and evaluation wells for
impairment, if there are specific impairment indicators evident at the well level. If technical feasibility and
commercial viability of the well is not established, the well costs are written off. For insignificant wells,
overall exploration and evaluation well indicators are evaluated. If there are indicators of impairment, the
wells are tested for impairment at the CGU level.
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Questerre Energy Corporation
Costs incurred prior to acquiring the legal rights to explore an area are recognized as exploration and
The costs to acquire and to develop oil and gas properties, including completing geological and geophysical
surveys and drilling development wells, and the costs to construct and install development infrastructure
are capitalized as oil and gas properties within Property, Plant and Equipment. Items of PP&E, which
include oil and gas development and production assets, are measured at cost less accumulated depletion
and depreciation and accumulated impairment losses.
The costs of planned major inspection, overhaul and turnaround activities that maintain PP&E and benefit
future years of operations are capitalized. Recurring planned maintenance activities performed on shorter
intervals are expensed as operating costs. Replacements outside of a major inspection, overhaul or
turnaround are capitalized when it is probable that future economic benefits will be realized by the company
and the associated carrying amount of the replaced component is derecognized.
Borrowing costs relating to assets that take over one year to construct are capitalized as part of the asset.
Capitalization of borrowing costs ceases when the asset is in the location and condition necessary for its
intended use, and is suspended when construction of an asset is ceased for extended periods.
Gains and losses on disposal of an item of PP&E, including oil and natural gas interests, are determined by
comparing the proceeds from disposal with the carrying amount of the property, plant and equipment and
are recognized net within gain (loss) on divestures in profit or loss.
Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or
fair value cannot be reliably measured. When the exchange is at fair value, a gain or loss is recognized in
profit or loss.
The net carrying value of development and production assets is depleted using the unit of production
method based on estimated proved and probable reserves, considering estimated future development
costs necessary to bring those reserves into production. These estimates are evaluated by independent
reserve engineers at least annually.
For the capital assets, depreciation is recognized in profit or loss on a straight-line basis over the respective
useful lives.
Intangibles assets are measured at historical acquisition costs or at fair value when acquired in a business
combination, net of accumulated amortization and, if applicable, accumulated impairment losses.
Subsequent expenditures are capitalized only when they increase the future economic benefits embodied
in the specific asset to which they relate.
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57
Amortization is calculated using the straight-line method based on the estimated useful life of the assets,
In the event of a business combination or acquisition in which the activity constitutes a business, as defined
in IFRS 3 Business Combinations, the acquisition method of accounting is applied. Goodwill represents
the difference between the aggregate of the fair value of purchase consideration transferred at the
acquisition date and the fair value of the identifiable assets, liabilities and contingent liabilities acquired,
less any non-controlling interest. The Company's goodwill is related to the requirement to recognize
deferred tax for the difference between the assigned fair values and the related tax base (technical
goodwill). In accordance with IAS 12 paragraphs 15 and 24, a provision is made for deferred tax
corresponding to the difference between the acquisition cost and the transferred tax depreciation basis.
The offsetting entry to this deferred tax is goodwill. Hence, goodwill arises as a technical effect of deferred
tax. Goodwill is initially measured at cost. Following initial recognition, goodwill is measured at cost less
any accumulated impairment. Goodwill is treated as an asset of the relevant entity to which it relates, and
accordingly goodwill is translated into Canadian dollars at the closing rate of exchange at each reporting
date. Impairments are expected to arise as the deferred tax that gave rise to the goodwill initially naturally
unwinds in the normal course of business. Impairment losses relating to goodwill cannot be reversed in
The carrying amounts of the Company’s non-financial assets, are reviewed at each reporting date to
determine whether there is any indication of impairment. If any such indication exists, then the asset’s
recoverable amount is estimated and compared to the carrying amount. Goodwill is tested for impairment
annually.
For the purpose of impairment testing, assets are grouped together into CGUs. Exploration and evaluation
assets are allocated to related CGUs when they are assessed for impairment, both at the time of any
triggering facts and circumstances as well as upon their reclassification to producing assets.
The recoverable amount of an asset or a CGU is the greater of its VIU and FVLCD. FVLCD is determined
using discounted future cash flows of proved and probable reserves using an after tax discount rate for
FVLCD. In determining FVLCD, recent market transactions are considered, if available. In the absence of
such transactions, the discounted cash flow model is used. In assessing VIU, the estimated future cash
flows are discounted to their present value using a pre-tax discount rate that reflects current market
assessments of the time value of money and the risks specific to the asset.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated
recoverable amount. Impairment losses are recognized in profit or loss.
Impairment losses recognized in prior
years are assessed at each reporting date for any indications that
the loss has decreased or no longer exists. An impairment loss is reversed for all CGUs, other than
58
Questerre Energy Corporation
goodwill, if there has been a change in the estimates used to determine the recoverable amount. An
impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the
carrying amount that would have been determined, net of depletion and depreciation or amortization, if no
Questerre applies the simplified approach to providing for expected credit losses prescribed by IFRS 9
Financial Instruments
(“IFRS 9”) which permits the use of the lifetime expected loss provision for all trade
receivables carried at amortized costs.
At each reporting date, the Company measures the lifetime expected loss provision taking into
consideration Questerre’s historical credit loss experience as well as forward-looking information in order
to establish loss rates. The impairment loss (or reversal) is the amount of expected credit losses that is
The Company has issued options to directors, officers and employees.
The Company accounts for its stock-based compensation awards on the basis that they will be equity
settled. Under the equity settled method, compensation costs attributable to stock options granted to
employees, officers or directors are measured at fair value at the grant date and expensed over the vesting
period with a corresponding increase to contributed surplus. The exercise of stock options is recorded as
an increase in Common Shares with a corresponding reduction in contributed surplus. A forfeiture rate is
A provision is recognized if, as a result of a past event, the Company has a present legal or constructive
obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be
required to settle the obligation. Provisions are determined by discounting the expected future cash flows
at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific
to the liability.
The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation
activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset
Asset retirement obligations are measured at the present value of management’s best estimate of
expenditure required to settle the present obligation at the balance sheet date. The best estimate of the
provision is recorded on a discounted basis using a risk-free interest rate. Subsequent to the initial
measurement, the obligation is adjusted at the end of each period to reflect the passage of time and
changes in the estimated future cash flows underlying the obligation. The increase in the provision due to
the passage of time is recognized as accretion of the asset retirement obligation whereas increases or
2025 Annual Report
59
decreases due to changes in the estimated future cash flows and risk-free rates are adjusted through
property, plant and equipment or exploration and evaluation assets. Actual costs incurred upon settlement
Questerre principally generates revenue from the sale of commodities and revenue from royalties on
production from leases where it owns a working interest. Revenue is based on the consideration specified
in a contract and is recorded when control of the product or service passes to the customer in accordance
with terms of the contract. Questerre considers its performance obligations to be satisfied and control to
be transferred when all of the following conditions are satisfied:
•
Questerre has transferred title and physical possession of the commodity to the buyer;
•
Questerre has transferred the significant risks and rewards of ownership of the commodity to the
buyer; and
•
Questerre has the present right to payment.
Revenue represents the Company’s share of commodity sales net of royalty obligations to governments
and other mineral interest owners. Questerre sells its production pursuant to variable priced contracts. The
transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location
or other factors, whereby each component of the pricing formula can be either fixed or variable, depending
on the contract terms. Under these contracts, the Company is required to deliver a variable volume of
crude oil, natural gas, condensate or NGLs and refined products to the contract counterparty.
Revenue is recognized when a unit of production is delivered to the contract counterparty. The amount of
revenue recognized is based on the agreed upon transaction price, whereby any variability in revenue is
related specifically to the Company’s efforts to deliver production. Therefore, the resulting revenue is
allocated to the production delivered in the period during which the variability occurs. Revenues are
normally collected in the month following delivery except where contract states due upon delivery.
Questerre does not have any contracts where the period between the transfer of the promised goods or
services to the customer and payment by the customer exceeds one year and therefore Questerre does
not adjust its revenue transactions for the time value of money. The Company enters into contracts with
customers that can have performance obligations that are unsatisfied, or partially unsatisfied, at the
reporting date.
Royalty revenue is recognized as it accrues in accordance with the terms of the governing agreement,
which is generally in the month when the product is produced with production volumes primarily marketed
with the payor’s production. Royalty revenue is measured at fair value of the consideration received when
Management can reliably estimate the amount pursuant to the terms of the royalty agreement. An accrual
is included in revenue and accounts receivable for amounts not received at the reporting date based on
historical trends, new wells on stream and current market prices. Differences between the estimates and
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Questerre Energy Corporation
Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss
except to the extent that it relates to items recognized directly in equity, in which case it is recognized in
equity.
Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or
substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.
Deferred tax is recognized using the balance sheet method, providing for temporary differences between
the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for
taxation purposes.
Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a
business combination. Deferred tax is measured at the tax rates that are expected to be applied to
temporary differences when they reverse, based on the laws that have been enacted or substantively
enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable
right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity,
or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their
tax assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available
against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting
The effect of a change in enacted or substantively enacted income tax rates on future income tax assets
and liabilities is recognized in profit or loss in the period that the change occurs unless the original entry
The Company’s crude oil inventories may be marketed in their raw state, as well as consumed in the
production process of their by-products. Work-in-process products are composed of product streams that
have already gone through at least one processing unit but still need to be processed, treated, or converted
to be made available for sale. Materials and supplies mainly represent production inputs and operating
materials that will be used in the Company’s activities and are presented at average purchase cost.
Product inventories are valued at the lower of cost, using a first-in, first-out, or weighted average cost
basis, and net realizable value. Parts and supplies are valued at the lower of weighted average cost and
net realizable value. The cost of inventory includes purchase costs, direct production costs, and depletion,
depreciation and accretion (“DD&A”). Net realizable value is the estimated selling price in the ordinary
course of business less expected selling costs. If the carrying amount exceeds net realizable value, a write-
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61
Basic per share amounts are calculated using the weighted average number of shares outstanding during
the
year. Diluted per share amounts are calculated using the weighted average number of shares
outstanding, adjusted for the potential number of shares which may have a dilutive impact on net profit.
Potentially dilutive shares include stock options. The weighted average number of diluted shares is
calculated in accordance with the treasury stock method. The treasury stock method assumes that the
proceeds received from the exercise of all potentially dilutive instruments are used to repurchase Common
Shares at the average market price.
Since the options may be settled in cash or shares at the Company’s discretion and therefore there is no
obligation to settle in cash, the share units are accounted for as equity-settled share based payment
Under IFRS 16, the Company recognizes right-of-use assets and lease liabilities for most leases. Certain
short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements
and may continue to be treated as operating leases. The right-of-use assets recognized are subsequently
depreciated using the straight-line method from the commencement date to the earlier of the end of the
useful life of the right-of-use assets or the end of the lease term. The estimated useful lives of right-of-use
assets are determined on the same basis as those of property and equipment. In addition, the right-of-use
assets are periodically reduced by impairment losses, if any, and adjusted for certain re-measurements of
the lease liabilities.
The lease liabilities are initially measured at the present value of the lease payments that are not paid at
the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be
readily determined, the Company's incremental borrowing rate. The Company uses its incremental
borrowing rate as the discount rate.
The lease liabilities are subsequently measured at amortized cost using the effective interest method. It is
re-measured when there is a change in future lease payments arising from a change in an index or rate, if
there is a change in the Company's estimate of the amount expected to be payable under a residual value
guarantee, or if the Company changes its assessment of whether it will exercise a purchase, extension or
termination option.
When the lease liabilities are re-measured in this way, a corresponding adjustment is made to the carrying
amount of the right-of-use assets or is recorded in profit or loss if the carrying amount of the right-of-use
assets has been reduced to nil. The Company presents right-of-use assets and lease liabilities separately
in the balance sheet.
The application of IFRS 16 requires significant judgments and estimations to be made. Areas that require
judgment include identifying whether a contract (or part of a contract) includes a lease, determining
whether it is reasonably certain that an extension or termination option will be exercised, determining
whether variable payments are in substance fixed, establishing whether there are multiple leases in an
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Questerre Energy Corporation
arrangement and determining the stand-alone amounts for lease and non-lease components. Other
sources of estimation uncertainty in the application of IFRS 16 include estimating the lease term,
determining the appropriate discount rate to apply to lease payments and assessing whether a right-of-use
New Accounting Standards and Interpretations not yet Adopted
There are new accounting standards, amendments to accounting standards and interpretations that are
effective for annual periods beginning on or after January 1, 2026, and have not been applied in preparing
the Consolidated Financial Statements for the year ended December 31, 2025. The standards applicable
to the Company are as follows and will be adopted on their respective dates:
Financial Instruments
On May 30, 2024, the IASB issued amendments to IFRS 9, “Financial Instruments”, and IFRS 7, “Financial
Instruments: Disclosures”. The amendments include clarifications on the derecognition of financial
liabilities and the classification of certain financial assets. In addition, new disclosure requirements for
equity instruments designated as FVOCI were added. The amendments are effective for annual periods
beginning on or after January 1, 2026, and will be applied retrospectively. The amendments to IFRS 9 and
IFRS 7 will not have a material impact on the Consolidated Financial Statements.
Presentation and Disclosure in Financial Statements
On April 9, 2024, the IASB issued IFRS 18, “Presentation and Disclosure in Financial Statements” (“IFRS
18”), which will replace International Accounting Standard 1, “Presentation of Financial Statements”. IFRS
18 will establish a revised structure for the Consolidated Statements of Comprehensive Income (Loss) and
improve comparability across entities and reporting periods. IFRS 18 is effective for annual periods
beginning on or after January 1, 2027. The standard is to be applied retrospectively, with certain transition
provisions. The Company is continuing to evaluate the impacts of adopting IFRS 18 on the Consolidated
Financial Statements. The Company will adopt IFRS 18 effective January 1, 2027, using the retrospective
approach
On September 26, 2025, the Company closed the acquisition of 100% of the common shares of PX Energy,
a privately held oil shale production and refining company based in southern Brazil (the “Acquisition”). The
Acquisition was completed by 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.
The Acquisition has been accounted for using the acquisition method in accordance with IFRS 3 Business
Combinations. Under the acquisition method, assets and liabilities are measured at their estimated fair
value on the date of acquisition. The total consideration was allocated to the assets acquired and liabilities
assumed. Transaction related costs are recorded in the income statement.
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63
Purchase Price Allocation
The Consideration consisted of (i) 15 million Class “A” common voting shares of Questerre Common
Shares (the “First Tranche Common Shares”), subject to a lock-up and voting agreement, with a deemed
value of $5.0 million; (ii) contingent equity consideration consisting of two additional tranches of 25 million
Common Shares, with an estimated fair value of $13.9 million at the acquisition date; and (iii) convertible
promissory notes with principal of $15.2 million, and the assumption of a certain liabilities including
obligations under a business combination agreement (“BCA”) with a special purpose acquisition company
(“SPAC”) with an estimated fair value of $7.6 million.
The contingent equity consideration is issuable upon the earlier of: (a) 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 completion of an equity financing of $25 million at $0.50 per common share on or before
September 30, 2027; and (b) 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 completion of an equity
financing of $25 million at $1.00 per common share on or before September 30, 2028. The contingent
equity consideration has been classified as equity.
As of December 31, 2025, the First Tranche Common Shares had not been issued. The obligation to issue
the shares has been recorded as liability.
Convertible Promissory Notes and Current Liabilities
As part of the Acquisition, the Company assumed the vendor’s obligations under the BCA with the SPAC.
Pursuant to the BCA, the Company’s wholly owned subsidiary is required to complete a go-public
transaction with the SPAC, subject to certain conditions precedent, including 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. At the acquisition date, the Company recognized assumed
obligations and other liabilities related to BCA with an estimated fair value of $7.6 million.
In addition, subject to the issuance of the First Tranche Common Shares and related conditions under the
BCA, the Company’s subsidiary will assume convertible promissory notes. An obligation has been recorded
to assume the notes measured at their fair value of $15.2 million. As at December 31, 2025, the notes
have not been assumed and the obligation remains outstanding.
Upon completion of the SPAC transaction, the notes are convertible into common shares of the SPAC. If
the SPAC transaction does not proceed, the notes are due and payable or convertible into equity of the
Company’s subsidiary.
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Questerre Energy Corporation
The following table summarizes the preliminary allocation of the consideration and the fair values of the
assets acquired and liabilities assumed at the date of the acquisition and is subject to change upon the
final adjustments to working capital:
Consideration Transferred | ($ thousands ) |
Pending share issuance for acquisition | $ 4,950 |
Contingent equity consideration | 13,941 |
Assumed liabilities of the vendor | 22,760 |
Total consideration transferred | $ 41,651 |
Identifiable Assets Acquired and Liabilities Assumed | ($ thousands ) |
Cash and cash equivalents | $ 1,228 |
Restricted cash | 1,254 |
Accounts receivable | 5,920 |
Prepaid tax contributions | 7,572 |
Inventory | 9,128 |
Deposits and prepaid expenses | 3,351 |
Right-of-use assets | 1,698 |
Property, plant and equipment | 209,203 |
Intangible asset | 5,755 |
Other assets | 709 |
Goodwill | 47,900 |
Total assets acquired | $ 293,718 |
Accounts payable and accrued liabilities | $ (15,792) |
Advances from customers | (10,320) |
Tax Contributions | (24,964) |
Lease liabilities | (1,698) |
Deferred tax liability | (61,873) |
Provisions | (15,333) |
Contingent consideration for original acquisition of PX Energy | (17,348) |
Secured debt | (95,539) |
Asset retirement obligation | (9,200) |
Total liabilities assumed | $ (252,067) |
Net Identifiable Assets Acquired | $ 41,651 |
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65
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Balance, beginning of year | $ – | $ – |
Arising on a business combination (Note 5) | 47,900 | – |
Foreign currency translation adjustment | (1,939) | – |
Balance, end of year | $ 45,961 | $ – |
The goodwill of $47.9 million was recorded principally from the requirement to recognize deferred tax
assets and liabilities for the difference between the assigned fair values and the tax basis of the acquired
assets and liabilities assumed in a business combination. The assessment of fair values of oil and gas
assets acquired is based on cash flows after tax. Nevertheless, in accordance with IAS 12 Income Taxes,
paragraphs 15 and 19, a provision is made for deferred tax corresponding to the tax rate multiplied by the
difference between the acquisition cost and the tax base. The offsetting entry to this deferred tax is
Acquisition Related Costs
Acquisition related costs incurred in connection with the transaction were expensed as incurred. These
costs totaled $3.3 million for the year ended December 31, 2025.
The business combination with PX Energy contributed revenues of $31.7 million and operating income of
$4 million since September 26, 2025 to December 31, 2025. If the Company had acquired PX Energy on
January 1, 2025, the pro-forma results of the revenue and net income and comprehensive income for the
year ended December 31, 2025, would have been as follows:
Pro Forma | |||
Year | |||
Ended | |||
December | |||
($ thousands ) | As Stated | PX Energy | 31, 2025 |
Petroleum and natural gas revenue | $ 77,136 | $ 91,569 | $ 168,705 |
Net loss | $ (78,935) | $ (30,778) | $ (109,713) |
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
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Questerre Energy Corporation
be submitted for arbitration pursuant to the ICC rules should either of the parties make a formal claim
Red Leaf Resources Inc. (“Red Leaf”) is a private Utah-based oil shale and technology company whose
principal assets are its proprietary HCCO technology to recover oil from shale, its oil shale leases and its
assets in the Uinta Basin in the State of Utah.
On December 30, 2025, the Company acquired the remaining equity interest in Red Leaf, increasing its
ownership from approximately 38% to 100%. Total consideration of $8.6 million consisted primarily of (i)
the issuance of Questerre common shares to Red Leaf common shareholders and (ii) cash consideration
payable in respect of the acquisition of Red Leaf preferred shares. 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 $2.2 million. Immediately prior to the acquisition, the Company held approximately 38% of the
common share capital and approximately 16% of the issued and outstanding preferred share capital of Red
Leaf on a non-diluted basis.
The Company assessed the acquired set of activities and assets and concluded that Red Leaf did not meet
the definition of a business for the purposes of IFRS 3
Business Combinations
. In making this
determination, the Company applied the optional concentration test in IFRS 3 and concluded that
substantially all of the fair value of the gross assets acquired was concentrated in a group of similar
identifiable assets. As a result, the transaction was accounted for as an asset acquisition and not as a
business combination.
The following table summarizes the Company’s allocation of the acquisition costs to the identified assets
acquire and liabilities assumed:
($ thousands ) |
|
Cash and cash equivalents |
$ 10,792 |
Restricted cash |
2,050 |
Property, plant and equipment |
3,570 |
Asset retirement obligation |
(3,098) |
Net Assets Acquired |
$ 13,314 |
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67
The table below summarizes the changes in the investment in Red Leaf:
December 31, |
December 31, |
|
($ thousands ) |
2025 |
2024 |
Balance, beginning of year |
$ 4,359 |
$ 4,471 |
Reclassification on change of control |
(6,623) |
– |
Gain (loss) on equity investment |
2,388 |
(474) |
Gain (loss) on foreign exchange |
(124) |
362 |
Balance, end of the year |
$ – |
$ 4,359 |
The previously held interest in Red Leaf was re-measured to fair value at the acquisition date. The
acquisition date fair value of the previously held interest was estimated to be $6.7 million and the net
carrying value of the Red Leaf assets was $4.4 million. As a result, the Company recognized a non-cash
revaluation gain of its existing interest of $2.4 million in the consolidated statements of net loss
December 31, |
December 31, |
|
($ thousands) |
2025 |
2024 |
Bank balances |
$ 15,095 |
$ 10,463 |
Short-term bank deposits |
10,324 |
21,328 |
Cash and cash equivalents |
$ 25,419 |
$ 31,791 |
Restricted cash |
$ 399 |
$ – |
Restricted cash acquired (Note 5 & 6) |
3,122 |
– |
Restricted cash and equivalents (Note 15) |
$ 3,521 |
$ – |
68
Questerre Energy Corporation
December 31, |
December 31, |
|
($ thousands ) |
2025 |
2024 |
Finished goods (1) |
2,646 |
$ – |
In-process products (2) |
876 |
– |
Materials and supplies (3) |
8,904 |
– |
Provision for inventory obsolescence |
(3,814) |
– |
Provision for adjustments to net realizable value |
(19) |
– |
Balance, end of period |
$ 8,593 |
$ – |
(1) Includes fuel oil, LPG, sulfur, naphtha, shale water and fuel gas
(2) Shale oil and oily water
(3) Includes operating materials and sludge acquired from third-party
($ thousands ) |
Total |
Cost or deemed cost: |
|
Balance, December 31, 2023 |
$ 314,321 |
Capital additions including change to asset retirement |
4,000 |
Transfer from exploration and evaluation assets |
8,605 |
Balance, December 31, 2024 |
326,926 |
Acquired through a business combination (Note 5) |
209,203 |
Asset acquisition (Note 6) |
3,570 |
Capital additions |
9,609 |
Transfer from exploration and evaluation assets |
23,515 |
Changes to asset retirement obligation |
426 |
Foreign exchange adjustments |
(8,403) |
Balance, December 31, 2025 |
$ 564,846 |
2025 Annual Report
69
Accumulated depletion, depreciation and impairment losses:
Balance, December 31, 2023 |
$ 198,386 |
Depletion and depreciation |
11,845 |
Balance, December 31, 2024 |
210,231 |
Depletion and depreciation |
29,280 |
Impairment |
49,795 |
Foreign exchange adjustments |
(384) |
Balance, December 31, 2025 |
$ 288,922 |
($ thousands ) |
Total |
Net book value: |
|
At December 31, 2024 |
$ 116,695 |
At December 31, 2025 |
$ 275,924 |
During the
years ended December 31, 2025, and 2024, the Company capitalized administrative
overhead charges of $0.6 million (2024: $0.4 million) and shared based compensation of $0.3 million
(2024: $0.3 million) that were directly attributable to development activities. Included in depletion
calculation at December 31, 2025 are future development costs of $279.2 million (2024: $293.6
million) for Canada and $165.9 million (2024: nil) for Brazil. Included in property, plant and equipment
are land ($9.2 million) and assets under construction ($6.7 million), which are not subject to depletion
or depreciation.
As at December 31, 2025, the future prices used for impairment testing to determine cash flows from
oil and natural gas reserves were as follows:
Average |
||||||
Annual % |
||||||
Change |
||||||
2026 |
2027 |
2028 |
2029 |
2030 |
Thereafter |
|
WTI (US$/barrel) |
59.92 |
65.10 |
70.28 |
71.93 |
73.37 |
2.00 |
BRENT (US$/barrel) |
63.92 |
69.13 |
74.36 |
76.10 |
77.62 |
2.00 |
AECO ($/MMbtu) |
3.00 |
3.30 |
3.49 |
3.58 |
3.65 |
2.00 |
With respect to the Kakwa and Antler CGUs an indicator of impairment was identified as a result of
the reduction in the future commodity prices. The result of the impairment test based on a FVLCD
assessment of the Kakwa CGU was $44.2 million, for the Antler CGU it was $5.6 million and with no
70
Questerre Energy Corporation
impairment reversals recorded for any CGU. The estimates of FVLCD were determined using a
discount rate of 15% (2024: 15.8%) and forecasted after tax cash flows based on proved plus
probable reserves, with escalating prices, royalties, operating costs and future development costs.
No indicators of impairment or impairment reversals were identified for the other CGUs in 2025.
The table below illustrates the impact of changes to the discount rate and price forecasts:
Five Percent |
||
One Percent |
Decrease in the |
|
Increase in the |
Forward Price |
|
($ thousands) |
Discount Rate |
Estimates |
Impairment charge of property, plant and equipment |
$ 55,287 |
$ 67,630 |
Exploration and evaluation assets consist of the Company’s exploration projects which are pending
the determination of technical feasibility and commercial viability. Additions represent the Company’s
share of costs incurred on exploration and evaluation assets during the period.
December 31, |
December 31, |
|
($ thousands ) |
2025 |
2024 |
Balance, beginning of year |
$ 13,106 |
$ 12,287 |
Additions |
16,008 |
16,344 |
Transfers to property, plant and equipment |
(23,515) |
(8,605) |
Foreign currency translation adjustment - Jordan |
– |
943 |
Impairment of Jordan asset |
– |
(7,863) |
Balance, end of period |
$ 5,599 |
$ 13,106 |
During the
year ended December 31, 2025, the Company did not capitalize any administration
overhead or share based compensation expense directly related to exploration and evaluation
activities.
In 2024, the Company recorded an impairment expense of $7.9 million representing its E&E assets
in Jordan due to the impending expiry of its exclusive exploration rights. No impairments were
2025 Annual Report
71
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Balance, beginning of year | $ – | $ – |
Software (acquired through a business combination see Note 5) | 5,755 | – |
Additions | 14 | – |
Depreciation | (85) | – |
Foreign exchange adjustments | (232) | – |
Balance, end of period | $ 5,452 | $ – |
($ thousands ) | ||
Net book value: | ||
Costs | $ 5,537 | $ – |
Accumulated depreciation | (85) | – |
$ 5,452 | $ – |
The tax on the Company’s net loss before taxes differs from the amount that would arise using the
weighted average tax rate applicable to profits or losses of the consolidated entities as follows:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Net loss before taxes | $ (81,076) | $ (7,329) |
Combined federal and provincial tax rate | 23.82% | 23.82% |
Statutory tax (recovery) | (19,312) | (1,746) |
Increase/(deduction) in tax expense resulting from: | ||
Non-deductible differences and permanent items | 273 | 1,567 |
Change in deferred tax asset not recognized | 13,609 | 179 |
Change in deferred tax asset due to obtaining control of Red Leaf | 5,620 | – |
Difference in jurisdictional tax rates | (2,336) | – |
Other | 5 | – |
Total income tax expense | $ (2,141) | $ – |
The Company evaluated the recoverability of its deferred tax assets using forecasted before-tax cash
flows based on proved reserves, with escalating prices and future development costs obtained from
an independent reserve evaluation report and a deduction for estimated general and administrative
72
Questerre Energy Corporation
costs associated with these proved reserves. As a result, deferred tax assets were not recognized.
The combined statutory tax rate was 23.82% in 2025 and 2024.
The breakdown of deductible and taxable temporary differences during the
year are as follows:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Petroleum and natural gas properties | $ 236,833 | $ 165,651 |
Asset Retirement Obligation | 19,120 | 19,420 |
Non-Capital Losses | 163,925 | – |
Capital Losses | 36,480 | 36,488 |
Tax Reserves | 14,501 | – |
Other | – | 33,908 |
Total deductible temporary differences | $ 470,859 | $ 255,467 |
Taxable temporary differences: | ||
Petroleum and natural gas properties | $ (228,265) | $ – |
Tax reserves | (2,039) | – |
Other | (100) | – |
Total taxable temporary differences | $ (230,404) | $ – |
Total net deductible temporary differences | $ 240,455 | $ 255,467 |
Total deductible temporary differences not recognized | (408,975) | (255,467) |
Total net taxable temporary differences recognized | $ (168,520) | $ – |
The deferred tax liabilities are as follows:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Petroleum and natural gas properties | (56,603) | – |
Tax Reserves | (694) | – |
Deferred tax liability | $ (57,297) | $ – |
A deferred tax asset is recognized to the extent that it is probable future taxable profits will be available
against which the asset can be utilized. See note 2(e) for detail on the related judgments used in this
determination. The provision of deferred tax assets and liabilities reflects the tax consequences that
would follow from the expected recovery or settlement of the carrying amount of its assets and
liabilities. We have not recognized $409 million (2024: $255 million) of deductible temporary
differences.
Deferred income tax assets are recognized for tax loss carry forwards to the extent that the realization
of the related tax benefit is probably based on estimated future earnings. As of December 31, 2025,
2025 Annual Report
73
our Canadian non-capital loss carry forwards were $45.9 million and capital loss carry forwards were
$36.5 million. The non-capital loss carry forwards begin to expire in 2045 and the capital losses do not
expire but can only be utilized against future capital gains. Our Brazil non-capital loss carry forwards
were $118 million which do not expire but the annual use is restricted.
Change in deferred income tax balances:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Net deferred income tax liability, beginning of year | $ – | $ – |
Deferred tax liability from FRBH acquisition | (61,873) | – |
Deferred tax recovery | 2,141 | – |
Other FX translation differences | 2,435 | – |
Net deferred income tax liability, end of year | $ (57,297) | $ – |
As at December 31, 2025, the Company’s other non-current assets included a finance lease receivable of
$0.6 million (2024: nil) and recoverable indirect taxes of $5.1 million (2024: nil).
The finance lease receivable represents the Company’s net investment in leases in which the Company is
the lessor. The receivable is measured at the present value of future lease payments and any estimated
residual value accrued to the Company. Finance income is recognized over the lease term using the
effective interest method.
The recoverable indirect taxes arise in the Company’s wholly owned subsidiary in Brazil and relate primarily
to indirect taxation regimes, including the Imposto sobre Circulação de Mercadorias e Serviços (“ICMS”),
Programa de Integração Social (“PIS”), Contribuição para o Financiamento da Seguridade Social
(“COFINS”), and other value-added and transactional taxes incurred in the normal course of operations.
These taxes incurred on purchases of assets can be recovered in forty-eight installments, PIS and COFINS
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Balance, beginning of year | $ – | $ – |
Secured bonds acquired through a business combination (see Note 5) | 95,539 | – |
Accretion | 2,271 | – |
Foreign currency translation adjustments | 2,945 | – |
Balance, end of year | $ 100,755 | $ – |
As at December 31, 2025, the entire balance was classified as long term debt.
74
Questerre Energy Corporation
Secured Bonds
In connection with the PX Energy Acquisition, the Company acquired 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 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 the 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% to 10% per annum effective August 1, 2025. All accrued and unpaid interest
up to December 31, 2025, converts into 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.
The maturity may be extended for two one year terms for a fee of 2% of the principal for each extension.
Additional amendments to the bond terms were also approved including covenant waivers to permit the
normal operation of bank accounts and working capital, including waivers to reduce the minimum liquidity
to US$3.2 million and a waiver to comply with the interest coverage ratio up to and including December
31, 2025.
Below are the main financial covenant clauses of the outstanding bonds:
Interest coverage ratio greater than 1.3x;
Minimum liquidity of US$3.2 million.
As at December 31, 2025, the Company was in compliance with the covenants under the amended bond
terms.
The Company maintains credit facilities with a Canadian chartered bank at $16 million for the year. The
credit facilities include a revolving operating demand facility of $16 million. It can be used for general
corporate purposes, ongoing operations, and capital expenditures within Canada. As such, the calculation
of the covenant below excluded as amounts related to the Acquisition. Any borrowing under the credit
facilities, with the exception of letters of credit, bears interest at the bank’s prime interest rate and an
establishment of wholly owned subsidiaries for the Acquisition and the issuance of shares for the
2025 Annual Report
75
remaining equity interest in Red Leaf. A waiver was subsequently granted by the lender on March 31,
2026.
Under the terms of the credit facility, 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 Facility A availability) to current liabilities (excluding outstanding bank debt
and unrealized hedging losses). The Adjusted Working Capital Ratio at December 31, 2025, was 2.55 (2024:
3.92) and the covenant was met. At December 31, 2025, and 2024 effectively nil was drawn on the facility.
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, in fact, be reduced or eliminated, the
Company would need to seek alternative credit facilities or consider the issuance of equity to enhance its
The Company’s asset retirement and abandonment obligations result from its ownership interest in oil and
natural gas assets. The total asset retirement obligation is estimated based on the Company’s net
ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and
facilities and the estimated timing of the costs to be incurred in future periods. For the Canadian assets,
the Company has estimated the net present value of the asset retirement obligation to be $20 million as
at December 31, 2025 (2024: $19.4 million) based on an undiscounted total future liability of $23.4 million
(2024: $24.6 million). These payments are expected to be made over the next 31 years. The average
discount factor, being the risk-free rate related to the liabilities, is 3% (2024: 3.06%). An inflation rate of
2% (2024: 2%) over the varying lives of the assets is used to calculate the present value of the asset
retirement obligation.
For the Brazilian assets, the Company has estimated the net present value of the asset retirement
obligation to be $13 million as at December 31, 2025 (2024: nil) based on an undiscounted total future
liability of $23.9 million (2024: $24.6 million). These payments are expected to be made over the next
17
years. The average discount factor, being the risk-free rate related to the liabilities, is 12.3% (2024: nil).
An inflation rate of 3.5% (2024: nil) over the varying lives of the assets is used to calculate the present
value of the asset retirement obligation.
76
Questerre Energy Corporation
December 31, |
December 31, |
|
($ thousands) |
2025 |
2024 |
Balance, beginning of year |
$ 19,410 |
$ 19,064 |
Acquired through a business combination (Note 5) |
9,200 |
– |
Revaluation of obligation acquired through a business combination |
2,676 |
– |
Acquired on asset acquisition (Note 6) |
3,098 |
– |
Liabilities incurred |
110 |
352 |
Liabilities settled |
(1,072) |
(49) |
Revisions due to change in estimates and discount rates |
315 |
(537) |
Accretion |
2,817 |
580 |
Foreign exchange adjustments |
(509) |
– |
Balance, end of year |
$ 36,045 |
$ 19,410 |
Current portion |
2,945 |
799 |
Non-current portion |
33,100 |
18,611 |
Balance, end of period |
$ 36,045 |
$ 19,410 |
PX Energy maintains deposits in financial institutions to comply with the requirements of ANP Resolution
No. 854/2021. These investments have restricted cash characteristics and are only moved annually based
on the ANP's review of the amount of the subsidiary's environmental liabilities and determination of the
amount to be maintained as a restricted cash.
In the
fourth quarter of 2025, PX Energy withdrew the amount related to a prior letter of guarantee, which
had been replaced by a new letter of guarantee in the third quarter of 2025. The new letter of guarantee
includes certain financial covenant requirements. As at December 31, 2025, PX Energy identified a risk of
non-compliance with certain of these requirements and is in discussions with the
issuing bank to amend
the covenant terms and provide alternative forms of security or guarantees. Red Leaf maintains a deposit
2025 Annual Report
77
Right-of-use assets
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Balance, beginning of year | $ 128 | $ 180 |
Acquired through a business combination (Note 5) | 1,698 | – |
Additions | (12) | 8 |
Depreciation | (285) | (60) |
Currency translation adjustment | (70) | – |
Balance, end of year | $ 1,459 | $ 128 |
b)
Lease liabilities
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Balance, beginning of year | $ 139 | $ 192 |
Additions | 2 | 8 |
Acquired through a business combination (Note 5) | 1,698 | – |
Interest expense | 22 | 4 |
Lease payments | (319) | (65) |
Currency translation adjustment | (69) | – |
Balance, end of year | $ 1,473 | $ 139 |
Current portion | 988 | 56 |
Long term portion | 485 | 83 |
Balance, end of year | $ 1,473 | $ 139 |
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Balance, beginning of year | $ – | $ – |
Acquired through a business combination (Note 5) | 17,348 | – |
Fair value adjustment in profit and loss (Note 23) | (255) | – |
Payment | (2,160) | – |
78
Questerre Energy Corporation
Foreign currency translation adjustment | 1,554 | – |
Balance, end of year | $ 16,487 | $ – |
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Current | $ 3,259 | $ – |
Long Term | $ 13,228 | $ – |
In connection with the PX Energy Acquisition, the Company assumed a liability that formed part of the
acquired business and recognized it as an identifiable liability assumed in the business combination. The
liability was initially measured at its fair value at the acquisition date.
As part of the prior acquisition agreement in respect of PX Energy, additional contingent consideration is
payable annually to Petrobras, the original owner of PX Energy, until the end of 2027. The contingent
consideration is determined based on incremental volumes of oil sludge purchased by PX Energy from the
seller and is linked to the future price of fuel oil.
The contingent consideration is classified as a financial liability and measured at fair value, taking into
account the projected volumes of oil sludge purchases for the remaining term of the arrangement and
forecast fuel oil prices. The fair value measurement incorporates significant unobservable inputs and is
therefore classified within Level 3 of the fair value hierarchy.
Subsequent changes in the fair value of the contingent consideration, other than measurement period
adjustments recorded in accordance with IFRS 3, are recognized in profit or loss in the period of
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Provision for contingencies | 7,876 | – |
Taxes and contributions | 7,077 | – |
Deferred revenue | 2,026 | – |
Other Long-term liabilities | 535 | – |
Less: Current Other liabilities | (7,327) | – |
Other long-term liabilities | $ 10,187 | $ – |
Provision for contingencies
The Company recognizes provisions in amounts sufficient to cover losses considered probable and for
which a reliable estimate can be made. Legal proceedings that represent present obligations for which the
2025 Annual Report
79
outflow of resources is not probable, or for which a sufficiently reliable estimate of the amount cannot be
made are not recognized but are disclosed unless the likelihood of outflow is remote.
As at December 31, 2025, the Company had recognized provisions for contingencies of $7.9 million in
Brazil, of which $0.5 million related to labor claims and $7.4 million related to tax matters in Brazil. Of the
total provision, $3 million was classified as current and the remainder of $4.9 million as long term.
These
amounts were recognized based on management’s assessment and the advice of internal and external
legal counsel that a loss is probable.
The tax risk provision relates to $4.9 million for state value added tax on triangular oil sales transactions
involving inventory stored at third-party locations and $2.5 million for a dispute with the Government of the
State of Paraná initiated in the fourth quarter of 2025 concerning oil purchases made without state value
added tax.
Based on legal opinions and technical assessments obtained by PX Energy, management has concluded
that the likelihood of loss in respect of these matters is probable and has recognized the related provisions
accordingly.
Taxes and contributions
The Company, through its wholly owned subsidiary in Brazil, is subject to indirect taxes, including federal
and state value added taxes the ICMS, PIS, COFINS and other value-added and transactional taxes, as well
as direct taxes, including corporate income tax (IRPJ) and social contribution on net income (CSLL). In the
normal course of operations, indirect taxes are incurred on transactions involving the sale, purchase and
movement of goods and services and are recognized as liabilities when payable in accordance with
applicable legislation. As at December 31, 2025, the Company had recognized indirect taxes payable of
$3.6 million (2024: nil).
The Company did not generate taxable income in Brazil in 2025. As at December 31, 2025, the Company
recognized liabilities of $5.4 million in respect of IRPJ and CSLL obligations from prior years, of which $1.8
million was classified as current and $3.6 million as long-term. These balances relate to prior year amounts
the Company elected to settle in installments and are subject to a 20% penalty, together with monthly
interest of 1% plus the SELIC rate.
Deferred revenue
As at December 31, 2025, the Company had a contract liability of $2.0 million, all of which was classified
as current, related to minimum volume commitments under customer contracts. The balance represents
consideration receivable for committed volumes for which the related oil had not yet been delivered as at
year end. Revenue will be recognized when the related performance obligations are satisfied through
delivery of the volumes
80
Questerre Energy Corporation
a) Overview
The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration,
development, production, and financing activities such as credit risk, liquidity risk and market risk. The
Company manages its exposure to these risks by operating in a manner that minimizes this exposure.
The Company’s financial instruments as at December 31, 2025, included cash and cash equivalents,
accounts receivable, deposits, credit facilities and accounts payable and accrued liabilities. As at December
31, 2025, the fair values of these financial assets and liabilities equaled their carrying values due to the
short-term maturity.
The company’s long-term debt and long-term financial liabilities are recorded at amortized cost using the
effective interest method. At December 31, 2025, the carrying value of secured debt accounted for under
amortized cost was $100.8 million (December 31, 2024 – nil) and the fair value at December 31, 2025 was
$115.7 million (December 31, 2024 – $10.1 million). The estimated fair value of long-term debt is based on
pricing sourced from market data, which is considered a Level 2 fair value input.
a hierarchy that prioritizes the inputs to fair value measurement.
Level 1 Fair Value Measurements
Level 1 fair value measurements are based on unadjusted quoted market prices.
Level 2 Fair Value Measurements
Level 2 fair value measurements are based on valuation models and techniques where the significant
inputs are derived from quoted indices.
Level 3 Fair Value Measurements
Level 3 fair value measurements are based on unobservable information.
The fair value measurement of PP&E, E&E, right-of-use assets and contingent payments made by
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 principally from the
Company’s receivables from joint venture partners and oil and gas marketers. The carrying amounts of
accounts receivable and cash and cash equivalents represent the maximum credit exposure.
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
2025 Annual Report
81
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 is paid in
the following
month from major oil and natural gas marketing companies and the Company has not
experienced any credit loss relating to these sales.
Receivables from joint venture partners are typically collected within one to three
months of the joint
venture bill being issued. The Company mitigates this risk by obtaining pre-approval of significant capital
expenditures.
The Company’s accounts receivables are aged as follows:
December 31, |
December 31, |
|
($ thousands) |
2025 |
2024 |
Current |
$ 11,016 |
$ 3,174 |
31 - 60 days |
3 |
3 |
61 - 90 days |
105 |
1 |
>90 days |
36 |
64 |
$ 11,160 |
$ 3,242 |
The Company does not anticipate any material default as it transacts with creditworthy customers and
management does not expect any losses from non-performance by these customers. There are no material
financial assets that the Company considers past due that are considered impaired.
Cash and cash equivalents include cash bank balances and short-term deposits. The Company manages
the credit risk exposure by investing in Canadian banks. Management does not expect any counterparty to
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become
due. The Company’s processes for managing liquidity risk include ensuring, to the extent possible, that it
will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual
capital expenditure budgets which are monitored and are updated as required. In addition, the Company
requires authorizations for expenditures on projects to assist with the management of capital.
Since the Company operates in the upstream oil and natural gas industry, it requires sufficient cash to fund
capital programs necessary to maintain or increase production, develop reserves and to potentially acquire
strategic assets. The Company’s capital programs are funded principally by cash obtained through its credit
facilities, equity issuances and from operating activities. During times of low oil and natural gas prices or
when cash resources may be limited, a portion of capital programs can generally be deferred, however,
due to the long cycle times and the importance to future cash flow in maintaining the Company’s
production, it may be necessary to utilize alternative sources of capital to continue the Company’s strategic
investment plan during periods of low commodity prices. As a result, the Company frequently evaluates
82
Questerre Energy Corporation
the options available with respect to sources of long and short-term capital resources. Occasionally, to the
extent possible, the Company will use derivative instruments to manage cash flow in the event of
commodity price declines.
The Company’s financial obligations relate to amounts due under the credit facilities, including trade and
other payables, which consist of invoices payable to trade suppliers relating to the office and field operating
activities and its capital spending program. The Company processes invoices within a normal payment
period and all amounts are due within the next 12 months.
The timing of cash outflows relating to financial liabilities as at December 31, 2025, and 2024 are as follows:
Less than |
One - Two |
Remaining |
||
($ thousands) |
one year |
years |
years |
Total |
Accounts payable and accrued liabilities |
$ 44,752 |
$ – |
$ – |
$ 44,752 |
Advances from customers |
13,367 |
– |
– |
13,367 |
Share issuance for acquisition |
8,153 |
– |
– |
8,153 |
Lease liabilities |
988 |
304 |
181 |
1,473 |
Secured debt |
– |
100,755 |
– |
100,755 |
Current liabilities related to business combination |
22,760 |
– |
– |
22,760 |
Contingent consideration for original acquisition of PX |
||||
Energy |
3,259 |
13,228 |
- |
16,487 |
Other liabilities |
7,327 |
10,187 |
– |
17,514 |
December 31, 2025 |
$ 100,606 |
$ 124,474 |
$ 181 |
$ 225,261 |
Less than |
One - Two |
Remaining |
||
($ thousands) |
one year |
years |
years |
Total |
Trade and other liabilities |
$ 12,545 |
$ – |
– |
$ 12,545 |
Lease liabilities |
56 |
– |
83 |
139 |
Current portion of asset retirement obligation |
799 |
– |
– |
799 |
December 31, 2024 |
$ 13,400 |
$ – |
$ 83 |
$ 13,483 |
Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates
and interest rates will affect the Company’s profit or loss or the value of the financial instruments. The
objective of the Company is to mitigate exposure to these risks while maximizing returns to the Company.
Commodity price risk
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes
in commodity prices. The Company’s financial performance is closely linked to crude oil and refined product
2025 Annual Report
83
prices (including pricing differentials for various product types) and, to some extent to electricity prices as
one of the major costs of production. Commodity prices for oil and natural gas are impacted not only by
the relationship between the Canadian and United States dollar, but also world economic events that
dictate the levels of supply and demand. The Company may enter into oil and natural gas contracts to
protect, to the extent possible, its cash flow on future sales. The contracts reduce the volatility in sales
revenue by locking in prices with respect to future deliveries of oil and natural gas. As at December 31,
2025, the Company had no outstanding commodity risk management contracts.
When assessing the potential impact of these commodity price changes, the Company believes a ten
percent volatility is a reasonable measure. A ten percent increase or decrease in commodity prices would
have resulted in $5.0 million net impact on revenue and net loss before tax.
Currency risk
as a result of changes in foreign exchange rates. The Company operates internationally and is exposed to
foreign exchange risk arising from transactions and balances denominated in currencies other than the
functional currency of the applicable entity, primarily the Brazilian real, Canadian dollar, U.S. dollar and
Jordanian dinar.
The Company’s Canadian petroleum and natural gas sales are denominated in Canadian dollars. However,
the underlying market prices for these commodities are influenced by benchmark prices denominated in
U.S. dollars and, accordingly, are indirectly affected by movements in the Canadian dollar relative to the
U.S. dollar.
In Brazil, revenues are denominated in Brazilian reals; however, commodity prices fluctuate with underlying
market prices denominated in U.S. dollars. Operating and capital expenditures in Brazil are primarily
denominated in local currency, resulting in exposure to fluctuations in the Brazilian real relative to the
Canadian dollar.
The Company also incurs expenditures through its Jordanian subsidiary that are denominated in Jordanian
dinars and U.S. dollars, which gives rise to additional foreign currency exposure.
Following the PX Energy acquisition, the Company was also exposed to foreign currency risk in respect of
the senior secured bonds, which are denominated in U.S. dollars. Fluctuations in the U.S. dollar exchange
rate relative to the Company’s functional currency may affect the carrying amount of the debt and the
related finance expense recognized in the consolidated financial statements.
The Company does not currently hedge its exposure to foreign exchange risk associated with these bonds
and, as at December 31, 2025, had no forward foreign exchange contracts in place. Management monitors
foreign exchange rates on an ongoing basis in assessing the impact of currency movements on the
Company’s financial position and cash flows.
Based on the Company’s foreign operations at December 31, 2025, a 10% strengthening or weakening of
the Canadian dollar relative to the functional currencies of the Company’s subsidiaries, with all other
variables held constant, would have increased or decreased loss before taxes by approximately $1.9 million
84
Questerre Energy Corporation
as a result of translating the results of those subsidiaries into the Company’s presentation currency, the
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.
The Company’s objective in managing capital is to maintain financial flexibility, preserve its ability to meet
financial obligations as they become due and provide sufficient liquidity to fund ongoing operations and
execute its business strategy. The Company believes that, with expected cash flow from operations,
existing credit facilities and other available sources of financing, it will be able to meet its foreseeable
capital obligations in the normal course of operations in the near term. The Company defines its capital
structure as shareholders’ equity, long-term debt, including the senior secured bonds assumed in
connection with the PX Energy acquisition, and working capital. The Company monitors its capital structure
having regard to current and projected cash flow from operations, debt levels, available liquidity and
forecast capital expenditures.
The volatility of commodity prices has a material impact on the Company’s cash flow from operations. The
Company attempts to mitigate the effect of lower prices by entering into risk management contracts,
shutting in production in unusually low pricing environments, reallocating capital to more profitable areas
and reducing capital spending based on results and other market considerations. The Company will adjust
its capital structure to minimize risk and its cost of capital through the issuance of shares, securing
additional credit facilities and adjusting its capital spending as required. The Company monitors its capital
structure based on the current and projected funds flow from operations.
2025 Annual Report
85
Annual and updated budgets are approved by the Board of Directors and are regularly reviewed to assess
The Company has a stock option program that provides for the issuance of options to purchase Common
Shares to its directors, officers and employees at or above grant date market prices. The options granted
under the plan generally vest evenly over a three-year period starting at the grant date or one
year from
the grant date. The grants expire five
years from the grant date.
Under the Company’s option plan, a put right is included that allows the optionee to settle options with
cash or equity. Under the put right, the optionee will receive the net cash proceeds that is the excess of
the closing price of the Common Shares at the day of the put notice over the exercise price of the option.
The Company has the option to decline a put right exercise at any time in 2025. The Company did settle
$0.2 million options in cash.
The number and weighted average exercise prices of stock options are as follows:
| Options Outstanding |
Options Exercisable |
|||||
Weighted |
Weighted |
Weighted |
Weighted |
|||
Number of |
Average |
Average |
Number of |
Average |
Average |
|
Options |
Years to |
Exercise |
Options |
Years to |
Exercise |
|
(thousands) |
Expiry |
Price |
(thousands) |
Expiry |
Price |
|
$0.18 - $0.20 |
7,775 |
0.07 |
$ 0.18 |
7,775 |
0.07 |
$ 0.18 |
$0.21 - $0.23 |
11,725 |
3.13 |
0.23 |
6,702 |
2.56 |
0.23 |
$0.24 - $0.26 |
5,950 |
3.10 |
0.25 |
3,471 |
3.10 |
0.25 |
$0.27 - $0.34 |
10,340 |
1.06 |
0.34 |
10,340 |
1.06 |
0.34 |
35,790 |
1.86 |
$ 0.25 |
28,288 |
1.39 |
$ 0.26 |
|
86
Questerre Energy Corporation
The following table summarizes information about stock options outstanding and exercisable at December
31, 2025:
December 31, 2025 |
December 31, 2024 |
|||
Weighted |
Weighted |
|||
Number of |
Average |
Number of |
Average |
|
Options |
Exercise |
Options |
Exercise |
|
(thousands) |
Price |
(thousands) |
Price |
|
Outstanding, beginning of period |
38,295 |
$ 0.25 |
38,140 |
$ 0.26 |
Granted |
6,675 |
0.23 |
6,950 |
0.25 |
Forfeited |
(2,880) |
0.22 |
(620) |
0.27 |
Expired |
(325) |
0.16 |
(6,175) |
0.29 |
Exercised |
(5,975) |
0.20 |
– |
– |
Outstanding, end of period |
35,790 |
$ 0.25 |
38,295 |
$ 0.25 |
Exercisable, end of period |
28,288 |
$ 0.26 |
29,704 |
$ 0.25 |
The fair value of the options granted were calculated using the Black-Scholes valuation model. The
following weighted average assumptions were used in the model for options granted in 2025 and 2024:
December 31, |
December 31, |
|
2025 |
2024 |
|
Weighted average fair value per award ($) |
0.18 |
0.19 |
Volatility (%) |
102.60 |
103.47 |
Forfeiture rate (%) |
8.46 |
8.85 |
Expected life (years) |
5.00 |
5.00 |
Risk free interest rate (%) |
2.91 |
3.54 |
This forfeiture rate estimate is adjusted to the actual forfeiture rate. Expected volatility and expected
The Company is authorized to issue an unlimited number of Common Shares. The Company is also
authorized to issue an unlimited number of Class
“B” Common voting shares and an unlimited number of
preferred shares, issuable in one or more series. At December 31, 2025 and 2024, there were no Class
“B”
common voting shares or preferred shares outstanding.
2025 Annual Report
87
a) Issued and outstanding
Number | Amount | |
(thousands) | ($ thousands) | |
Balance, December 31, 2024 | 428,516 | 429,878 |
Shares issued for acquisition | 17,248 | 5,347 |
Balance, December 31, 2025 | 445,764 | $ 435,225 |
During the year, the Company issued 17.2 million Questerre Common Shares to Red Leaf common
shareholders with a deemed value of $0.31 per Common Share. As at December 31, 2025, the portion of
consideration related to the common shares remains unpaid and has been recognized as a current liability
of $3.2 million.
As part of the Acquisition, the Company is obligated to issue 15 million Class “A” common voting shares
(“Common Shares”) with a deemed value of $5.0 million. As at December 31, 2025, these shares had not
yet been issued and the related amount has been recognized as a current liability.
In January 2026, the Company completed the economic spin out its Quebec-based assets through a
reorganization of its capital. The reorganization consisted of the exchange of one old Common Share for
one new Common Share and one Series 2 Preferred Share. The Preferred Shares entitle holders to the
economic benefits of the Quebec assets and the Common Shares represent ownership of the remaining
assets of the Company.
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Balance, beginning of year | $ 29,283 | $ 27,908 |
Contingent consideration for business combination classified as | ||
| equity (Note 5) | 13,941 | – |
Share based compensation | 1,203 | 1,375 |
Balance, end of period | $ 44,427 | $ 29,283 |
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.
The contingent equity consideration meets the definition of an equity instrument under IFRS and,
accordingly, is not subject to subsequent remeasurement. See Note 5 for further details regarding the
88
Questerre Energy Corporation
Basic and Diluted net loss per share is calculated as follows:
December 31, | December 31, | |
(thousands, except as noted) | 2025 | 2024 |
Net loss | $ (78,935) | $ (7,329) |
Issued Common Shares at beginning of year | 428,516 | 428,516 |
Shares issued for the acquisition | 17,248 | – |
Weighted average number of Common Shares beginning and | ||
outstanding (basic and diluted) | 429,083 | 428,516 |
Basic and diluted net loss per share | $ (0.18) | $ (0.02) |
Under the current stock option plan, options can be exchanged for Common Shares of the Company,
or for cash at the Company’s discretion. They are considered potentially dilutive and are included in
the calculation of diluted net loss per share for the period. The average market value of the Common
Shares for purposes of calculating the dilutive effect of options was based on quoted market prices
for the period that the options were outstanding. At December 31, 2025, 22.5 million options
(December 31, 2024: 23.7 million) were excluded from the diluted weighted average number of
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Oil and liquids | $ 39,942 | $ 34,148 |
Natural gas | 4,996 | 2,699 |
Royalty revenue | 525 | 80 |
Total Canada | $ 45,463 | $ 36,927 |
Oil and liquids | 29,554 | – |
Natural gas | 2,119 | – |
Total Brazil | $ 31,673 | $ – |
Total Company | $ 77,136 | $ 36,927 |
2025 Annual Report
89
Other income consists of the following:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Rental income | $ 1,999 | $ – |
Fair value adjustment for contingent consideration of former owner | 255 | – |
Other | (641) | – |
Balance, end of year | $ 1,613 | $ – |
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Finance Income | ||
Foreign exchange gain | $ 1,270 | $ – |
Income from financial investments | 562 | 1,149 |
Interest income from leases | 24 | – |
Other finance income | 46 | – |
Total finance income | $ 1,902 | $ 1,149 |
Finance expenses | ||
Lease finance costs | $ 41 | $ 4 |
Interest expenses | 6,250 | – |
Bond accretion | 2,271 | – |
Foreign exchange loss | 6,010 | – |
Brazil financial transactions tax (IOF) | 86 | – |
Other | 122 | – |
Total finance expense | $ 14,780 | 4 |
Net finance (costs) income | $ (12,878) | $ 1,145 |
90
Questerre Energy Corporation
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Salaries, bonuses and other short-term benefits | $ 2,694 | $ 2,518 |
Share based compensation | 920 | 1,205 |
$ 3,614 | $ 3,723 |
Key management includes directors and officers. The compensation paid or payable to key management
is as follows:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Salaries, bonuses, director fees and other short-term benefits | $ 2,359 | $ 2,128 |
Share based compensation | 1,015 | 1,296 |
$ 3,374 | $ 3,424 |
The Company has entered into written executive employment agreements with each of the officers
of the Company. Each of these written agreements provides that in the event of a change of control
of the Company, each of the officers is entitled to: (i) 18 months of then applicable base salary with
24 months for the CEO; and (ii) the vesting of all options to purchase Common Shares. In the event
of a change in control, all options will vest and the severance payable to key management would have
been $2.8 million at December 31, 2025. This amount does not include accelerated share-based
2025 Annual Report
91
Changes in non-cash working capital are detailed below:
December 31, |
December 31, |
|
($ thousands) |
2025 |
2024 |
Accounts receivable |
$ (143) |
$ (226) |
Deposits and prepaid expenses |
5,953 |
16 |
Inventory |
692 |
– |
Other long term assets |
(5,053) |
– |
Accounts payable and accrued liabilities |
(3,862) |
3,105 |
Other liabilities |
(639) |
– |
Change in non-cash working capital |
$ (3,052) |
$ 2,895 |
Related to: |
||
Operating activities |
$ 214 |
$ (890) |
Investing activities |
(3,266) |
3,785 |
$ (3,052) |
$ 2,895 |
Other Non-cash items:
December 31, |
December 31, |
|
($ thousands) |
2025 |
2024 |
Inventory obsolescence |
$ (157) |
$ – |
Fair value adjustment for contingent consideration of former owner |
(255) |
– |
Provision for contingencies |
2,820 |
– |
Foreign exchange |
637 |
– |
Tax penalties relief |
(1,272) |
– |
Total other non-cash items |
$ 1,773 |
$ – |
A summary of the Company’s net commitments at December 31, 2025, follows:
($ thousands) |
2026 |
2027 |
Total |
Transportation and Processing |
$ 2,153 |
$ 1,043 |
$ 3,196 |
Refinery maintenance contract |
$ 15,897 |
$ 1,199 |
$ 17,096 |
Supply contracts |
$ 6,149 |
$ – |
$ 6,149 |
92
Questerre Energy Corporation
On February 26, 2026,the Company’s indirect subsidiary FRBH formally acknowledged a liability in the
amount of $3.2 million, related to the prior acquisition of PX Energy (see Note 17). The liability will be
settled in eleven monthly installments consisting of principal and interest. FRBH is required to provide a
financial guarantee for this amount.
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. The Company is assessing options to have the
Preferred Shares listed for trading.
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, breech 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
DIRECTORS
Michael Binnion
Hans Jacob Holden
Jauvonne Kitto
Dennis Sykora
Bjorn Inge Tonnessen
OFFICERS
Michael Binnion,
President and
Chief Executive Officer
John Brodylo,
VP Exploration
Jason D’Silva,
Chief Financial Officer
Jyoti Parmar,
VP Finance
David Pellegrin,
VP Operations
Rick Tityk,
VP Land
BANKERS
National Bank
1800 ,301 Sixth Avenue SW
Calgary, Alberta T2P 4M9
LEGAL COUNSEL
Borden Ladner Gervais LLP
1900, 520 Third Avenue SW
Calgary, Alberta T2P 0R3
TRANSFER AGENT
Computershare Trust
Company of Canada
800, 324 Eighth Avenue SW
Calgary, Alberta T2P 2Z2
DNB Carnegie
Dronning Eufemias gate 30
0191 Oslo, Norway
AUDITORS
Ernst and Young LLP
2200, 215 Second Street SW
Calgary, Alberta T2P 1M4
CORPORATE INFORMATION
INDEPENDENT
RESERVOIR ENGINEERS
McDaniel & Associates Consultants Ltd.
2000, 525 Eighth Avenue SW
Calgary, Alberta T2P 1G1
GLJ Ltd.
1920, 401 Ninth Avenue SW
Calgary, Alberta T2P 3C5
HEAD OFFICE
1650 AMEC Place
801 Sixth Avenue SW
Calgary, Alberta T2P 3W2
Telephone: (403) 777-1185
Facsimile: (403) 777-1578
Web: www.questerre.com
Email: [email protected]
STOCK INFORMATION
Toronto Stock Exchange
Oslo Stock Exchange
Symbol: QEC
QUESTERRE
ENERGY CORPORATION
1650 AMEC Place
801 Sixth Avenue SW
Calgary, Alberta T2P 3W2
Telephone: (403) 777-1185
Facsimile: (403) 777-1578
Web: www.questerre.com
Email: [email protected]