XOSL:QEC ESEF Annual Report
QUESTERRE EN PREF (XOSL:QEC)
ESEF Annual Report
2026-04-01
For: 2025-12-31
View Original
Added on
September 24, 2026
2025 Annual Report
1
President’s Message
Following the acquisition of PX Energy, we now have a clear path to commercially developing oil
shale. It is an integrated production platform to advance the Red Leaf patented technology to produce
oil from shale. As we assess the options for a small scale commercial pilot, our goal is to restructure
the business into a profitable operation.
The acquisition was a catalyst to consolidate our equity ownership of Red Leaf Resources and spin
out our Quebec assets. We purchased the remaining interest of Red Leaf through a common share
exchange and the acquisition of its preferred shares. Among the other assets we acquired, we now
own the HCCO® technology that incorporates carbon capture directly into the process and their oil
shale leases in the state of Utah.
The spin out of our Quebec assets was completed when we issued a new class of preferred shares
in January 2026 to hold the rights to these assets. A path to producing our discovery remains our
main goal because it could help solve their energy shortage. We are also protecting our shareholder
rights by following the legal process for our claim.
Highlights
•
Closed acquisition of PX Energy, an integrated oil shale company in southern Brazil
•
Consolidated ownership of Red Leaf Resources
•
Spun-out of Quebec assets through share reorganization
•
Average daily production of 3,711 boe per day, net cash from operating activities of $5.8
million and adjusted funds flow from operations of $11.1 million
•
Total proved and probable reserves for PX Energy are xxxMMBOE with a NPV 10% of xxxx
•
Total proved and probable reserves for our Canadian assets declined by less than 10% to 22.4
MMboe with a before tax NPV 10% of $133.3 million
Oil Shale
We plan to restructure PX Energy into a cash flowing business backstopped by long life reserves
and
a sustainable balance sheet
.
The first step is to restore the company’s financial health. The acquisition of PX Energy came with a
significant working capital deficit and long term debt. Additionally, we assumed several other liabilities
as part of our consideration and there are legacy issues with the vendors, debtors and prospective
joint venture partners. Some of these issues may require litigation to ultimately right size the balance
sheet.
The business could also benefit from a new approach. With over thirty years’ under a Brazilian
supermajor, the company had a long-established management structure and business and operating
procedures. These include a strong HSE culture and focus on safety which is essential for an operation
with close to 1,000 employees and contractors on site. By applying a private sector approach, we
intend to improve profitability in a business with annual revenue of over $130 million. In the first
2
Questerre Energy Corporation
quarter of this year, a restructured management team has identified cost savings of to $10 million.
We are targeting an additional $10 million by the end of this year.
We are also looking at opportunities to grow revenue. These include debottlenecking initiatives to
increase oil sales volumes by replacing fuel consumed in the process with cheaper alternatives. In
addition to the oil produced from shale, approximately one third of production volumes come from
processing refinery waste, commonly known as oil sludge. Although competitive, this business has
good margins. We intend to build out this business by diversifying our supply sources, seeking
premium pricing for our products and expanding our processing capacity.
With access to an existing mine, utilities and processing facilities, PX Energy’s site in Brazil could
materially reduce our original estimates of $30 million to $50 million for a test facility. As a first step,
we are planning to evaluate a key component of the HCCO® technology using existing equipment
on location. We estimate this could cost just over $2.5 million and increase production by over 300
barrels per day.
Quebec
We are actively promoting our natural gas discovery to help solve Quebec’s economic challenges.
The energy shortage in Quebec appears to be growing. The provincial utility has become ‘a net
importer of power in a reversal from past years’ reflecting growing demand and reduced supply, in
part caused by a drop in its northern water reservoirs
(1)
. As it plans to invest C$200 billion in increasing
renewable energy supply, associations representing consumers, small and medium sized businesses
and large industrial users have collectively expressed their concerns about sharp increases in prices
(2)
.
In January this year, the provincial utility announced its plans to convert the natural gas fired
Becancour power plant to meet peak demand during the winter using renewable natural gas
(3)
. We
have continued to advocate for our gas to supply this plant that lies less than ten kilometers from our
discovery wells. Our gas can also be a secure and reliable source of natural gas for the province. It
currently engaged in a trade dispute with the United States that supplies 50% of its needs
(4)
.
Longer term, our gas could also provide the supply for LNG exports from Quebec. The recent contract
between Germany and Qatar suggests Europe continues to look for more secure supplies of energy
following the Russian invasion of Ukraine.
The legal process to protect our legal rights has been moving forward, albeit slower than many
shareholders expect. During the year, we completed the questioning of key Government witnesses
including current and former members of the Executive Council of Quebec. In January, the Justice
approved Questerre to advance as ‘test case’ to expedite the process. Subject to any appeal by the
Attorney General of Quebec and other pre-trial motions, we are hopeful to have a hearing date for the
main trial set this year.
Operating and Financial
Our volumes increased this year following the tie-in of three (1.5 net) wells at Kakwa North and the
incremental production from PX Energy after the acquisition closed at the end of the third quarter.
2025 Annual Report
3
Average production for the year was 3,711 boe per day compared to 1,756 boe per day last year. In
the fourth quarter, our production averaged 7,046 boe per day with 4,411 boe per day from Brazil.
Even with lower realized commodity prices, revenue for our Canadian operations increase to $45.5
million with adjusted funds flow from operations of $_ million, excluding costs related to the PX Energy
acquisition. For the quarter, our operations in Brazil generated $ 31.9 million in revenue and $_ million
in adjusted funds flow from operations.
Our consolidated working capital position reflects the working capital deficit of PX Energy of $7.6
million and the non-recourse debt and other obligations assumed as part of the PX Energy acquisition.
Though our cost-cutting initiatives at PX Energy and assuming commodity prices remain above
US$65 per barrel, we expect this deficit to be reduced to $_ million by year-end
.
Outlook
We are focused on restructuring PX Energy into a company with a stronger balance sheet, and
profitable at lower oil prices, despite the recent run-up in prices. Testing the
HCCO®
technology at
scale is also a priority through a field pilot in Brazil or possibly Jordan. This could lead to a commercial
scale project that, with success, could turn oil shale resources into reserves.
Although we are advancing our legal claim, we are still pursuing a business and political solution in
Quebec. At a recent speech to the Quebec Board of Trade in February, the head of the province’s
largest bank argued that Quebec should develop its natural gas resources
(5)
. A leading candidate for
the current ruling party also expressed support for assessing local gas development
(6)
. We are
optimistic that this reflects a broader sentiment and eventually provides a path to realizing the value
of our discovery
.
Michael Binnion
President and Chief Executive Officer
Footnotes:
(1)
https://www.theglobeandmail.com/business/article-hydro-quebec-electricity-net-importer-water-reservoirs-demand/
(2)
https://montreal.citynews.ca/2026/03/01/hydro-quebec-projects-drive-up-electricity-prices/
(3)
https://news.hydroquebec.com/news/press-releases/all-quebec/quebec-energy-security-hydro-quebec-confirms-next-steps-use-power-plant-
becancour-during-peak-periods.html
(4)
https://www.canadianenergycentre.ca/big-vulnerability-how-ontario-and-quebec-became-reliant-on-u-s-oil-and-gas/
(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/
4
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
5
Management’s Discussion and Analysis
This Management’s Discussion and Analysis (“MD&A”) was prepared as of March
26, 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 December2025, 2025 and
2024. Additional information relating to Questerre, including Questerre’s Annual Information Form
for
the
year ended December 31, 2025, dated March 26, 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:
•
drilling plans and the development and optimization of producing assets;
•
the judicial plans to achieve a hearing of the Company’s claim made in connection with Quebec’s
Bill 21;
6
Questerre Energy Corporation
•
working collaboratively to find a political and business solution with the Government of Quebec;
•
future production of oil, natural gas and natural gas liquids;
•
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 enhancement of existing production through workovers and expanding the pilot secondary
recovery scheme at Antler;
•
the transfer of wells drilled in 2025 from the proved undeveloped to the proved producing
category;
•
the need for additional LNG facilities to materially improve natural gas prices;
•
hedging policy;
•
liquidity and capital resources;
•
the negotiation by a special committee of the Red Leaf board of an agreement to fund and
advance a small-scale demonstration project in Jordan;
•
the Company’s plans to utilize the Red Leaf technology for its project in Jordan;
•
the Company’s negotiations and finalization of a concession agreement in Jordan;
•
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;
•
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:
•
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;
•
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;
2025 Annual Report
7
•
general economic conditions;
•
the terms and availability of credit facilities;
•
counterparty credit risk;
•
changes or fluctuations in oil, natural gas liquids and natural gas production levels;
•
liabilities inherent in oil and natural gas operations;
•
adverse judicial rulings, regulatory rulings, orders and decisions;
•
attracting, retaining and motivating skilled personnel;
•
uncertainties associated with estimating oil and natural gas reserves and resources;
•
insufficient advancement by Red Leaf in the engineering of its proprietary process;
•
competition for, cost and availability of, among other things, capital, acquisitions of reserves,
undeveloped lands, 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.
8
Questerre Energy Corporation
BOE Conversions
Barrel of oil equivalent (“boe”) amounts may be misleading, particularly if used in isolation. A boe
conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas
to one barrel of oil, and is based on an energy equivalent conversion method application at the burner
tip and does not necessarily represent an economic value equivalency at the wellhead. Given that the
value ratio based on the current price of crude oil as compared to natural gas is significantly different
from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an
indication of value.
Non-GAAP Measures
This document contains certain financial measures, as described below, which do not have
standardized meanings prescribed under GAAP. As these measures are commonly used in the oil and
gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned
that these amounts may not be directly comparable to measures for other companies where similar
terminology is used.
This document contains the term “adjusted funds flow from operations”, which is an additional non-
GAAP measure. The Company uses this measure to help evaluate its performance.
As an indicator of the Company’s performance, adjusted funds flow from operations should not be
considered as an alternative to, or more meaningful than, net cash from operating activities as
determined in accordance with GAAP. The Company’s determination of adjusted funds flow from
operations may not be comparable to that reported by other companies.
Adjusted Funds Flow from Operations Reconciliation
($ thousands)
2025
2024
Net cash from operating activities
$
9,237
$
13,093
Transaction costs
3,276
–
Change in non-cash working capital
7,830
886
Adjusted funds flow from operations
$
20,343
$
13,979
This document also contains the terms “operating netbacks”, “cash netbacks” and “working capital
surplus,” 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.
2025 Annual Report
9
The Company also uses the term “working capital surplus”. Working capital surplus, 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, as used by the Company,
is calculated as current assets less current liabilities excluding any outstanding risk management
contracts and lease liabilities.
10
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
77,346
36,927
41,701
Adjusted Funds Flow from Operations
(1)
20,343
13,979
15,855
Cash Flow from Operations
9,237
13,093
16,317
Basic and Diluted ($/share)
0.04
0.03
0.04
Net Income (Loss)
(31,998)
(7,329)
(23,708)
Basic and Diluted ($/share)
(0.07)
(0.02)
(0.06)
Capital Expenditures
25,358
20,640
10,148
Working Capital Surplus
(2)
(24,831)
23,091
29,866
Total Assets
434,887
170,723
172,346
Shareholders' Equity
123,688
138,629
143,667
Common Shares Outstanding (thousands)
445,764
428,516
428,516
Weighted average - basic (thousands)
445,763
428,516
428,516
Weighted average - diluted (thousands)
449,948
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)
Crude Oil and Natural Gas Liquids ($/bbl)
79.80
91.92
94.01
Crude Oil - Brent ($USD/bbl)
86.18
—
—
Natural Gas ($/Mcf)
2.35
1.65
3.02
Total ($/boe)
57.10
57.45
61.83
Netback ($/boe)
Petroleum and Natural Gas Revenue
(4)
57.10
57.45
61.83
Royalties Expense
(4)
(4.71)
(4.32)
(8.89)
Percentage
8%
8%
14%
Operating Expense
(4)
(33.91)
(23.58)
(23.84)
Operating Netback
18.48
29.55
29.10
General and Administrative Expense
(4)
(6.39)
(8.60)
(7.54)
Cash Netback
12.09
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 15 in the Consolidated Financial Statements for the years ended December 31, 2025 and 2024.
(4)
Refer to Consolidated Statement of Comprehensive Loss and Comprehensive Loss for the years ended December 31, 2025 and
2024.
2025 Annual Report
11
Highlights
•
Closed acquisition of PX Energy, an integrated oil shale company in southern Brazil with
production of 4,411 boe per day
•
Consolidated ownership of Red Leaf Resources
•
Spun-out of Quebec assets through share reorganization
•
Average daily production of 3,711 boe per day, net cash from operating activities of $5.8
million and adjusted funds flow from operations of $11.1 million
•
Total proved and probable reserves for PX Energy are xxxMMBOE with a NPV 10% of xxxx
•
Total proved and probable reserves for our Canadian assets declined by less than 10% to 22.4
MMboe with a before tax NPV 10% of $133.3 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 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 access to its proprietary technology to produce oil from oil shale that incorporates carbon
capture.
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 through a wholly
owned subsidiary of the Company.
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 reserve as of December 31, 2025, were _ MMbbls with an
NPV-10% of $ million. Average daily production from PX Energy for the fourth quarter was over 4,000
boe per day.
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:
12
Questerre Energy Corporation
•
25 million Common Shares subject to the achievement of US$30 million in free cash flow 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 subject to the achievement of US$40 million in free cash flow or
the completion of an equity issue by the Company of $25 million at a price of $1.00 per
Common Share no later than September 30, 2028.
Pursuant to the agreement between the Company and the vendors (the “Acquisition Agreement”),
the Company has notified the vendors it is seeking a purchase price adjustment of US$_ 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.
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
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 conditions precedent including receipt of regulatory approvals, the filing of a
Proxy/Registration Statement with the 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 subject to the issuance of the First Tranche Common Shares and associated
transactions, the Company’s subsidiary will assume convertible promissory notes originally issued by
the vendor in the principal amount of $15.2 million. The notes bear interest at 12% per annum and
are due on December 31, 2026. PX Energy has issued a US$5 million guarantee for these notes.
Subject to conditions precedent in the BCA and the closing of the SPAC transaction, the notes are
convertible into common shares of the SPAC. If the SPAC transaction does not proceed, the notes
are due and payable or convertible into equity of the Company’s subsidiary. Liabilities acquired under
the acquisition included US$80 million in senior secured callable bonds issued by FRBH with a
maturity date of April 24, 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 follows:
2025 Annual Report
13
Interest dropped from 16% per annum 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.
Concurrent with the Acquisition, the Company entered a binding term sheet with Nice Capital
Holdings Ltda. (“Nice”) for a 50/50 joint venture for the ownership and management of PX Energy
(the “Joint Venture”). After yearend, the Company was advised by Nice that the term sheet for a
50/50 joint venture to develop PX Energy expired in accordance with its terms.
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. 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 and
17% of its preferred equity capital.
Total consideration was $8.6 million and consisted of the issuance of 20.4 million Questerre Common
Shares to Red Leaf common shareholders with a deemed value of $0.31 per Common Share and $2.2
million cash to acquire Red Leaf preferred shares not held by the Company.
Questerre intends to utilize the Red Leaf technology for its project in the Kingdom of 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.
For 2026, the Company plans to optimize the operations of PX Energy to improve profitability and
assess 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 1,142 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
14
Questerre Energy Corporation
40,320 (17,700 net) acres in the Kakwa area.
At Kakwa North, the operator finalized a three 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.
In Antler, 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 wells. (2024: $0.8 million). Daily production averaged 207 bbl/d (2024: 250 bbl/d). Total
proved and probable reserves as at December 31, 2025, were estimated at 1.2 MMBbls (2024: 1.2
MMBbls) with a before tax NPV-10% of $17.4 million (2024: $21.9 million). The Company currently
holds 14,730 net acres in the area.
In 2026, the Company expects to continue its work to enhance existing production through workovers
and expanding the pilot secondary recovery scheme while assessing future drilling locations.
Quebec
The Company’s primary objective remains the implementation of a business and political solution for
the development of its natural gas discovery in the province. Concurrently, it is protecting its legal
rights following the enactment in August 2022 of Bill 21,
An Act mainly to end petroleum exploration
and production and the public financing of those activities in Quebec
(“Bill 21”).
Discussions remain ongoing with the Quebec Ministry of Economy, Innovation and Energy, for the
Company’s carbon storage pilot project application under Bill 21. The project includes a
comprehensive program to assess the carbon storage potential including injection and monitoring
wells, compression facilities and a pipeline to an adjacent industrial park. The Company is seeking
Government funding for this pilot project. The Company is participating in the consultation process
for new regulations 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.
2025 Annual Report
15
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.
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 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 Shares for one new Common Share and one Series 2 Preferred Share. The Preferred
Share entitle shareholders 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.
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 of PX Energy contributed to
production volumes doubling over the prior year.
Production from Kakwa 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 63% of Company
volumes. Including light oil production from the Company’s assets in Saskatchewan and Manitoba,
production grew 110% over the prior year with an approximately equal weighting between oil and
liquids and natural gas. The production volumes in Brazil reflect the acquisition of PX Energy that
closed at the end of the third quarter. Production is primarily heavy crude oil and includes both
volumes from the mining and processing of oil shale and the processing of refinery waste.
16
Questerre Energy Corporation
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 stable production volumes from Brazil.
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
29,870
2,013
31,883
–
–
–
$
70,281
$
7,065
$
77,346
$
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.
Petroleum and natural gas revenue increased by 111% over the prior year even with 60% of a decline
due to the lower commodity prices. 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
Brent Crude ($/bbl)
96.66
–
Realized prices:
Natural Gas ($/Mcf)
2.35
1.65
Crude Oil and Natural Gas Liquids ($/bbl)
79.80
91.92
Brent Crude ($/bbl)
86.18
–
Note: Oil and liquids include light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.
Crude Oil
The WTI price decreased 17% to US$64.86 per barrel compared to US$75.72 per barrel in 2024. The
decreases are primarily due to OPEC+ unwinding voluntary production cuts, leading to an oversupply
in the global market and bearish sentiment.
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, the Company’s oil and liquids production, consisting primarily of a premium heavy fuel oil, is
based on Brent pricing with applicable premiums as published by the state controlled energy
company. Realized prices are based on produced volumes less volumes utilized in the production
process and reflect applicable discounts offered to customers for transportation. For the year ended
2025 Annual Report
17
December 31, 2025, Brazil’s realized price for crude oil and natural gas liquids averaged $86.47 per
barrel compared to the benchmark Brent Crude Oil that averaged $96.66 per barrel. Brazil realized
price for crude oil and natural gas liquids is primarily influenced by the price of Brent crude.
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 16% to an average of
$1.40 per Mcf compared to $1.38 per Mcf in 2024.
Including the higher heat content gas from Kakwa, the Company’s realized natural gas prices averaged
$2.35 per Mcf (2024: $1.65 per Mcf).
Royalties
($ 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 production. 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 10% on the value of oil shale production and a 2%
royalty on production volumes related to waste oil processing (TBC with PX).
Operating Costs
($ thousands)
2025
2024
Canada
$
21,822
$
15,158
Brazil
24,111
–
Total Company
$
45,933
$
15,158
$/boe:
Canada
33.91
23.58
Brazil
59.37
–
Total Company
$
33.91
$
30.61
18
Questerre Energy Corporation
Gross operating costs increased by over $30 million to $46 million in 2025. Over 75% of this increase
is attributable to the PX Energy assets acquired at the end of the third quarter of the year.
In Canada, operating costs at Kakwa, Alberta, specifically transporting and disposing of produced
water increased by $0.4 million with production from new wells. On a unit of production basis, this
increase from $30.61 per boe to $34.06 per boe.
In Brazil, operating costs are largely fixed and include mining, refining and energy costs. During the
quarter, they averaged $59.88 per boe.
General and Administrative Expenses
($ thousands)
2025
2024
Canada general and administrative expenses
$
9,912
$
5,530
Brazil general and administrative expenses
2,017
–
Transaction costs from acquisition
(3,276)
–
General and administrative expenses, net
$
8,653
$
5,530
Gross General & Administrative expenses (“G&A”) nearly double to $8.7 million from $5.5 million last
year. Just over 50% of this increase of $6.4 million or $3.3 million relates to transaction costs for PX
Energy acquisition. Post the acquisition, the Company incurred $2 million in ongoing G&A costs.
Compared to last year, the Company also saw an increase in wages and costs related to its Quebec
assets.
Depletion, Depreciation, Impairment, Accretion and Lease Expiries
For the year ended December 31, 2025, the Company recorded depletion, depreciation, and accretion
expense of $25.9 million (2024: $12.5 million) with depletion accounting for over 90% of this amount.
On a unit of production basis this increased to $18.39 per boe from $17.60 per boe last year. The
reduction due to lower production volumes was offset by the increase in the carrying value of its
assets on a boe basis.
In 2024, the Company assessed its property, plant, and equipment (“PP&E”) assets for indicators of
impairment or impairment reversals. With respect to the Kakwa cash generating unit (“CGU”) an
indicator of impairment was identified as a result of the reduction in the volume of reserves due to
technical revisions. The result of the impairment test, based on a fair value less costs of disposal
(“FVLCD”) assessment of the Kakwa CGU was that no impairment or impairment reversals were
recorded. The estimates of FVLCD were determined using a discount rate of 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 2024.
In 2024, the Company assessed the carrying value of its exploration and evaluation (“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
2025 Annual Report
19
million. No other impairment was recorded in the current year. In 2023 the Company recorded $0.8
million of impairment expense at Antler.
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
$0.3 million (2024: $0.3 million) in expense that was capitalized during the year.
Equity Investment
Questerre previously held approximately 38% of the outstanding equity interest in Red Leaf. Prior to,
the Company acquired the remaining 62% equity interest, resulting in Questerre obtaining 100%
ownership and control of Red Leaf. 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 $1.0 million was recognized. Further details regarding the transaction
are provided in Note 6 to the Financial Statements.
Finance income and expenses
The Company earned interest income of $3.3 million and other income of $2.4 million for the year
ended December 31, 2025 while expensing $11.8 million for the year ended. In the prior year, other
income included $1.1 million of interest that was earned on its cash and term deposits.
Other Comprehensive Income (Loss)
In 2025, the Company recorded other comprehensive income of $4.9 million (2024: $0.6 million)
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 $18.3 million compared
to a net loss of $7.3 million in the prior year. Compared to last year, the loss in the current year is
reduced by a deferred tax recovery offsetting with increased in overall increase in expenses plus a
new finance expenses from PX Energy.
Including other comprehensive income, the Company reported a total comprehensive loss of $13.5
million compared to a loss of $6.8 million last year.
Cash Flow from Operating Activities
The Company reported cash flow from operating activities of $13.6 million (2024: $13.7 million). The
variance over the prior year is attributed to the lower adjusted funds flow from operations and a
decrease in the non-cash working capital in the current year compared to an increase last year.
20
Questerre Energy Corporation
Cash Flow used in Investing Activities
Consistent with higher capital spending, the cash used in investing activities increased to $25.9 million
from $16.9 million last year. Expenditures increased by $10.5 million to $20.6 million and the Company
recorded an increase in non-cash working capital in the current year compared to a decrease last year.
Cash Flow used in Financing Activities
For both current and prior years, cash used in financing activities relates to the principal portion of the
lease payments.
Capital Expenditures
($ thousands)
2025
2024
Canada
$
24,048
$
20,640
Brazil
1,310
–
Total
$
25,358
$
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, $24.2 million was incurred to finish drilling, completing and tying-in three (1.5
net) wells in Kakwa and two (100% net) wells in Antler; and
•
In Brazil, $1.4 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 $42.8 million from $9.6
million last year. The increase in revenue 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/decreased $_ million over the
prior year with higher production volumes offsetting the impact of lower prices (TBC).
The acquisition of PX Energy also contributed to the increase in operating costs for the fourth
quarter. The acquired assets in Brazil accounted for $_ million with the remainder representing
the costs attributable to its assets in Canada. Operating costs in Canada increased over the prior
quarter and same period last year due to higher water transportation and disposal costs at Kakwa
2025 Annual Report
21
(TBC).
Including impairment expense relating to its E&E assets in Jordan, the Company reported a net loss
of $8.1 million (2023: $26 million loss) and total comprehensive loss of $7.5 million (2023: $26.3
million) for the quarter. Despite lower expenses in the current year, the loss is largely due to the
impairment expense. In the prior year, the loss was higher due to higher impairment expense.
In the fourth quarter, net cash from operating activities was $3.8 million (2023: $5.2 million). This
reflects the higher adjusted funds flow from operations of $3.7 million (2023: $3.2 million) and a
smaller increase in non-cash working capital of $0.1 million compared to $1.9 million last year. Net
cash used in investing activities increased to $7.9 million over $3.4 million in the prior year due to
higher capital spending associated with Kakwa North wells. There was no change in the net cash
used in financing activities over the prior 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.
At December 31, 2025, and 2024, there were no material borrowings under its credit facility and the
Company is compliant with all its covenants under the credit facilities. 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 13 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 2025. 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.
22
Questerre Energy Corporation
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.
March 26,
December 31,
December 31,
(thousands)
2026
2025
2024
Common Shares
452,213
445,764
428,516
Stock Options
47,885
35,790
38,295
Weighted average Common Shares
Basic
445,763
428,516
Diluted
449,948
431,715
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
(8,855)
0.22
(620)
0.27
Expired
(325)
0.16
(6,175)
0.29
Outstanding, end of period
35,790
$
0.25
38,295
$
0.25
Exercisable, end of period
28,288
$
0.26
29,704
$
0.25
Commitments
A summary of the Company’s net commitments at December 31, 2025 follows:
($ thousands)
2026
2027
2028
Transportation and Processing
$
2,219
$
1,094
$
0
2025 Annual Report
23
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
6 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.
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
24
Questerre Energy Corporation
sufficient capital, it may be required to defer, reduce or restructure planned capital programs or other
strategic initiatives.
Questerre faces several financial risks over which it has no control, such as commodity prices,
exchange rates, interest rates, access to credit and capital markets, as well as changes to government
regulations and tax and royalty policies.
The Company uses the following guidelines to address financial exposure:
•
Internally generated cash flow provides the initial source of funding on which the Company’s
annual capital expenditure program is based.
•
Equity, including flow-through shares, if available on acceptable terms, may be raised to fund
acquisitions and capital expenditures.
•
Debt may be utilized to expand capital programs, including acquisitions, when it is deemed
appropriate and where debt retirement can be controlled.
•
Farm-outs of projects may be arranged if management considers that a project requires too
much capital or where the project affects the Company’s risk profile.
Credit risk represents a potential financial loss to the Company if a customer or counterparty to a
financial instrument fails to meet or discharge their obligation to the Company. Credit risk arises from
the Company’s receivables from joint venture partners and oil and gas marketers. In the event such
entities fail to meet their contractual obligations to the Company, such failures may have a material
adverse effect on the Company’s business, financial condition, results of operations and prospects.
Credit risk also arises from the Company’s cash and cash equivalents. In the past, the Company
manages credit risk exposure by investing in Canadian banks and credit unions. Management does
not expect any counterparty to fail to meet its obligations.
Poor credit conditions in the industry may impact a joint venture partner’s willingness to participate in
the Company’s ongoing capital program, potentially delaying the program and the results of such
program until the Company finds a suitable alternative partner if possible.
Substantially all of the accounts receivable are with oil and natural gas marketers and joint venture
partners in the oil and natural gas industry and are subject to normal industry credit risks. The
Company generally extends unsecured credit to these customers and therefore, the collection of
accounts receivable may be affected by changes in economic or other conditions. Management
believes the risk is mitigated by entering into transactions with long-standing, reputable
counterparties and partners.
Accounts receivable related to the sale of the Company’s petroleum and natural gas production are
paid in the following
month from major oil and natural gas marketing and infrastructure companies
and the Company has not experienced any credit loss relating to these sales to date. Pursuant to IFRS
9, the Company made a provision of $0.04 million at December 31, 2025, for its expected credit losses
related to its accounts receivable.
2025 Annual Report
25
Receivables from joint venture partners are typically collected within one to three
months after the
joint venture bill is issued. The Company mitigates this risk by obtaining pre-approval of significant
capital expenditures.
The Company has issued and may continue in the future to issue flow-through shares to investors.
The Company has historically used its best efforts to ensure that qualifying expenditures of Canadian
Exploration Expense ("CEE") are incurred in order to meet its flow-through obligations. In 2017, the
Federal Government amended the law regarding what expenses constitute CEE. Generally, oil and
gas drilling expenses are now Canadian Development Expense rather than CEE. In the event that the
Company has CEE expenditures reclassified under audit by the Canada Revenue Agency or fails to
incur expenditures required under a flow-through share agreement, the Company may be required to
liquidate certain of its assets in order to meet the indemnity obligations under flow-through share
subscription agreements.
Exploration and development drilling risks are managed through the use of geological and geophysical
interpretation technology, employing technical professionals and working in areas where those
individuals have experience. For its non-operated properties, the Company strives to develop a good
working relationship with the operator and monitors the operational activity on the property. The
Company also carries appropriate insurance coverage for risks associated with its operations.
The Company may use financial instruments to reduce corporate risk in certain situations. Questerre’s
hedging policy is up to a maximum of 40% of total production at management’s discretion.
As at December 31, 2025, the Company had no outstanding commodity risk management contract in
place.
Environmental Regulation and Risk
The Company’s operations are subject to extensive environmental laws and regulations in the
jurisdictions in which it operates. These requirements govern, among other things, emissions, water
use, waste handling, site restoration, abandonment and reclamation, and remediation of
contaminated properties. Compliance with these requirements may increase capital expenditures,
operating costs and administrative obligations, and may affect the timing and economics of the
Company’s exploration, development and production activities. Failure to comply could result in
penalties, the suspension or revocation of approvals, remediation orders or other liabilities.
For Questerre, these risks are particularly relevant in Canada, where environmental and climate-
related regulation continues to evolve. 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.
26
Questerre Energy Corporation
More broadly, climate-related policy, carbon regulation, methane requirements and changing
stakeholder expectations may increase the Company’s costs, reduce operational flexibility and affect
the competitiveness and economic viability of certain projects. These developments may also affect
reserve values, access to capital and the Company’s ability to advance portions of its asset base.
While the Company seeks to manage these risks through compliance, operational planning and
ongoing monitoring of regulatory developments, there can be no assurance that future environmental
or climate-related measures will not have a material adverse effect on its business, financial condition
and results of operations.
For more information, please refer to the “Risk Factors” and “Industry Conditions” sections of the
AIF.
Interest Rate Risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market
interest rates. Following the PX Energy acquisition, the Company is exposed to variable-rate risk
through the senior secured bonds acquired as part of that transaction.
Under the terms of the bonds, all accrued and unpaid interest up to December 31, 2025 converts into
shares if the contemplated SPAC transaction is completed. If the SPAC transaction does not proceed,
no interest is payable in 2025. Thereafter, interest is payable quarterly at variable rates determined by
reference to Brent crude oil prices, ranging from 4% when Brent is below US$55 per barrel to 20%
when Brent exceeds US$95 per barrel, subject to an overall cap such that interest does not exceed
16% over the term of the bonds. Interest in 2026 may be settled in cash or in kind at the issuer’s
election. From 2027 onward, interest is payable in kind if Brent prices are below US$65 per barrel.
The maturity of the bonds may also be extended for up to two additional one-year terms for a fee
equal to 2% of principal for each extension.
At December 31, 2025, the Company’s exposure to variable-rate debt under these bonds was US$80
million (2024 – nil). As a result, changes in Brent pricing may affect the amount and timing of interest
payable and, in certain periods, whether interest is settled in cash or in kind. The Company monitors
this exposure in assessing its financing costs and expected liquidity requirements.
At December 31, 2025, and 2024, the Company’s credit facilities outstanding balance was essentially
nil.
Critical Accounting Estimates
The preparation of the consolidated financial statements requires management to make judgments,
estimates and assumptions that affect the application of accounting policies and the reported
amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates.
These estimates and judgments have risk of causing a material adjustment to the carrying amounts
of assets and liabilities within the next financial
year.
2025 Annual Report
27
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting
estimates are recognized in the
year in which the estimates are revised and in any future
years
affected.
Petroleum and Natural Gas Reserves
All of Questerre’s petroleum and natural gas reserves are evaluated and reported on by independent
petroleum engineering consultants in accordance with
National Instrument 51-101 Standards of
Disclosure for Oil and Gas Activities
and the COGE Handbook. For further information, please refer to
“Statement of Reserves Data and Other Oil and Gas Information” in the AIF.
The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected
future rates of production, commodity prices and the timing of future expenditures, all of which are
subject to numerous uncertainties and various interpretations. The Company expects that its
estimates of reserves will change to reflect updated information. Reserve estimates can be revised
upward or downward based on the results of future drilling, testing, production levels and changes in
costs and commodity prices. These estimates are evaluated by independent reserve engineers at
least annually.
Proved and probable reserves are estimated using independent reserve engineer reports and
represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological,
geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable
in future
years from known reservoirs and which are considered commercially producible. If
probabilistic methods are used, there should be at least a 50
percent probability that the quantities
actually recovered will equal or exceed the estimated proved plus probable reserves and there should
be at least a 90
percent probability that the quantities actually recovered will equal or exceed the
estimated proved reserves.
Reserve estimates impact a number of the areas, in particular, the valuation of property, plant and
equipment and the calculation of depletion.
Cash Generating Units
A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are
largely independent of the cash inflows of other assets or groups of assets. The allocation of assets
into CGUs requires significant judgment and interpretations. Factors considered in the classification
include geography and the way management monitors and makes decisions about its operations.
Impairment of Property, Plant and Equipment, Exploration and Evaluation Assets
The Company assesses its oil and natural gas properties, including exploration and evaluation assets,
for possible impairment or reversal of previously recognized impairments 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.
28
Questerre Energy Corporation
The recoverable amounts of CGUs have been determined based on the VIU and the FVLCD. The key
assumptions the Company uses in estimating future cash flows for recoverable amounts are
anticipated future commodity prices, expected production volumes, the discount rate, future
operating and development costs and recent land transactions. Changes to these assumptions will
affect the recoverable amounts of the CGUs and may require a material adjustment to their related
carrying value.
Asset Retirement Obligation
Determination of the Company’s asset retirement obligation is based on Government regulations,
operator estimates, internal estimates using current costs and technology in accordance with existing
legislation and industry practice and must also estimate timing, a risk-free rate and inflation rate in the
calculation. These estimates are subject to change over time and, as such, may impact the charge
against profit or loss. The amount recognized is the present value of estimated future expenditures
required to settle the obligation using a risk-free rate. The associated abandonment and retirement
costs are capitalized as part of the carrying amount of the related asset. The capitalized amount is
depleted on a unit of production basis in accordance with the Company’s depletion policy. Changes
to assumptions related to future expected costs, risk-free rates and timing may have a material impact
on the amounts presented.
Share Based Compensation
The Company has a stock option plan enabling employees, officers and directors to receive Common
Shares or cash at exercise prices equal to the market price or above on the date the option is granted.
Under the equity settled method, compensation costs attributable to stock options granted to
employees, officers or directors are measured at fair value using the Black-Scholes option pricing
model. The assumptions used in the calculation are: the volatility of the stock price, risk-free rates of
return and the expected lives of the options. A forfeiture rate is estimated on the grant date and is
adjusted to reflect the actual number of options that vest. Changes to assumptions may have a
material impact on the amounts presented.
Income Tax Accounting
Deferred tax assets are recognized when it is considered probable that deductible temporary
differences will be recovered in the foreseeable future. To the extent that future taxable income and
the application of existing tax laws in each jurisdiction differ significantly from the Company’s
estimate, the ability of the Company to realize the deferred tax assets could be impacted.
The determination of the Company’s income and other tax assets or liabilities requires interpretation
of complex laws and regulations. All tax filings are subject to audit and potential reassessment after
the lapse of considerable time. Accordingly, the actual income tax asset or liability may differ
significantly from that estimated and recorded by management.
2025 Annual Report
29
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.
30
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 ($/boe)
65.93
44.32
48.62
58.66
Petroleum and Natural Gas Revenue
42,740
11,801
13,675
9,130
Adjusted Funds Flow from Operations
(1)
6,551
2,813
5,005
3,543
Cash Flow from Operations
(6,825)
1,294
6,288
3,359
Net Profit (Loss)
(28,266)
(5,334)
(677)
4
Basic and Diluted ($/share)
(0.06)
(0)
–
–
Capital Expenditures, net of acquisitions and
dispositions
4,198
2,248
1,048
17,864
Working Capital Surplus
(22,981)
(40,330)
13,157
9,202
Total Assets
434,887
384,853
169,976
181,519
Shareholders' Equity
123,688
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.
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
23,091
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.
2025 Annual Report
31
The general trends over the last eight quarters are as follows:
•
Petroleum and natural gas revenues and adjusted funds flow from operations have fluctuated with
production volumes and realized commodity prices. Revenue has generally declined in 2024 as a
result of a 7% drop in realized commodity prices in 2024 compared to 2023.
•
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 the fourth quarter of 2023, $3 million was also invested at Antler.
•
The working capital position has generally increased when capital expenditures and other
investments have been lower than adjusted funds flow from operations and cash from financing
activities.
•
Shareholders equity generally decreased as a result of net loss incurred in the last six quarters.
Off-Balance Sheet Transactions
The Company did not engage in any off-balance sheet transactions during the
year ended December
31, 2024.
32
Questerre Energy Corporation
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
26, 2025
2025 Annual Report
33
Independent Auditor’s Report
To the Shareholders of Questerre Energy Corporation
Opinion
We have audited the consolidated financial statements of Questerre Energy Corporation (the
Company) which comprise the consolidated balance sheet as at December 31, 2024 and 2023, and
the consolidated statement of net loss and comprehensive loss, consolidated statement of changes
in equity and consolidated statement 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 Company as at December 31, 2024 and 2023, 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
Company 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 Matter
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. This matter was 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 this matter.
For the 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
this
matter.
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 matter below,
provide the basis for our audit opinion on the accompanying consolidated financial statements.
34
Questerre Energy Corporation
Key audit matter
How our audit addressed the key audit matter
Impairment of property, plant and equipment
As at December 31, 2024, the carrying amount of
property, plant and equipment in the Western
Canada operating segment was $116.7 million.
Property, plant and equipment is tested for
impairment only when circumstances indicate that
the carrying amount of a Cash Generating Unit
(“CGU”) may exceed its recoverable amount. As
impairment indicators existed in the Kakwa CGU in
the Western Canada operating segment, property,
plant and equipment for the Kakwa CGU was
tested for impairment.
For the year ended December 31, 2024, an
impairment test was performed resulting in nil
impairment being recorded with respect to
property, plant and equipment in the Kakwa CGU.
Refer to Note 2(e) for a description of the
Company’s estimates and judgements relating to
impairment and to Note 3(f) for a description of the
Company’s impairment of non-financial assets
accounting policy. Refer to Note 8 for the
Company’s
property,
plant
and
equipment
impairment disclosures.
Auditing the Company’s estimated recoverable
amount for the Kakwa CGU was complex due to
the subjective nature of the underlying inputs and
assumptions and the significant effect changes in
these could have on the recoverable amount.
Additionally, the evaluation of this estimate
required specialized skills and knowledge. The
primary inputs noted in the fair value less cost of
disposal
model
was
forecasted
production,
escalated pricing, royalties, operating costs, future
development costs and an after-tax discount rate.
Determining the amount of impairment requires an
estimate of a CGU’s respective recoverable
amount. The recoverable amount of the CGU was
determined using a fair value less costs of disposal
To test the Company's estimated recoverable
amount of the Kakwa CGU within the Western
Canada operating segment, we performed the
following procedures, among others:
•
Evaluated
management’s
experts’
competence, capability and objectivity as
well as obtained an understanding of the
work
they
performed.
The
appropriateness of their work as audit
evidence was evaluated by considering
the relevance and reasonableness of the
methods and assumptions utilized;
•
Involved our internal valuation specialists
to assess the methodology applied, and
the various inputs utilized in determining
the after-tax discount rate by referencing
current
industry,
economic,
and
comparable company information, as well
as company and cash-flow specific risk
premiums;
•
With the assistance of our internal
valuation specialists, we compared the
market capitalization to net assets and
observed
quantitative
and
qualitative
reconciliations using market data and
transactions;
•
Compared
forecasted
benchmark
commodity
pricing
against
historical
realized prices and to other third-party
price forecasts;
•
Assessed
forecasted
production,
royalties, operating costs, and future
development costs by comparing them to
historical results; and
•
Evaluated the adequacy of the impairment
note disclosure included in Note 8 of the
2025 Annual Report
35
model based on expected after-tax future net cash
flows from the production of proved plus probable
reserve volumes using forecast commodity prices
and costs, discounted using market-based rates.
Proved plus probable reserves were determined by
the Company’s independent petroleum engineers
(management’s experts).
accompanying
consolidated
financial
statements in relation to this matter.
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.
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
Company’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 Company or to cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’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
36
Questerre Energy Corporation
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 Company’s internal control.
•
Evaluate the appropriateness of accounting policies used and the reasonableness of
accounting estimates and related disclosures made by management.
•
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 Company’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 Company 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.
2025 Annual Report
37
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
26, 2025
38
Questerre Energy Corporation
Consolidated Balance Sheets
December 31,
December 31,
($ thousands)
Note
2025
2024
Assets
Current Assets
Cash and cash equivalents
7
$
$
Accounts receivable
16
Inventory
8
Deposits and prepaid expenses
Right-of-use assets
15
Investments
6
Property, plant and equipment
9
Intangible assets
11
Exploration and evaluation assets
10
Restricted cash
7
Other non current assets
$
$
Liabilities
Current Liabilities
Accounts payable and accrued liabilities
16
$
$
Advances from customers
Taxes and Contribution
Share issuance for acquisition
5
SPAC Convertible Notes
13
Lease liabilities
15
Asset retirement obligations
6,14
Other current liabilities
Lease liabilities
15
Taxes and Contribution
Deferred tax liability
Contingent consideration of acquisition of previous subsidiary
Secured debt
13
Other long term liabilities
16
Asset retirement obligation
6,14
Shareholders' Equity
Share capital
18
Contributed surplus
Accumulated other comprehensive income (loss)
(2,408 )
Deficit
(353,556 )
(321,428 )
$
$
The notes are an integral part of these consolidated financial statements.
Signed on behalf of the Board of Directors
Bjorn Inge Tonnessen, Director
Dennis Sykora, Director
2025 Annual Report
39
Consolidated Statements of Net Loss
For the year ended December 31,
($ thousands, except per share amounts
)
Note
2025
2024
Revenue
Petroleum and natural gas revenue
19
$
$
Royalties
(6,383 )
(2,776 )
Petroleum and natural gas revenue, net of royalties
Expenses
Operating
General and administrative
Depletion, depreciation and accretion
9,11,14
Impairment
10
Loss (gain) on equity investment
Transaction costs
Share based compensation
17
Other operating income
(2,412 )
Finance income
21
Finance expense
21
(16,175 )
Loss before taxes
$
(34,277 )
$
(7,329 )
Deferred tax recovery
12
(2,279 )
Net loss
$
(31,998 )
$
(7,329 )
Net Loss per Share
Basic and diluted
18
$
(0.07
$
(0.02
The notes are an integral part of these consolidated financial statements.
40
Questerre Energy Corporation
Consolidated Statements of Comprehensive Loss
For the year ended December 31,
($ thousands, except per share amounts
)
Note
2025
2024
Net loss
$
(31,998 )
$
(7,329 )
Other Comprehensive Income, Net of Tax
Items that may be reclassified subsequently to profit or loss:
Foreign currency translation adjustment
(3,304 )
Income on foreign exchange on investment
(3,304 )
Total Comprehensive Loss
$
(35,302 )
$
(6,413 )
The notes are an integral part of these consolidated financial statements.
2025 Annual Report
41
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
Balance, beginning and end of year
$
$
Contributed Surplus
Balance, beginning of year
Shares issued for acquisition
Share based compensation
Balance, end of year
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year
(20 )
Other comprehensive income (loss)
(3,304 )
Balance, end of year
(2,408 )
Deficit
Balance, beginning of year
(321,428 )
(314,099 )
Net loss
(31,998 )
(7,329 )
Balance, end of year
(353,426 )
(321,428 )
Total Shareholders' Equity
$
$
The notes are an integral part of these consolidated financial statements.
42
Questerre Energy Corporation
Consolidated Statements of Cash Flows
For the years ended December 31,
($ thousands)
Note
2025
2024
Operating Activities
Net loss
$
(31,998 )
$
(7,329 )
Adjustments for:
Depletion and depreciation
8,12,19
Accretion of asset retirement
Impairment
10
Gain (loss) on equity investment
7
Share based compensation
17
Foreign currency translation
(573 )
Finance income
Finance expense
21
Other operating income
20
Deferred tax expense
10
(2,279 )
Other items not involving cash
Abandonment expenditures
14
(1,072 )
(49 )
Change in non-cash working capital
(7,828 )
(886 )
Net cash from operating activities
Investing Activities
Property, plant and equipment expenditures
9
(9,349 )
(4,046 )
Exploration and evaluation expenditures
10
(16,009 )
(16,594 )
Cash acquired from asset acquisition
9
Cash acquired through business combination
Change in non-cash working capital
18
Net cash used in investing activities
(13,162 )
(16,855 )
Financing Activities
Contingent liability
(2,160 )
Principal portion of lease payments
19
(293 )
(65 )
Net cash used in financing activities
(2,453 )
(65 )
Change in cash and cash equivalents
(3,721 )
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
.
2025 Annual Report
43
Notes to the Consolidated Financial Statements
For the years ended December 31, 2025, and 2024
innovation company actively engaged in the acquisition, exploration and development of oil and gas
Questerre is incorporated under the laws of the Province of Alberta and is domiciled in Canada
Corporation, and its wholly-owned subsidiaries including Questerre Energy Corporation/Jordan, which
holds interests in the oil shale assets in Jordan, Paraná Xisto S.A. (“PX Energy”), located in the city
of São Mateus do Sul, Brazil, whose corporate purpose includes: (i) mining, refining, processing,
marketing, distribution, import, export, transportation, and storage of oil from wells, shale, or other
rocks, its derivatives, related products, and biofuels; (ii) production, distribution, and commercialization
of utilities such as steam, water, compressed air, and industrial gases, and Red Leaf Resources Inc.
(Red Leaf”), a technology company in the USA focused on developing, licensing, and commercializing
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 – Mining, refining, processing, distribution, and storage of oil from shale, or other rocks,
its derivatives and biofuels; production, distribution, and commercialization of utilities such as
steam, water, compressed air, and industrial gases, mainly in Brazil.
•
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
44
Questerre Energy Corporation
Segmented assets are those assets associated with each operating segment as recorded on the
consolidated balance sheets.
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 |
229,182 |
131,384 |
– |
784 |
361,350 |
Other |
30,853 |
36,282 |
– |
803 |
67,938 |
Total Assets, December 31, 2025 |
$ 260,035 |
$ 173,265 |
$ – |
$ 1,588 |
$ 434,887 |
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 |
$ 31,883 |
$ 45,463 |
$ – |
$ – |
$ 77,346 |
Expenses |
(25,019) |
(25,082) |
(2,215) |
(29,500) |
(81,816) |
Other income |
(32,716) |
2,909 |
– |
– |
(29,807) |
Total Loss, December 31, 2025 |
$ (25,852) |
$ 23,290 |
$ (2,215) |
$ (29,500) |
$ (34,277) |
Revenues |
$ – |
$ 34,151 |
$ – |
$ – |
$ 34,151 |
Expenses |
– |
(26,972) |
(671) |
(13,363) |
(41,006) |
Other income |
– |
– |
– |
(474) |
(474) |
Total Loss, December 31, 2024 |
$ – |
$ 7,179 |
$ – |
$ (13,837) |
$ (7,329) |
The Company prepares its consolidated financial statements in accordance with International Financial
Reporting Standards (“IFRS”) as issued by the International Accounting Standards Boards (“IASB”).
outstanding as
at March
26, 2026,
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
2025 Annual Report
45
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 has rights to the net assets of the arrangement. Joint ventures are
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 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
46
Questerre Energy Corporation
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
The Company assesses its oil and gas properties, including exploration and evaluation assets
(“E&E”), for possible impairment or reversal of previously recognized impairments 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-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.
Refer to Notes
10.
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
2025 Annual Report
47
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 gas properties (included in property, plant and equipment) derived from
estimated recoverable quantities of proved and probable oil and gas reserves and the related cash
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.
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
48
Questerre Energy Corporation
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
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
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.
Foreign currency differences are recognized in other comprehensive income ("OCI") and accumulated
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
2025 Annual Report
49
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
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
there is a legally enforceable right to offset the recognized amounts and there is an intention to settle
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
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 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 measured at amortized cost using the effective interest method less a
term deposits with original maturities of one
50
Questerre Energy Corporation
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 Resources Inc. in December, 2025, therefore, Red Leaf is
now the wholly owned subsidiary of the Company. See Note 6 for further details.
For the comparative period, the Company used the equity method of accounting to reflect its
ownership in Red Leaf. Under the equity method, the Company’s initial and subsequent investments
are recognized at cost and subsequently adjusted for the Company’s share of Red Leaf’s income or
loss, less distributions received. The Company is deemed to have significant influence in Red Leaf on
the basis that it holds more than 20% of the voting power and the ability to participate in the decision
Common Shares are classified as equity. Incremental costs directly attributable to the issue of
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
2025 Annual Report
51
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.
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.
52
Questerre Energy Corporation
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.
Amortization is calculated using the straight-line method based on the estimated useful life of the
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.
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 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 impairment loss had
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.
2025 Annual Report
53
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 required to adjust the loss allowance at the reporting date to the amount that is required to be
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 estimated on the grant date and is adjusted to reflect the actual number of options
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 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 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
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
54
Questerre Energy Corporation
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 actual amounts received are adjusted and recorded in the
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
2025 Annual Report
55
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 date and are reduced to the extent that it is no longer probable that the related tax
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
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
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
56
Questerre Energy Corporation
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 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
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
2025 Annual Report
57
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
On September 26, 2025, the Company closed the acquisition of 100% of the common shares 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 through a
wholly owned subsidiary of the Company.
The primary reason for the Acquisition is to advance the Company’s strategy of seeking to
commercially develop oil shale resources globally. It provides a platform of producing oil shale
operations, including mining, processing and refining facilities as well as oil shale reserves and
resources. PX Energy has over thirty years of operations and utilizes technology to produce oil from
oil shale developed by an integrated energy company. The Acquisition includes downstream
production expertise and complements the Company’s experience with upstream resource
development and technology assessment. It expands the Company’s existing portfolio of oil shale
assets including its project in the Kingdom of Jordan and its investment in Red Leaf, specifically its
rights to use Red Leaf’s proprietary technology to produce oil from shale that incorporates carbon
capture.
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.
Purchase Price Allocation
58
Questerre Energy Corporation
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 $14.9 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 $8.7
million. See Note 13 for details.
The contingent equity consideration is issuable upon the earlier of: (a) achievement of US$30 million
in free cash flow 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 or completion of
an equity financing of $25 million at $1.00 per common share on or before September 30, 2028.
The following table summarizes the details of the consideration and the recognized amounts of assets
acquired and liabilities assumed at the date of the acquisition:
Consideration Transferred | ($ thousands ) |
Pending share issuance for acquisition | $ 4,950 |
Contingent equity consideration | 13,941 |
Obligations related to convertible promissory notes | 15,188 |
Assumed liabilities | 7,572 |
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 | 7,957 |
Deposits and prepaid expenses | 3,351 |
Right-of-use assets | 1,698 |
Property, plant and equipment | 258,274 |
Intangible asset | 5,755 |
Deferred tax assets | – |
Other assets | 709 |
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) |
Provisions | (61,873) |
Contingent consideration for original acquisition of PX Energy | (15,333) |
Secured debt | (17,348) |
Asset retirement obligation | (95,539) |
Total liabilities assumed | $ (242,867) |
2025 Annual Report
59
Net Identifiable Assets Acquired | $ 50,851 |
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 $32 million and operating income
of $5 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:
[insert chart – proforma results]
Concurrent with the Acquisition, the Company entered a binding term sheet with Nice Capital
Holdings Ltda. (“Nice”) a subsidiary of Nimofast, a private fuel distributor in Brazil, for a 50/50 joint
venture for the ownership and management of PX Energy (the “Joint Venture”). In December 2025
the term sheet for a 50/50 joint venture to develop Parana Xisto SA (“PX Energy”) expired in
accordance with its terms, hence, the Company remained the 100% owner and operator of PX
whose principal assets are its proprietary HCCO technology to recover oil from shale, its oil shale
On December 30, 2025, the Company acquired the remaining equity interests in Red Leaf Resources
Inc., increasing its ownership from approximately to 100%. Total consideration transferred was $8.6
million and consisted primarily of (i) issuance of Questerre common shares to Red Leaf common
shareholders and (ii) cash paid to acquire/settle Red Leaf preferred shares. Right before the
acquisition, Questerre held approximately 38% of the common share capital of Red Leaf and
approximately 16% of the issued and outstanding preferred share capital of Red Leaf on a non-diluted
basis.
The Company assessed the acquired set of activities and assets and concluded that Red Leaf did not
meet the definition of a business for the purposes of IFRS 3
Business Combinations
. In making this
determination, the Company applied the optional concentration test in IFRS 3 and concluded that
substantially all of the fair value of the gross assets acquired was concentrated in a group of similar
identifiable assets. As a result, the transaction was accounted for as an asset acquisition and not as
a business combination.
The following table summarizes the Company’s allocation of the acquisition costs to the identified
assets acquire and liabilities assumed:
60
Questerre Energy Corporation
($ thousands ) | |
Cash and cash equivalents | $ 10,792 |
Restricted cash | 2,050 |
Other current assets | – |
Property, plant and equipment | 785 |
Asset retirement obligation | (313) |
Net Assets Acquired | $ 13,314 |
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 $5.2 million and the net
carrying value of the Red Leaf assets was $4.4 million. The company recognized a non-cash
revaluation gain of its existing interest of $0.8 million in the consolidated statements of
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Bank balances | $ 10,463 | $ 10,463 |
Short-term bank deposits | 14,956 | 21,328 |
Cash and Cash equivalents | $ 25,419 | $ 31,791 |
Letters of credit | $ 399 | $ |
Restricted Cash though business combination (Note 5) | 3,122 | – |
Restricted Cash and equivalents | $ 3,521 | $ – |
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Finished goods (1) | 2,447 | $ – |
In-process products (2) | 876 | – |
Materials and supplies (3) | 8,833 | – |
Provision for inventory obsolescence | (3,615) | – |
Provision for adjustments to net realizable value | (19) | – |
2025 Annual Report
61
Balance, end of period | $ 8,522 | $ – |
(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 |
Additions including change to asset retirement | 4,000 |
Transfer from exploration and evaluation assets | 8,605 |
Balance, December 31, 2024 | 326,926 |
Acquired in business combination (Note 5) | 258,273 |
Asset acquisition (Note 6) | 916 |
Capital expenditures | 9,596 |
Transfer from exploration and evaluation assets | 23,515 |
Changes to asset retirement obligation | (5,257) |
Foreign exchange adjustments | (9,747) |
Balance, December 31, 2025 | $ 604,222 |
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 | 33,117 |
Foreign exchange adjustments | (476) |
Balance, December 31, 2025 | $ 242,873 |
($ thousands ) | Total |
Net book value: | |
At December 31, 2024 | $ 116,695 |
At December 31, 2025 | $ 361,350 |
During the
years ended December 31, 2025, and 2024, the Company did not capitalize any
administrative overhead or share based compensation expense directly related to development
activities. Included in December 31, 2025, depletion calculation are future development costs of
$279.2 million (2024: $293.6 million) for Canada and ….
As at December 31, 2025, the future prices used for impairment testing to determine cash flows from
oil and natural gas reserves were as follows:
62
Questerre Energy Corporation
Average |
||||||
Annual % |
||||||
Change |
||||||
2026 |
2027 |
2028 |
2029 |
2030 |
Thereafter |
|
WTI (US$/barrel) |
59.92 |
63.82 |
67.55 |
67.79 |
67.78 |
2.00 |
BRENT (US$/barrel) |
63.92 |
67.77 |
71.47 |
71.71 |
71.71 |
2.00 |
AECO ($/MMbtu) |
3.00 |
3.24 |
3.35 |
3.38 |
3.38 |
2.00 |
With respect to the Kakwa CGU an indicator of impairment was identified as a result of the reduction
in the volume of reserves due to technical revisions. The result of the impairment test based on a
FVLCD assessment of the Kakwa CGU was that no impairment or impairment reversals were
recorded. 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 | $ 5,724 | $ 17,845 |
For the prior year, the Company recorded an impairment of $23.7 million as follows: Antler CGU
recorded an impairment expense of $5.3 million based on a FVLCD assessment and the Kakwa CGU
Exploration and evaluation assets consist of the Company’s exploration projects which are pending
the determination of technical feasibility and commercial viability. Additions represent the Company’s
share of costs incurred on exploration and evaluation assets during the period.
2025 Annual Report
63
December 31, | December 31, | |
($ 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 capitalized administrative overhead charges
of $0.6 million (2024: $0.4 million) and $0.3 million (2024: $0.3 million) for capitalized share based
compensation expense directly related to exploration and evaluation activities.
Due to the impending expiry of its exclusive exploration rights in Jordan in the first half of 2025 and
no immediate plans to conclude a subsequent agreement, the Company recorded an impairment
expense of $7.9 million representing its E&E assets in the country for the year ending 2024. No
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Balance, beginning of year | $ – | $ – |
Software (acquired on close of 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 | $ 5,536 | $ – |
Accumulated depreciation | (85) | – |
$ 5,452 | $ – |
64
Questerre Energy Corporation
NOT UPDATED
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 |
$ (34,277) |
$ (7,329) |
Combined federal and provincial tax rate |
23.82% |
23.82% |
Statutory tax (recovery) |
(8,165) |
(1,746) |
Increase/(deduction) in tax expense resulting from: |
||
Non-deductible differences and permanent items |
1,567 |
|
Change in deferred tax asset not recognized |
179 |
|
Change in deferred tax asset due to obtaining control of Red Leaf |
||
Difference in jurisdictional tax rates |
||
Other |
||
Total income tax expense |
$ (8,165) |
$ - |
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
costs associated with these proved reserves. As a result, no deferred tax asset was recorded. The
combined statutory tax rate was 23.82% in 2025 and 23.82% in 2024.
The movement in deferred tax assets and liabilities during the
year, without taking into consideration
the valuation allowances, are as follows:
The following temporary differences have not been recognized:
December 31, |
December 31, |
|
($ thousands) |
2025 |
2024 |
Petroleum and natural gas properties |
$ |
$ 165,651 |
Investments |
33,908 |
|
Asset retirement obligation and leases |
19,420 |
|
Tax Reserves |
– |
|
Other |
– |
|
Capital losses |
36,488 |
|
Net deferred income tax asset |
$ – |
$ 255,467 |
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
2025 Annual Report
65
liabilities. 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.
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
our Canadian non-capital loss carry forwards were $xxx and capital loss carry forwards were $xxx
million. The non-capital loss carry forwards begin to expire in 2046 and the capital losses do not expire
but can only be utilize against future capital gains. Our Brazil non-capital loss carry forwards were XXX
million Brazil Reais which does not expire but the annual use is restricted.
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Net deferred income tax asset, beginning of year | $ – | $ – |
Recognized in deferred income tax expense/(recovery) | – | – |
Acquired from Forbes/PX Energy Acquisition | – | – |
Change in unrecognized deferred tax assets | ||
Other | ||
Tax charge relating to components of other comprehensive income or | ||
loss | – | – |
Net deferred income tax asset, end of year | $ – | $ – |
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Secured bonds | 98,484 | – |
Convertible Promissory notes | 15,188 | – |
Balance, end of year | $ 113,672 | $ – |
Current debt | 15,188 | – |
Long-term debt | 98,484 | – |
Balance, end of year | $ 113,672 | $ – |
Secured Bonds
In connection with the PX Energy Acquisition, the Company acquired senior secured bonds issued by
FRBH with a maturity date of April 24, 2028. The bonds have a face value of US$80 million and an
acquisition date fair value of US$66 million. The carrying amount will accrete from US$66 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.
66
Questerre Energy Corporation
The terms of the bonds were negotiated as part of the closing of the acquisition and are as follows:
•
Interest 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 until 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.
Convertible Promissory Notes
The consideration for the Acquisition also included the assumption of the vendor’s obligations under
a business combination agreement (“BCA”) with a 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 conditions precedent including receipt
of regulatory approvals, the filing of a Proxy/Registration Statement with the 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, and other liabilities, with an
estimated fair value of $7.6 million. Related to the SPAC and subject to 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 conditional 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.
2025 Annual Report
67
The contingent obligations under the convertible promissory notes and other liabilities were measured
at their estimated fair value at the closing date of the Acquisition. See Note 5 or Note 13.
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 (“Facility A”). Facility
A 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 based on the ratio of debt to
over all assets of the Company and a general assignment of books debts.
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 Credit 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 Facility A.
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
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 $20 million as at December 31, 2025 (2024: $19.4 million) based on an undiscounted
total future liability of $23.4 million (2024: $24.6 million). These payments are expected to be made
over the next 31
years. The average discount factor, being the risk-free rate related to the liabilities,
is 3% (2024: 3.06%). An inflation rate of 2% (2024: 2%) over the varying lives of the assets is used
to calculate the present value of the asset retirement obligation.
68
Questerre Energy Corporation
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Balance, beginning of year | $ 19,410 | $ 19,064 |
Liabilities incurred | 110 | 352 |
Acquired on close of business combination (see Note 3) | 9,200 | – |
Revalue of obligation acquired through a business combination | 2,590 | – |
Acquired on asset acquisition | 313 | – |
Liabilities settled | (1,039) | – |
Revisions due to change in estimates and discount rates | (5,379) | (49) |
Accretion | 5,507 | (537) |
Foreign exchange adjustments | (531) | 580 |
Balance, end of year | $ 30,181 | $ 19,410 |
Current portion | 2,616 | – |
Non-current portion | 27,565 | 799 |
Balance, end of period | $ 30,181 | $ 799 |
Paraná Xisto S.A., a subsidiary of the Company, 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
deposit.
In the fourth quarter of 2025, the Company 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, the Company
identified a risk of non-compliance with certain of these requirements and is in discussions with the
2025 Annual Report
69
Right-of-use assets
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Balance, beginning of year | $ 128 | $ 180 |
Acquired from corporate acquisition | 1,698 | – |
Additions | 6 | 8 |
Depreciation | (285) | (60) |
Currency translation adjustment | (70) | |
Balance, end of year | $ 1,477 | $ 128 |
b)
Lease liabilities
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Balance, beginning of year | $ 139 | $ 192 |
Additions | 21 | 8 |
Acquired from corporate acquisition | 1,698 | – |
Interest expense | 23 | 4 |
Lease payments | (319) | (65) |
Currency translation adjustment | (69) | – |
Balance, end of year | $ 1,492 | $ 139 |
Current portion | 1,007 | 56 |
Long term portion | 485 | 83 |
Balance, end of year | $ 1,492 | $ 139 |
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Contingent consideration for original acquisition of PX Energy | $ – | $ – |
Assumed liabilities upon business combination with PX Energy | – | |
Provision for contingencies | 57,392 | – |
Taxes and contributions | – | – |
Deferred revenue | – | |
Long term customer financing | – | |
Other Long-term liabilities | – | – |
Less: Current Other liabilities | (28,266) | – |
Other long-term liabilities | $ 29,126 | $ – |
70
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, investments, credit facilities and accounts payable and accrued
liabilities. As at December 31, 2025, excluding the investment in Red Leaf, the fair values of the
Company’s financial assets and liabilities equaled their carrying values due to the short-term maturity.
within 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.
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 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.
2025 Annual Report
71
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 |
$ 9,089 |
$ 3,174 |
31 - 60 days |
1,931 |
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
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 the options available with respect to sources of long
72
Questerre Energy Corporation
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.
Following the PX Energy acquisition, the Company’s liquidity risk also includes obligations associated
with the senior secured bonds. The amount and timing of interest payments on these bonds are
variable and depend on Brent pricing, and 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$65 per
barrel. In addition, the maturity of the bonds may be extended for up to two additional one-year terms
for a fee equal to 2% of principal for each extension. Accordingly, the Company considers the potential
variability in the amount, timing and form of settlement of these obligations in its liquidity planning.
The Company’s financial obligations relates to amounts due under the credit facilities, including trade
and other payables, which consist of invoices payable to trade suppliers relating to the office and field
operating activities and its capital spending program. The Company processes invoices within a
normal payment period and all amounts are due within the next 12
months.
The timing of cash outflows relating to financial liabilities as at December 31, 2025, and 2024 are as
follows:
Less than |
Remaining |
||
($ thousands) |
one year |
years |
Total |
Accounts payable and accrued liabilities |
$ 32,240 |
$ – |
$ 32,240 |
Advances from customers |
5,329 |
– |
5,329 |
Taxes and Contribution |
988 |
– |
988 |
Share issuance for acquisition |
3,203 |
– |
3,203 |
Lease liabilities |
1,850 |
485 |
2,335 |
Current portion of asset retirement obligation |
2,616 |
27,565 |
30,181 |
SPAC Convertible Notes |
– |
– |
– |
Other current liabilities |
28,266 |
– |
28,266 |
December 31, 2025 |
$ 74,492 |
$ 28,050 |
$ 74,276 |
Less than | Remaining | ||
($ thousands) | one year | years | Total |
Trade and other liabilities | $ 12,496 | $ – | $ 12,496 |
Credit facility | 49 | – | 49 |
Lease liabilities | 56 | – | 56 |
Current portion of asset retirement obligation | 799 | – | 799 |
December 31, 2024 | $ 13,400 | $ – | $ 13,400 |
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.
2025 Annual Report
73
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 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.
Currency risk
fluctuate as a result of changes in foreign exchange rates. The Company operates internationally and
is exposed to foreign currency 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 U.S. 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
74
Questerre Energy Corporation
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
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
75
Annual and updated budgets are approved by the Board of Directors and are regularly reviewed to
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. The Company
did not settle any cash options in 2025.
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 | 14,550 | 0.65 | $ 0.19 |
$0.21 - $0.23 | 11,725 | 3.13 | 0.23 | 6,100 | 3.16 | 0.23 |
$0.24 - $0.26 | 5,950 | 3.10 | 0.25 | 6,700 | 4.10 | |
$0.27 - $0.34 | 10,340 | 1.06 | 0.34 | 10,945 | 2.06 | 0.34 |
35,790 | 1.86 | $ 0.25 | 38,295 | 2.06 | $ 0.25 | |
76
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 | (8,855) | 0.22 | (620) | 0.27 |
Expired | (325) | 0.16 | (6,175) | 0.29 |
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 ($) | 0.18 | 0.19 |
Volatility (%) | 102.60 | 103.47 |
Forfeiture rate (%) | 8.46 | 8.85 |
Expected life (years) | 5.00 | 5.00 |
Risk free interest rate (%) | 2.91 | 3.54 |
This forfeiture rate estimate is adjusted to the actual forfeiture rate. Expected volatility and expected
The Company is authorized to issue an unlimited number of Common Shares. The Company is also
authorized to issue an unlimited number of Class
“B” Common voting shares and an unlimited
number of preferred shares, issuable in one or more series. At December 31, 2025 and 2024, there
were no Class
“B” common voting shares or preferred shares outstanding.
2025 Annual Report
77
a) Issued and outstanding – Common Shares
Number | Amount | |
(thousands) | ($ 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 |
Basic and Diluted net loss per share is calculated as follows:
December 31, | December 31, | |
(thousands, except as noted) | 2025 | 2024 |
Net loss | $ (31,998) | $ (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) | 445,763 | 428,516 |
Basic and diluted net loss per share | $ (0.07) | $ (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, 23 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 | 29,870 | – |
Natural gas | 2,013 | – |
Total Brazil | $ 31,883 | $ – |
Total Company | $ 77,346 | $ 36,927 |
78
Questerre Energy Corporation
Other income consists of the following:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Rental income | $ 1,999 | $ – |
Fair value adjustment for contingent consideration | (1,509) | – |
Provision for contingencies | 1,143 | – |
Other | 778 | – |
Currency translation adjustment | – | – |
Balance, end of year | $ 2,412 | $ – |
December 31, | December 31, | |
($ thousands ) | 2025 | 2024 |
Finance Income | ||
Foreign exchange gain (loss) | $ 1,354 | $ – |
Income from financial investments | 563 | 1,145 |
Interest income from leases | 24 | – |
Other finance income | 1,318 | – |
$ 3,259 | $ 1,145 | |
Finance expenses | ||
Accretion expense | $ 5,507 | $ 580 |
Lease finance costs | 41 | 4 |
Interest expenses | 10,144 | – |
Foreign exchange loss | 5,806 | – |
IOF expenses | 86 | – |
Other | 98 | – |
$ 21,682 | $ 584 |
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Salaries, bonuses and other short-term benefits | $ 2,694 | $ 2,245 |
Share based compensation | 920 | 1,381 |
$ 3,614 | $ 3,626 |
2025 Annual Report
79
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 |
$ 1,875 |
Share based compensation |
1,164 |
1,480 |
$ 3,524 |
$ 3,355 |
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 $2.8 million at December 31, 2025. This amount does not include accelerated share-based
Changes in non-cash working capital are detailed below:
December 31, | December 31, | |
($ thousands) | 2025 | 2024 |
Accounts receivable | $ (143) | $ (226) |
Deposits and prepaid expenses | 5,953 | 16 |
Inventory | (722) | – |
Other long term assets | (5,282) | |
Accounts payable and accrued liabilities | (1,079) | 3,109 |
Current taxes payable | (21,935) | – |
Contingent liabilities | 10,827 | |
Other current liabilities | 4,551 | – |
Change in non-cash working capital | $ (7,830) | $ 2,899 |
Related to: | ||
Operating activities | $ (7,830) | $ 2,899 |
80
Questerre Energy Corporation
A summary of the Company’s net commitments at December 31, 2024, follows:
($ thousands) | 2026 | 2027 | 2028 |
Transportation and Processing | $ 2,219 | $ 1,094 | $ 0 |
Refinery maintenance contract | $ 15,897 | 1,199 | – |
Supply contracts | $ 6,149 | – | – |
The Company reorganized to spin out the Company’s Quebec assets through the exchange of the
shares. Pursuant to the reorganization, the Company’s existing Class A Common Shares (the
“Common Shares”) will be exchanged for a new class of Class A Common Shares (the “New
Common Shares”) and Series 2 Preferred Shares and the original Common Shares will be cancelled.
For each Common Share, the shareholders will receive one (1) New Common Share and one (1) Series
2 Preferred Share. The New Common Shares will continue to trade on the TSX and Oslo Bors.
Excluding the ownership of the Quebec assets, the New Common Shares will possess substantively