MERK:QGAS ESEF Annual Report
QUESTERRE EN PREF (MERK:QGAS)
ESEF Annual Report
2025-04-30
For: 2024-12-31
View Original
Added on
September 25, 2026
2024 ANNUAL REPORT
QUESTERRE ENERGY CORPORATION
CONTENTS
President’s Message
Page
1
Management’s Discussion & Analysis
Page
5
Consolidated Financial Statements
Page
31
Notes to the Consolidated
Financial Statements
Page
41
QUESTERRE ENERGY CORPORATION
is an energy technology and
innovation company. It is leveraging its expertise gained through early
exposure to low permeability reservoirs to acquire significant high-quality
resources. We believe we can successfully transition our energy portfolio.
With new clean technologies and innovation to responsibly produce and use
energy, we can sustain both human progress and our natural environment.
Questerre is a believer that the future success of the oil and gas industry
depends on a balance of economics, environment and society. We are
committed to being transparent and are respectful that the public must be
part of making the important choices for our energy future. Questerre’s
common shares are traded on the Toronto Stock Exchange and Oslo Stock
Exchange under the symbol QEC
.
2024 Annual Report
1
President’s Message
The world took a pivotal turn on January 20, 2025, with a new administration in the United States.
The energy shortage in Quebec and, more recently, the prospect of tariffs on energy to the United
States and their broader impacts revitalizes interest in our discovery. To us, they highlight the
importance of maintaining a pragmatic and flexible approach while protecting our shareholders’ legal
rights.
We participated in drilling programs at both Kakwa joint ventures last year as part of our strategy to
build our assets outside Quebec. The Kakwa North wells were tested in March. Over a one week
period, the wells produced over 2,000 boe per day net to Questerre
(1)
. While encouraging, these rates
are not necessarily indicative of long-term performance or ultimate recovery. The wells should be tied-
in and on production by the end of April. We are being more selective in our participation in future
wells, particularly at Kakwa Central, to ensure we maximize returns given current commodity prices.
On the technical front, Red Leaf made meaningful progress. They completed a pilot-scale lab test
producing over one barrel of oil and proving the rock mechanics inside the capsule. The engineering
for a small-scale project in Jordan was also finalized. However, the costs were higher than expected
and Red Leaf requires additional funding to conclude an agreement to advance this opportunity. Going
forward, we recently appointed a special committee of the Red Leaf board to negotiate this
agreement directly with the consortium in Jordan.
Highlights
•
Submitted expert witness report on economic losses for legal claim in Quebec
•
Participated in six (2.25 net) wells at Kakwa including three (0.75 net) wells on production and
three (1.50 net) wells awaiting completions at year-end
•
Average daily production of 1,756 boe per day, net cash from operating activities of $13.7
million and adjusted funds flow from operations of $14.6 million
•
Total proved and probable reserves declined by 10% to 23.8 MMboe with a before tax NPV-
10% of $195.3 million unchanged from last year
Quebec
The 2023 loss of the Volkswagen battery plant by Quebec in part due to insufficient power supply
was, perhaps, an early warning of the impending energy shortage in the province
(2)
.
In response, the Government introduced Bill 69 last year. Among other changes to the regulatory
regime, it included the requirement for integrated resource management plans for electricity and
natural gas every six years. The provincial utility also announced plans to invest a minimum of $100
billion over the next decade in hydro and wind power to increase capacity and meet future demand
(3)
.
While these initiatives support their 2050 goal of carbon neutrality, concerns about the costs to
industrial and residential consumers are growing. The Alliance for Quebec’s Energy Competitiveness
estimates under Bill 69 rates for large industrial users could increase by 60% over ten years
(4)
.
2
Questerre Energy Corporation
Normand Mousseau, director of the Trottier Energy Institute noted ‘the Government has capped
residential rate increases to 3% per annum. While that can work for a few years, it is untenable and
can only lead to disturbances when rates will have to catch up with reality
(5)
.
These concerns have been exacerbated by the impact of tariffs on competitiveness and have led to
the delay in implementing Bill 69 according to Quebec’s energy minister
(6)
. The Bill is still under
consideration by Quebec’s National Assembly. Though we expect final passage of the Bill by the end
of spring, new amendments and the political debate could delay its adoption.
We remain committed to a political and business solution because local gas production is the simplest
and most proximal solution to Quebec’s energy and environmental goals. It can help with energy
affordability, security, and reliability. One example of the benefit of local gas is supplying the 550MW
natural gas fired power plant at Becancour that currently provides peaking power during the winter.
We estimate that a total of six wells per year over eight years could supply the natural gas for this
power plant for ten years.
Perhaps more pressing is the threatened trade war with the United States. Local gas could replace
imports from the U.S., which currently supplies nearly half of Quebec’s natural gas
(7)
.
We are equally committed to protecting our shareholders’ rights and those of impacted stakeholders.
Our claim against the Government for the attempted revocation of our licenses without just
compensation is proceeding on the Court schedule. Questioning of the Government’s witnesses
should commence this summer. We anticipate a trial date could be set for next year.
Operating and Financial
Our production for the year averaged 1,756 boe per day, a 5% decrease from last year. These volumes
include the three (0.75 net) wells at Kakwa Central but exclude the three (1.5 net) wells at Kakwa
North that were completed during the first quarter of 2025.
These slightly lower production volumes along with slightly lower realized prices, offset by lower
royalty and operating expenses contributed to cash flow from operating activities of $13.7 million and
adjusted funds flow from operations of $14.6 million compared to $16.3 million and $15.9 million
respectively last year. Although we are advancing a pilot project with Red Leaf, we impaired the
carrying value of our Jordan assets as our exclusive rights are set to expire this May if we do not have
a new agreement before then. We are optimistic these rights could be extended if the pilot project
proceeds.
We financed our capital expenditures of $20.6 million through a combination of our net cash from
operating activities and cash on hand. At year-end, we held $31.8 million in cash and cash equivalents
and an unutilized credit facility of $16 million. Our committed capital expenditures for 2025 are
estimated at $14.4 million and largely reflect the completion and tie-in costs for the Kakwa North
wells. We intend to fund these costs through our existing resources.
Outlook
Our plans for projects to lower emissions including our carbon storage pilot in Quebec and, more
2024 Annual Report
3
broadly, our hub concept remain contingent on government funding. We recognize that these, and
the timeline for net-zero targets globally may be impacted by the recent changes enacted by the U.S.
Government. These include suspending funding under the
Inflation Reduction Act
and their
withdrawal from the Paris climate agreement.
As energy security and independence return as a priority, we hope the Government of Quebec
recognizes the role our discovery can play. As Canada seeks to diversify its energy markets, our
discovery can also provide the baseload supply of natural gas for possible LNG exports from Quebec.
In the interim, we are following the legal process for our claim.
Michael Binnion
President and Chief Executive Officer
1.
Consisting of 4,970 MMcf/d of natural gas and 1,298 bbls/d of condensate and estimated natural gas liquids.
2.
https://ici.radio-canada.ca/nouvelle/1963459/investissement-vw-canada-usine-batteries-saint-thomas-fitzgibbon-entrevue
3.
https://www.hydroquebec.com/data/a-propos/pdf/action-plan-2035.pdf
4.
https://www.theglobeandmail.com/business/article-industry-group-demands-quebec-reverse-course-on-planned-
electricity/
5.
https://www.theglobeandmail.com/business/commentary/article-hydro-quebecs-ambitious-plans-will-come-at-great-cost-
to-consumers-and/
6.
https://www.montrealgazette.com/news/provincial-news/article567140.htm
l
7.
https://www.canadianenergycentre.ca/big-vulnerability-how-ontario-and-quebec-became-reliant-on-u-s-oil-and-gas/
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
2024 Annual Report
5
Management’s Discussion and Analysis
This Management’s Discussion and Analysis (“MD&A”) was prepared as of March
26, 2025 and
should be read in conjunction with the audited consolidated financial statements of Questerre Energy
Corporation (“Questerre” or the “Company”) as at and for the
years ended December 31, 2024 and
2023. Additional information relating to Questerre, including Questerre’s Annual Information Form
for
the
year ended December 31, 2024, dated March 26, 2025 (“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”.
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;
•
working collaboratively to find a political and business solution with the Government of Quebec;
6
Questerre Energy Corporation
•
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;
•
general economic conditions;
2024 Annual Report
7
•
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)
2024
2023
Net cash from operating activities
$
13,673
$
16,317
Change in non
-cash working capital
886
(462)
Adjusted funds flow from operations
$
14,559
$
15,855
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.
2024 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,
2024
2023
2022
Financial ($ thousands, except as noted)
Petroleum and Natural Gas Revenue
36,927
41,701
51,751
Adjusted Funds Flow from Operations
(1)
14,559
15,855
26,738
Cash Flow from Operations
13,673
16,317
28,810
Basic and Diluted ($/share)
0.03
0.04
0.03
Net Income (Loss)
(7,329)
(23,708)
14,067
Basic and Diluted ($/share)
(0.02)
(0.06)
0.03
Capital Expenditures
20,640
10,148
11,591
Working Capital Surplus
(2)
23,091
29,866
24,007
Total Assets
170,723
172,346
196,486
Shareholders' Equity
138,629
143,667
166,128
Common Shares Outstanding (thousands)
428,516
428,516
428,516
Weighted average - basic (thousands)
428,516
428,516
428,516
Weighted average - diluted (thousands)
431,715
430,294
430,524
Operations (units as noted)
Average
Production
Crude Oil and Natural Gas Liquids (bbls/d)
1,021
1,056
1,020
Natural Gas (Mcf/d)
4,411
4,749
4,167
Total (boe/d)
1,756
1,848
1,715
Average Sales Price
(3)
Crude Oil and Natural Gas Liquids ($/bbl)
91.92
94.01
121.58
Natural Gas ($/Mcf)
1.65
3.02
6.10
Total ($/boe)
57.45
61.83
82.67
Netback ($/boe)
Petroleum and Natural Gas Revenue
(4)
57.45
61.83
82.67
Royalties Expense
(4)
(4.32)
(8.89)
(7.72)
Percentage
8%
14%
9%
Operating Expense
(4)
(23.58)
(23.84)
(24.47)
Operating Netback
29.55
29.10
50.51
General and Administrative Expense
(4)
(8.60)
(7.54)
(7.07)
Cash Netback
20.95
21.56
43.43
Wells Drilled
Gross
6.00
2.00
1.00
Net
2.25
1.35
0.25
(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, 2024 and 2023.
(3)
Refer to Note 15 in the Consolidated Financial Statements for the years ended December 31, 2024 and 2023.
(4)
Refer to Consolidated Statement of Comprehensive Loss and Comprehensive Loss for the years ended December 31, 2024 and
2023.
2024 Annual Report
11
Highlights
•
Submitted expert witness report on economic losses for legal claim in Quebec
•
Participated in six (2.25 net) wells at Kakwa including three (0.75 net) wells on production and
three (1.50 net) wells awaiting completions at year-end
•
Average daily production of 1,756 boe per day, net cash from operating activities of $13.7
million and adjusted funds flow from operations of $14.6 million
•
Total proved and probable reserves declined by 10% to 23.8 MMboe with a before tax NPV-
10% of $195.3 million unchanged from last year
2024 Activities
Western Canada
Kakwa, Alberta
Questerre participated in development drilling at both the Kakwa Central and Kakwa North joint
ventures during 2024.
Capital invested in Kakwa totalled $19.3 million for the year (2023: $3.6 million) with daily production
averaging 1,452 boe/d (2023: 1,536 boe/d) comprising of 4.4 MMcf/d of natural gas (2023: 4.7
MMcf/d) and 719 bbl/d of condensate and natural gas liquids (2023: 753 bbl/d). Total proved and
probable reserves as of December 31, 2024, were estimated at 22.5 MMBoe (2023: 25.0 MMBoe)
with a before tax NPV-10% of $180.6 million (2023: $178.6 million). The Company currently holds
40,320 (17,700 net) acres in the Kakwa area.
At Kakwa Central, the operator drilled, completed and tied-in three wells during 2024. Questerre holds
a 25% working interest in all three wells. The operator subsequently commenced a follow-up three
well program in the fall. Questerre elected to forego participation in this entire program due to the
proposed inter-well spacing that is expected to impact overall well recoveries.
At Kakwa North, the operator commenced a three well program in the fall of 2024. Questerre elected
to participate in the program and holds a 50% interest in all three wells. The wells were completed in
the first quarter of 2025. Subject to results, the Company anticipates a follow-up drilling program could
commence later this year.
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.
Antler, Saskatchewan
Consistent with prior years, activities at Antler focused on optimizing existing production and
expanding the pilot secondary recovery scheme to increase recovery of the oil in place.
$0.8 million was invested at Antler during the year to expand the pilot secondary recovery scheme.
(2023: $5.5 million). Daily production averaged 250 bbl/d (2023: 239 bbl/d). Total proved and probable
reserves as at December 31, 2024 were estimated at 1.2 MMBbls (2023: 1.3 MMBbls) with a before
12
Questerre Energy Corporation
tax NPV-10% of $21.9 million (2023: $23.3 million). The Company currently holds 12,560 net acres in
the area.
In 2025, the Company expects to continue its work to enhance existing production through workovers
and expanding the pilot secondary recovery scheme.
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”).
In February 2024, the Company submitted its application for a carbon storage pilot project to the
Quebec Ministry of Economy, Innovation and Energy 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. This included infrastructure
will facilitate the transition to a commercial project.
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
introduced in June 2024. The centerpiece of the proposed legislation is an integrated
resource management plan to promote energy development in Quebec. Among other things, it will
establish for electric power and natural gas markets, policy directions, objectives and targets regarding
supply, energy infrastructure and innovation.
Following the permission granted to the Attorney General of Quebec to appeal the Quebec Superior
Court (Civil Division) ruling in January 2024 suspending key provisions of Bill 21 pending a hearing on
the merits of the case, Questerre and other license holders filed a joint motion for review and
annulment of the judgement granting the application for the leave to appeal (the “Motion”). In October
2024, the Quebec Court of Appeal heard the Motion and the appeal by the Attorney General. The
Company is awaiting a decision from the Court of Appeal.
In October 2024, in connection with its claim against the Government of Quebec, the Company filed
an independent report on potential economic losses. Based on the scope and subject to the
restrictions, qualifications and major assumptions, under various scenarios, all of which are set out in
the report, the report estimates the economic losses if the licenses are successfully revoked under
three different scenarios with estimates ranging from $700 million to $4.8 billion. Please refer to our
press release of October 3, 2024. A copy of the report is available on the disclosure system in Norway
and on SEDAR+ in Canada.
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 is expected to take place this summer to be followed
by the establishment of a trial date for the hearing.
2024 Annual Report
13
Oil Shale Mining
The Company continued to assist its investee, Red Leaf Resources Inc. (“Red Leaf”), advance their
assets in the Unitah Basin and their proprietary technology that incorporates carbon capture to
produce oil from organic rich material.
Red Leaf is a private Utah based company whose principal assets include its proprietary technology
to produce oil from organic material, oil shale leases in the state of Utah and approximately US$10
million in unrestricted cash as of December 31, 2024. It also holds freehold surface rights as well as
carbon sequestration rights and a permit for a wax processing facility in the oil-producing Uintah Basin
in the state of Utah. The Company currently owns approximately 41% of the common share capital
of Red Leaf.
Red Leaf completed the engineering design for a small-scale demonstration project for a consortium
of local companies in Jordan. Red Leaf requires additional funding to conclude an agreement to
advance this opportunity. A special committee of the Red Leaf board has been appointed to negotiate
this agreement directly with the consortium. In early 2025, the company completed a pilot-scale lab
test producing over one barrel of oil and demonstrating the rock mechanics within the vessel. The
company continues to evaluate broader applications of their technology beyond the production of oil
from shale.
Questerre intends to utilize the Red Leaf technology for its project in the Kingdom of Jordan.
Discussions with the Government of Jordan for this small-scale commercial project and the related
negotiations for the concession agreement for the project remain ongoing. Questerre has been
advised that its exclusive rights to the project will expire in May 2025 subject to the execution of a
new agreement with the government prior thereto.
Drilling Activities
During 2024, the Company participated in six (2.25 net) wells at Kakwa including three (0.75 net) wells
at Kakwa Central and three (1.5 net) wells at Kakwa North. In the prior year, the Company drilled one
net operated well at Antler and participated in one (0.35 net) well at Pierson.
Production
2024
2023
Oil
and
Natural
Oil
and
Natural
Liquids
Gas
Total
Liquids
Gas
Total
(bbls/d)
(Mcf/d)
(boe/d)
(bbls/d)
(Mcf/d)
(boe/d)
Alberta
724
4,411
1,459
753
4,749
1,545
Saskatchewan and Manitoba
297
–
297
303
–
303
1,021
4,411
1,756
1,056
4,749
1,848
Note: Oil and liquids include light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.
For the year ended December 31, 2024, production volumes declined by 5% over the prior year and
averaged 1,756 boe per day.
14
Questerre Energy Corporation
Consistent with prior years, Kakwa accounts for over 80% of corporate volumes. Natural declines
from this area were largely offset by three (0.75 net) new wells at Kakwa Central that were completed
and tied-in during the third quarter. While Kakwa North accounted for only 30% of corporate volumes
in 2024, it is anticipated the volumes will increase in 2025 following the tie in of three (1.5 net) wells
that were completed in March 2025.
The product mix at Kakwa is equally split between natural gas and liquids that include condensate.
Aggregated with the light oil production from Saskatchewan and Manitoba, the Company’s liquids
weighting is close to 60%, unchanged from prior years. Production volumes from these areas
remained largely flat with well workovers mitigating the impact of natural declines.
With no additional wells currently planned for the remainder of 2025, the Company’s production
volumes should decline over the second half of the year. Subject to the timing of a possible drilling
program at Kakwa North this fall, the Company could see incremental volumes added in the second
quarter of 2026.
2024 Financial Results
Petroleum and Natural Gas Revenue
2024
2023
Oil
and
Natural
Oil
and
Natural
($ thousands)
Liquids
Gas
Total
Liquids
Gas
Total
Alberta
$
23,820
$
2,736
$
26,556
$
25,418
$
5,486
$
30,904
Saskatchewan and Manitoba
10,371
–
10,371
10,797
–
10,797
$
34,191
$
2,736
$
36,927
$
36,215
$
5,486
$
41,701
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 declined by 12% over the prior year with just over 40% of the
decline due to the lower production volumes and the remainder due to lower commodity prices.
Pricing
2024
2023
Benchmark prices:
Natural Gas - AECO 5A, daily spot ($/GJ)
1.38
2.64
Crude Oil - Canadian Light Sweet Blend ($/bbl)
97.54
100.39
Realized prices:
Natural Gas ($/Mcf)
1.65
3.02
Crude Oil and Natural Gas Liquids ($/bbl)
91.92
94.01
Note: Oil and liquids include light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.
Crude oil prices declined by under 3% over the prior year. The benchmark West Texas Intermediate
averaged US$75.72 per barrel compared to US$77.62 per barrel last year.
2024 Annual Report
15
Prices were supported in the first half of the year by the extension of voluntary supply cuts by OPEC+
members of just over 2.2 million barrels per day and the risk of the Middle East conflict expanding
into a regional war. Later in the year, concerns arose about the strength of the demand recovery in
China and the risk of increasing supply from non-OPEC countries including the U.S., Canada and Brazil.
In 2025, prices will likely reflect the fallout from trade disputes involving the U.S., Canada, Mexico,
China and the European Union. In the first quarter, this was partly offset by the weakening in the
Canadian dollar relative to the US dollar.
The startup of the TMX pipeline expansion in May 2024 helped diversify market access for Canadian
crude and improved the differentials for heavier grades. The differential between WTI and Canadian
condensate prices increased to US$2.78 per barrel from US$1.03 per barrel last year, in part due to
the increase in liquids rich gas production for the startup of LNG Canada export facility.
For the year ended December 31, 2024, Questerre’s realized price for crude oil and natural gas liquids
averaged $91.92 per barrel (2023: $94.01 per barrel) compared to the benchmark Canadian Mixed
Sweet Blend that averaged $97.54 per barrel (2023: $100.39 per barrel).
Natural gas prices also declined in 2024. During the year the benchmark Henry Hub averaged US$2.19
per MMBtu compared to US$2.54 per MMBtu last year. Canadian natural gas prices declined more
materially with the benchmark AECO 5A averaging $1.38 per GJ compared to $2.64 per GJ last year.
A warmer than expected winter and persistent supply in the United States continued to outpace
demand including exports via LNG and pipelines to Mexico. In Canada the increased supply and
limited storage was compounded by the lack of LNG export facilities, substantially increasing the
differential between the Henry Hub and AECO prices. While the startup of LNG Canada in mid-2025
is expected to help strengthen prices, additional export facilities are likely needed to further increase
demand.
Including the higher heat content gas from Kakwa, the Company’s realized natural gas prices averaged
$1.65 per Mcf (2023: $3.02 per Mcf).
Royalties
($ thousands)
2024
2023
Alberta
$
1,989
$
5,081
Saskatchewan and Manitoba
787
914
$
2,776
$
5,995
% of Revenue:
Alberta
7%
16%
Saskatchewan and Manitoba
8%
8%
Total Company
8%
14%
Royalties decreased substantially over the prior year due mainly to the credits received in Alberta for
processing the Crown’s share of production through Company facilities. As a percentage of revenue,
this decreased from 14% last year to 8% this year.
16
Questerre Energy Corporation
Excluding these credits, royalty expense on production in Alberta was $5.7 million (2023: $6.4 million),
representing a royalty rate of 22% (2023: 21%). Royalties on production in Saskatchewan and
Manitoba declined commensurate with the lower petroleum sales during the year.
Operating Costs
($ thousands)
2024
2023
Alberta
$
11,379
$
11,499
Saskatchewan and Manitoba
3,108
4,050
Quebec
671
533
$
15,158
$
16,082
$/boe:
Alberta
21.31
20.39
Saskatchewan and Manitoba
28.55
36.61
Total Company
$
23.58
$
23.84
Gross operating costs decreased by just over 5% reflecting lower costs in Saskatchewan and
Manitoba. On a unit of production basis, this remained relatively stable at approximately $24 per boe.
In Alberta, operating costs at Kakwa remained relatively flat over the prior year with similar production
volumes. In Saskatchewan, the decrease in operating costs is attributable to lower workover costs
compared to last year. Operating costs in Quebec reflect the costs associated with maintaining the
Company’s assets in the province and increased nominally due to consulting expense and rentals.
General and Administrative Expenses
($ thousands)
2024
2023
General and
administrative expenses, gross
$
5,886
$
5,356
Capitalized expenses and overhead recoveries
(356)
(270)
General and administrative expenses, net
$
5,530
$
5,086
Gross General & Administrative expenses (“G&A”) increased by 10% to $5.9 million from $5.4 million
last year. Higher expenses were incurred in several categories, including legal fees, consulting and
government and public relations related to the Company’s project in Quebec and salaries and
directors’ fees. Capitalized expenses are overhead costs associated with the Company’s projects in
Alberta and Jordan.
Depletion, Depreciation, Impairment, Accretion and Lease Expiries
For the year ended December 31, 2024, the Company recorded depletion, depreciation, and accretion
expense of $12.5 million (2023: $12.6 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.
2024 Annual Report
17
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 2023, based on a review of indicators of impairment conducted, the Company’s Western Canada
CGUs were tested in accordance with the Company’s accounting policy. The recoverable amount of
the CGUs was estimated based on the higher of the FVLCD and value in use (“VIU”) using a
discounted cash flow model. Due to a decrease in future gas prices, an increase in the future operating
costs reducing the value of the reserves and a 11% reduction in reserves, the Company recorded an
impairment expense in 2023 of $23.7 million. Of this amount, the Antler CGU recorded an impairment
expense of $5.3 million based on a FVLCD assessment and the Kakwa CGU recorded an impairment
expense of $18.4 million based on a VIU assessment. No impairments were recorded for the
Company’s other CGUs.
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
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 $1.1 million (2023: $1.4 million) net of
$0.3 million (2023: $0.2 million) in expense that was capitalized during the year.
Equity Investment
Questerre holds approximately 41% of the equity capital of Red Leaf. The Company uses the equity
method of accounting for its ownership of Red Leaf. Under this method, the Company records its
proportionate share of Red Leaf’s net loss and any impairment or reversals of previously recorded
impairments are recognized through the income statement.
The Company recorded an expense of $0.5 million (2023: $1.2 million) related to its investment in
Red Leaf. For more information, please see Note 7 to the Financial Statements.
18
Questerre Energy Corporation
Interest and Other Income
The Company earned interest and other income of $1.1 million for the year ended December 31,
2024. The interest was earned on its cash and term deposits that totalled $31.8 million at year-end.
In the prior year, other income included $1.5 million of interest that was earned on its cash and term
deposits.
Other Comprehensive Income (Loss)
In 2024, the Company recorded other comprehensive income of $0.9 million (2023: $0.4 million loss)
related to the change in foreign exchange rates. A gain of $0.4 million in the current year (2023: $0.1
million loss) was attributable to the change in the US dollar denominated investment in Red Leaf. The
Company also incurred a gain of $0.5 million (2023: $0.3 million loss) due to the appreciation in the
Jordanian dinar impacting its dinar-denominated assets in Jordan.
Net Loss and Total Comprehensive Loss
For the year ended December 31, 2024, the Company recorded a net loss of $7.3 million compared
to a net loss of $23.7 million in the prior year. Compared to last year, the loss in the current year is
due to lower petroleum and natural gas revenue offset by lower expenses including impairment.
Including other comprehensive income (loss), the Company reported a total comprehensive loss of
$6.4 million compared to a loss of $24.1 million last year.
Cash Flow from Operating Activities
The Company reported cash flow from operating activities of $13.7 million (2023: $16.3 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.
Cash Flow used in Investing Activities
Consistent with higher capital spending, the cash used in investing activities increased to $16.9 million
from $10.8 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)
2024
2023
Alberta
$
19,357
$
3,616
Saskatchewan, Manitoba and Jordan
1,283
6,532
Total
$
20,640
$
10,148
Notes: Capital expenditures exclude certain non-cash items such as share-based compensation and asset retirement obligations.
For the year ended December 31, 2024, the Company incurred capital expenditures of $20.6 million
2024 Annual Report
19
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.
For the year ended December 31, 2023, the Company incurred capital expenditures of $10.1 million
as follows:
•
In Alberta, $3.6 million to finish drilling, complete and tie-in one (0.25 net) well on the
Kakwa Central joint venture;
•
In Saskatchewan, $5.5 million was spent to drill, complete and tie-in one well and
recompletions for the pressure maintenance scheme; and
•
$1 million was spent to drill, complete and tie-in one (0.35 net) well in Manitoba and on other
assets.
Fourth Quarter 2024 Results
In the fourth quarter of 2024, petroleum and natural gas revenue declined slightly to $9.6 million from
$9.7 million last year. This was due to lower realized commodity prices that were almost completely
offset by a 5% increase in production volumes in the quarter.
Both crude oil and natural gas prices declined over the prior year and preceding quarter. This was
offset in part by the differential between WTI and Canadian condensate prices that was a premium in
the quarter compared to a discount last year.
Operating costs increased over the same period in the prior year and preceding quarter. In the fourth
quarter, operating costs totalled $3.9 million compared to $3.5 million last year. With costs relatively
flat in Saskatchewan and Manitoba, the change is mainly due to higher operating costs from the new
wells at Kakwa.
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.
20
Questerre Energy Corporation
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, 2024, and 2023, 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, 2024 was 3.92
(2023: 5.76) 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 2025 future development costs associated with proved reserves
in its independent reserves assessment as of December 31, 2024. It anticipates that, as a result,
reserves associated with wells drilled in 2025 will be transferred from the proved undeveloped to the
proved producing category.
For a detailed discussion of the risks and uncertainties associated with the Company’s business and
operations, see the Risk Management section of the MD&A and the AIF.
Share Capital
The Company is authorized to issue an unlimited number of Common Shares. The Company is also
authorized to issue an unlimited number of Class “B” Common voting shares and an unlimited
number of preferred shares, issuable in one or more series. At December 31, 2024, there were no
Class “B” common voting shares or preferred shares outstanding.
2024 Annual Report
21
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)
2025
2024
2023
Common Shares
428,516
428,516
428,516
Stock Options
38,920
38,295
38,140
Weighted average Common Shares
Basic
428,516
428,516
Diluted
431,715
430,294
A summary of the Company’s stock option activity during the
years ended December 31, 2024 and
2023 follows:
December
31,
2024
December
31,
2023
Weighted
Weighted
Number
of
Average
Number
of
Average
Options
Exercise
Options
Exercise
(thousands)
Price
(thousands)
Price
Outstanding, beginning of period
38,140
$
0.26
35,298
$
0.28
Granted
6,950
0.25
6,000
0.24
Forfeited
(620)
0.27
–
–
Expired
(6,175)
0.29
(3,158)
0.48
Outstanding, end of period
38,295
$
0.25
38,140
$
0.26
Exercisable, end of period
29,704
$
0.25
28,153
$
0.25
Commitments
A summary of the Company’s net commitments at December 31, 2024 follows:
($
thousands)
2025
2026
2027
Total
Transportation and Processing
$
2,515
$
1,566
$
545
$
4,626
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
22
Questerre Energy Corporation
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
6 to the audited consolidated financial
statements for the
year ended December 31, 2024.
Volatility in the oil and gas industry is a major risk facing the Company. Market events and conditions,
including global oil and natural gas supply and demand, actions taken by OPEC and non-OPEC
member countries’ decisions on production growth and spare capacity, including recent decisions by
Saudi Arabia and Russia, on production growth and spare capacity, market volatility and disruptions,
weakening global relationships, the war in Ukraine, conflict between the U.S. and Iran, isolationist and
punitive trade policies including potential trade disputes involving Canada, Mexico, China, the
European Union and the U.S., hostilities in the Middle East, Ukraine and Taiwan, U.S. shale
production, sovereign debt levels and political upheavals in various countries including growing anti-
fossil fuel sentiment, the implementation of new export tariffs or import taxes on Canadian energy
resources in the U.S. have caused significant volatility in commodity prices. Russia’s invasion of
Ukraine has led to sanctions being levied against Russia by the international community and may
result in additional sanctions or other international action, any of which may have a destabilizing effect
on commodity prices and global economies more broadly. These events and conditions have been a
factor in the decrease in the valuation of oil and gas companies and a decrease in confidence in the
oil and gas industry. These difficulties have been exacerbated in Canada by political and other actions
resulting in uncertainty surrounding regulatory, tax and royalty changes and other environmental
regulations.
In addition, the difficulties in obtaining the necessary approvals to build pipelines and other facilities
to provide better access to markets for the oil and gas industry in Western Canada has led to additional
uncertainty and reduced confidence in the oil and gas industry in Western Canada. Lower commodity
prices may also affect the volume and value of the Company’s reserves especially as certain reserves
become uneconomic. In addition, lower commodity prices have previously reduced the Company’s
cash flow leading to a reduction in funds available for capital expenditures. As a result, the Company
may not be able to replace its production with additional reserves and both the Company’s production
and reserves could be reduced on a year over year basis. Any decrease in value of the Company’s
reserves may reduce the borrowing base under its credit facilities, which, depending on the level of
the Company’s indebtedness, could result in the Company having to repay all or a portion of its
indebtedness. Given the current market conditions and the lack of confidence in the Canadian oil and
natural gas industry, the Company may have difficulty raising additional funds in the future to raise
funds on unfavourable and highly dilutive terms.
Another significant risk for Questerre as a junior exploration company is access to capital. The
Company attempts to secure both equity and debt financing on terms it believes are attractive in
2024 Annual Report
23
current markets. Management also endeavors to seek participants to farm-in on the development of
its projects on favorable terms. However, there can be no assurance that the Company will be able
to secure sufficient capital if required or that such capital will be available on terms satisfactory to the
Company.
As future capital expenditures will be financed out of adjusted funds flow from operations, borrowings
and possible future equity sales, the Company’s ability to do so is dependent on, among other factors,
the overall state of capital markets and investor appetite for investments in the energy industry, and
the Company’s securities. To the extent that external sources of capital become limited or unavailable,
or available but on onerous terms, the Company’s ability to make capital investments and maintain
existing assets may be impaired, and its assets, liabilities, business, financial condition and results of
operations may be materially and adversely affected. Based on current funds available and expected
adjusted funds flow from operations, the Company believes it has sufficient funds available to fund
its projected capital expenditures. However, if adjusted funds flow from operations is lower than
expected, or capital costs for these projects exceed current estimates, or if the Company incurs major
unanticipated expense related to development or maintenance of its existing properties, it may be
required to seek additional capital to maintain its capital expenditures at planned levels. Failure to
obtain any financing necessary for the Company’s capital expenditure plans may result in a delay in
development or production on the Company’s properties.
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.
24
Questerre Energy Corporation
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, 2024, for its expected credit losses
related to its accounts receivable.
Receivables from joint venture partners are typically collected within one to three
months after the
joint venture bill is issued. The Company mitigates this risk by obtaining pre-approval of significant
capital expenditures.
The Company has issued and may continue in the future to issue flow-through shares to investors.
The Company has historically used its best efforts to ensure that qualifying expenditures of Canadian
Exploration Expense ("CEE") are incurred in order to meet its flow-through obligations. In 2017, the
Federal Government amended the law regarding what expenses constitute CEE. Generally, oil and
gas drilling expenses are now Canadian Development Expense rather than CEE. In the event that the
Company has CEE expenditures reclassified under audit by the Canada Revenue Agency or fails to
incur expenditures required under a flow-through share agreement, the Company may be required to
liquidate certain of its assets in order to meet the indemnity obligations under flow-through share
subscription agreements.
Exploration and development drilling risks are managed through the use of geological and geophysical
interpretation technology, employing technical professionals and working in areas where those
individuals have experience. For its non-operated properties, the Company strives to develop a good
working relationship with the operator and monitors the operational activity on the property. The
Company also carries appropriate insurance coverage for risks associated with its operations.
The Company may use financial instruments to reduce corporate risk in certain situations. Questerre’s
hedging policy is up to a maximum of 40% of total production at management’s discretion.
As at December 31, 2024, the Company had no outstanding commodity risk management contract in
place.
2024 Annual Report
25
Environmental Regulation and Risk
The oil and natural gas industry is currently subject to environmental regulations pursuant to provincial
and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases
of emissions and regulation on the storage and transportation of various substances produced or
utilized in association with certain oil and natural gas industry operations, which can affect the location
and operation of wells and facilities, and the extent to which exploration and development is
permitted. In addition, legislation requires that well and facility sites are abandoned and reclaimed to
the satisfaction of provincial authorities. As well, applicable environmental laws may impose
remediation obligations with respect to property designated as a contaminated site upon certain
responsible persons, which include persons responsible for the substance causing the contamination,
persons who caused the release of the substance and any past or present owner, tenant or other
person in possession of the site. Compliance with such legislation can require significant
expenditures, and a breach of such legislation may result in the suspension or revocation of necessary
licenses and authorizations, civil liability for pollution damage, the imposition of fines and penalties or
the issuance of clean-up orders. The Company mitigates the potential financial exposure of
environmental risks by complying with the existing regulations and maintaining adequate insurance.
For more information, please refer to the “Risk Factors” and “Industry Conditions” sections of the
AIF.
Climate change policy is evolving at regional, national and international levels, and political and
economic events may significantly affect the scope and timing of climate change measures that are
ultimately put in place. The federal and certain provincial governments have implemented legislation
aimed at incentivizing the use of alternative fuels and in turn reducing carbon emissions. The taxes
placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas
products and at the same time, increasing the Company’s operating expenses, each of which may
have a material adverse effect on the Company’s profitability and financial condition. Further, the
imposition of carbon taxes puts the Company at a disadvantage with the Company’s counterparts
who operate in jurisdictions where there are less costly carbon regulations.
Interest Rate Risk
Interest rate risk is the risk that changes in the applicable interest rates for its credit facilities will
impact the Company’s interest expense. At December 31, 2024, and 2023 the Company had
effectively no amounts drawn down on its credit facilities with an effective rate of 7.74% (2023:
7.95%).
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.
26
Questerre Energy Corporation
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.
2024 Annual Report
27
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.
28
Questerre Energy Corporation
Investment in Red Leaf
Questerre has investments in certain private companies, including Red Leaf, which it classifies as an
equity investment and assesses for indicators of impairment at each period end. The primary risk
related to the investment in Red Leaf is the decline in the net current assets of the company without
a sufficient advancement in the engineering for their proprietary technology or their refinery project.
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, 2024.
•
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, 2024, 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, 2024, 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.
2024 Annual Report
29
Quarterly Financial Information
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.
December
31,
September
30,
June
30,
March
31,
($ thousands, except as noted)
2023
2023
2023
2023
Production (boe/d)
1,794
1,830
1,978
1,790
Average Realized Price ($/boe)
59.04
63.71
59.46
65.38
Petroleum and Natural Gas Revenue
9,743
10,725
10,702
10,531
Adjusted Funds Flow from Operations
(1)
3,209
3,034
5,335
4,277
Cash Flow from
Operations
5,154
2,382
4,133
4,648
Net Profit (Loss)
(26,003)
(337)
1,692
946
Basic and Diluted ($/share)
(0.06)
–
–
–
Capital Expenditures, net of acquisitions and
dispositions
3,588
845
2,469
3,246
Working
Capital Surplus
29,866
30,191
28,013
25,085
Total Assets
172,346
197,716
201,213
199,264
Shareholders' Equity
143,667
169,636
169,444
167,371
Weighted Average Common Shares Outstanding
Basic (thousands)
428,516
428,516
428,516
428,516
Diluted (thousands)
428,516
428,516
431,100
431,064
(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.
30
Questerre Energy Corporation
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.
2024 Annual Report
31
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
32
Questerre Energy Corporation
Independent Auditor’s Report
To the Shareholders of Questerre Energy Corporation
Opinion
We have audited the consolidated financial statements of Questerre Energy Corporation (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.
2024 Annual Report
33
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 di
scount 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
34
Questerre Energy Corporation
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
2024 Annual Report
35
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.
36
Questerre Energy Corporation
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
2024 Annual Report
37
Consolidated Balance Sheets
December
31,
December
31,
($
thousands)
Note
2024
2023
Assets
Current Assets
Cash and cash equivalents
5
$
$
Accounts receivable
6
Deposits and prepaid expenses
Right
-of-use assets
19
Investments
7
Property, plant and equipment
8
Exploration and evaluation assets
9
$
$
Liabilities
Current Liabilities
Accounts payable and accrued liabilities
$
$
Lease liabilities
19
Current portion of asset retirement obligation
12
Credit Facilities
6,13
Lease liabilities
19
Asset retirement obligation
12
Shareholders' Equity
Share capital
14
Contributed surplus
Accumulated other comprehensive income (loss)
(20 )
Deficit
(321,428 )
(314,099 )
$
$
Commitments (note 20)
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
38
Questerre Energy Corporation
Consolidated Statements of Net Loss and Comprehensive Loss
For
the
year ended December
31,
($
thousands,
except
per
share
amounts
)
Note
2024
2023
Revenue
Petroleum and natural gas revenue
15
$
$
Royalties
(2,776 )
(5,995 )
Petroleum and natural gas revenue, net of royalties
Expenses
Direct operating
General and administrative
Depletion, depreciation and accretion
8,12,19
Impairment
8,9
Loss on equity investment
7
Lease expiries
9
Share based compensation
11
Interest and other income
(1,145 )
(1,572 )
Loss before taxes
(7,329 )
(23,708 )
Deferred tax (recovery) expense
10
Net loss
(7,329 )
(23,708 )
Other Comprehensive Income (Loss), Net of Tax
Items that may be
reclassified subsequently to profit or loss:
Foreign currency translation adjustment
(267 )
Income (loss) on foreign exchange on investments
7
(93 )
(360 )
Total Comprehensive Loss
$
(6,413 )
$
(24,068 )
Net Loss per Share
Basic and diluted
14
$
(0.02
$
(0.06
The notes are an integral part of these consolidated financial statements.
2024 Annual Report
39
Consolidated Statements of Changes in Equity
For
the
year ended December
31,
($
thousands)
2024
2023
Share Capital
Balance, beginning and end of year
$
$
Contributed Surplus
Balance, beginning of year
Share based compensation
Balance, end of year
Accumulated Other Comprehensive Income (Loss)
Balance, beginning of year
(20 )
Other comprehensive income (loss)
(360 )
Balance, end of year
(20 )
Deficit
Balance, beginning of year
(314,099 )
(290,391 )
Net loss
(7,329 )
(23,708 )
Balance, end of year
(321,428 )
(314,099 )
Total Shareholders' Equity
$
$
The notes are an integral part of these consolidated financial statements.
40
Questerre Energy Corporation
Consolidated Statements of Cash Flows
For
the
years
ended
December
31,
($
thousands)
Note
2024
2023
Operating Activities
Net loss
$
(7,329 )
$
(23,708 )
Adjustments for:
Depletion, depreciation and accretion
8,12,19
Impairment
8,9
Lease expiries
9
Loss on equity investment
7
Share based compensation
11
Deferred tax (recovery) expense
10
Abandonment expenditures
12
(49 )
(255 )
Change in non
-cash working capital
18
(886 )
Net cash from
operating activities
Investing Activities
Property, plant and equipment expenditures
8
(4,046 )
(4,650 )
Exploration and evaluation expenditures
9
(16,594 )
(5,498 )
Change in non
-cash working capital
18
(666 )
Net cash used in investing activities
(16,855 )
(10,814 )
Financing Activities
Principal portion of lease payments
19
(65 )
(58 )
Repayment of credit facilities
13
Net cash used in financing
activities
(65 )
(55 )
Change in cash and cash equivalents
(3,247 )
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
.
2024 Annual Report
41
Notes to the Consolidated Financial Statements
For the years ended December 31, 2024, and 2023
innovation company actively engaged in the acquisition, exploration and development of oil and gas
consolidated financial statements of the Company as at and for the
years ended December 31, 2024,
and 2023 comprise the Company and its wholly-owned subsidiaries in those periods owned. The
Company wholly-owns Questerre Energy Corporation/Jordan, which holds interests in the oil shale
Questerre is incorporated under the laws of the Province of Alberta and is domiciled in Canada
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:
•
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
segments. Includes exploration activities in the Kingdom of Jordan and an investment in Red
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.
42
Questerre Energy Corporation
Western | Corporate | |||
($ thousands ) | Canada | Quebec | & other | Consolidated |
Assets by operating segment | ||||
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 |
Exploration and Evaluation | $ 5,366 | $ – | $ 6,921 | $ 12,287 |
Property, Plant & Equipment | 115,935 | – | – | 115,935 |
Other | 4,435 | 7,658 | 32,031 | 44,124 |
Total Assets, December 31, 2023 | $ 125,736 | $ 7,658 | $ 38,952 | $ 172,346 |
Results by operating segment | ||||
Revenues | $ 34,151 | $ – | $ – | $ 34,151 |
Expenses | (26,972) | (671) | (13,363) | (41,006) |
Other income | – | – | (474) | (474) |
Total Loss, December 31, 2024 | $ 7,179 | $ (671) | $ (13,837) | $ (7,329) |
Revenues | $ 35,706 | $ – | $ – | $ 35,706 |
Expenses | (52,768) | (533) | (4,881) | (58,182) |
Other income | – | – | (1,232) | (1,232) |
Total Loss, December 31, 2023 | $ (17,062) | $ (533) | $ (6,113) | $ (23,708) |
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
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 foreign exchange recorded through
other comprehensive income or loss as disclosed in Note
functional currency. The Company has a wholly-owned subsidiary with a functional currency of the
2024 Annual Report
43
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 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.
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
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 depletion.
44
Questerre Energy Corporation
Refer to Note
8
& 9 for carrying amounts of property, plant and equipment, exploration and evaluation
assets.
Exploration and evaluation assets
The application of the Company's accounting policy for exploration and evaluation assets (“E&E”)
requires judgement in determining whether it is likely that future economic benefit exists when
activities have not reached a stage where technical feasibility and commercial viability can be
reasonably determined. In addition, Management uses judgement to determine when E&E assets are
reclassified to PP&E assets.
Exploration and evaluation assets are subject to ongoing management review to confirm the
continued intent to establish the technical feasibility and commercial viability of the assets. In making
this determination, various factors are considered such as drilling results, future capital and operating
expenditures, including judgement over the amount of economically recoverable resources, and
whether the appropriate government, regulatory, or internal approvals are likely to be received.
Cash generating units (“CGU”)
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.
Refer to Note
8 for carrying amounts of property, plant and equipment.
Impairment of property, plant and equipment, exploration and evaluation assets
The Company assesses its oil and 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.
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
2024 Annual Report
45
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
8 and 9.
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.
Refer to Note
12 for the carrying amounts related to the asset retirement obligation.
Share based compensation
The Company has a stock option plan enabling employees, officers and directors to receive Class
“A”
Common voting shares (“Common Shares”) or cash at exercise prices equal to the market price or
above on the date the option is granted. The Company has the right and full discretion to settle any
exercised options by issuing shares and accordingly uses the equity settled method of accounting.
Under the equity settled method, compensation costs attributable to stock options granted to
employees, officers or directors are measured at fair value using the Black-Scholes option pricing
model. The assumptions used in the calculation are the volatility of the stock price, risk-free rates of
return and the expected lives of the options. A forfeiture rate is estimated on the grant date and is
adjusted to reflect the actual number of options that vest. Changes to assumptions may have a
material impact on the amounts presented.
For further detail refer to Note
11.
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.
Refer to Note
10.
46
Questerre Energy Corporation
Investment in Red Leaf
For the purpose of testing impairment, the Company measures the fair market value of Red Leaf by
valuation techniques such as a net liquidation approach. Judgment is required in measuring the fair
value of the Company’s investment in Red Leaf, which may result in material adjustments to its
related carrying value. Refer to Note
7 for the carrying amounts related to the Company’s investment
The accounting policies set out below have been applied consistently to all periods presented in these
consolidated financial statements.
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
Transactions eliminated on consolidation
Intercompany balances and transactions, and any unrealized income and expenses arising from
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.
2024 Annual Report
47
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
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
c) Investments
Questerre holds investments in certain private companies including its investment in Red Leaf.
The Company uses 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 making process of
Red Leaf through its current Board representation.
Common Shares are classified as equity. Incremental costs directly attributable to the issue of
Recognition and measurement
Costs incurred prior to acquiring the legal rights to explore an area are recognized as exploration and
evaluation expense in profit or loss.
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 exploration and evaluation assets. The
costs are accumulated in cost centres by exploration area pending determination of technical
feasibility and commercial viability. Gains and losses on exploration and evaluation assets are
recognized on disposal through the income statement.
48
Questerre Energy Corporation
At each reporting period, exploration and evaluation assets are assessed for impairment to determine
if (i)
sufficient data exists to determine technical feasibility and commercial viability, or (ii)
facts and
circumstances suggest that the carrying amount exceeds the recoverable amount.
The technical feasibility and commercial viability of extracting a mineral resource is considered to be
determinable based on several factors including the assignment of reserves. A review of each
exploration license or field is carried out, at each reporting date, to ascertain whether technical
feasibility and commercial viability has been achieved. Upon determination of technical feasibility and
commercial viability, intangible exploration and evaluation assets attributable to those reserves are
first tested for impairment and then reclassified from exploration and evaluation assets to property,
plant and equipment.
Every reporting period, the Company evaluates individually significant exploration and evaluation wells
for impairment, if there are specific impairment indicators evident at the well level. If technical
feasibility and commercial viability of the well is not established, the well costs are written off. For
insignificant wells, overall exploration and evaluation well indicators are evaluated. If there are
Items of property, plant and equipment, which include oil and gas development and production assets,
are measured at cost less accumulated depletion and depreciation and accumulated impairment
losses. Cost includes all costs required to acquire developed or producing oil and gas properties and
to develop oil and gas properties. Development and production assets are grouped into CGUs for
impairment testing.
Gains and losses on disposal of an item of property, plant and equipment, 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
Other property, plant and equipment
Expenditures related to workovers or betterments that improve the productive capacity or extend the
life of an asset are capitalized. The carrying amount of any replaced or sold component is
derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized
in profit or loss as incurred.
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.
2024 Annual Report
49
For other assets, depreciation is recognized in profit or loss on a straight-line basis over the respective
useful lives.
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.
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
50
Questerre Energy Corporation
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, which include crude oil, natural
gas, condensate and natural gas liquids (“NGLs”). Questerre also generates revenue from royalties
on production from leases where it owns a working interest. Revenue associated with the sale of
commodities is recognized when control is transferred from Questerre to its customers. Questerre’s
commodity sale contracts represent a series of distinct transactions. 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;
2024 Annual Report
51
•
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 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. Payment terms for Questerre’s commodity sales contracts are on the 25
th
of the month
following 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
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
52
Questerre Energy Corporation
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
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
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
2024 Annual Report
53
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
Future Accounting Pronouncements
An amendment to IAS 1
Presentation of Financial Statements
to clarify the requirements for the
presentation of liabilities as current or non-current on the consolidated balance sheet was adopted
effective January 1, 2024. IFRS 18 Presentation and Disclosure in Financial Statements was finalized
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Bank balances | $ 10,463 | $ 10,283 |
Short -term bank deposits | 21,328 | 24,755 |
$ 31,791 | $ 35,038 |
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, 2024, included cash and cash equivalents,
accounts receivable, deposits, investments, credit facilities and accounts payable and accrued
54
Questerre Energy Corporation
liabilities. As at December 31, 2024, 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.
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.
2024 Annual Report
55
The Company’s accounts receivables are aged as follows:
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Current | $ 3,174 | $ 2,939 |
31 - 60 days | 3 | – |
61 - 90 days | 1 | 46 |
>90 days | 64 | 31 |
$ 3,242 | $ 3,016 |
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
and short-term capital resources. Occasionally, to the extent possible, the Company will use derivative
instruments to manage cash flow in the event of commodity price declines.
The Company’s financial obligations 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.
56
Questerre Energy Corporation
The timing of cash outflows relating to financial liabilities as at December 31, 2024, and 2023 are as
follows:
Less than | Remaining | ||
($ thousands) | one year | years | Total |
Trade and other liabilities | $ 12,496 | $ – | $ 12,496 |
Credit facilities | 49 | – | 49 |
Lease liabilities | 56 | 83 | 139 |
Current portion of asset retirement obligation | 799 | – | 799 |
December 31, 2024 | $ 13,400 | $ 83 | $ 13,483 |
Less than | Remaining | ||
($ thousands) | one year | years | Total |
Trade and other liabilities | $ 9,387 | $ – | $ 9,387 |
Credit facilities | 36 | – | 36 |
Lease liabilities | 58 | 134 | 192 |
Current portion of asset retirement obligation | 184 | – | 184 |
December 31, 2023 | $ 9,665 | $ 134 | $ 9,799 |
Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange
rates and interest rates will affect the Company’s profit or loss or the value of the financial
instruments. The objective of the Company is to mitigate exposure to these risks while maximizing
returns to the Company.
Commodity price risk
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of
changes in commodity prices. 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, 2024, the Company had no outstanding commodity risk management contracts.
Currency risk
underlying market prices for these commodities are impacted by the exchange rate between Canada
and the United States. The Company also incurs expenditures in its Jordanian subsidiary that are
denominated in Jordanian Dinar and United States dollars. As at December 31, 2024, the Company
2024 Annual Report
57
Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market
interest rates. At December 31, 2024, and 2023, the Company had credit facilities outstanding of
The Company believes with its expected positive cash flow from operations and existing credit
facilities in the near future it will be able to meet its foreseeable capital obligations in the normal
course of operations. On an ongoing basis, the Company reviews its capital expenditures to ensure
that cash flow from operations or access to credit facilities are available to fund these capital
expenditures. To execute its current business plan including incurring capital expenditures related to
the full participation in the current and future drilling programs it anticipates it will require access to
additional financial liquidity.
The volatility of commodity prices has a material impact on Questerre’s cash flow from operations.
Questerre 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 considers its capital structure to include shareholders’ equity, any outstanding amounts
under its credit facilities and cash flow from operations. 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. Questerre monitors its capital structure based
on the current and projected funds flow from operations.
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Credit facilities | $ 49 | $ 36 |
Cash flow from operating activities | 13,673 | 16,317 |
Shareholders' equity | 138,629 | 143,667 |
Red Leaf is a private Utah based oil shale and technology company whose principal assets are its
proprietary technology to recover oil from shale and its oil shale leases in the state of Utah. The
As at December 31, 2024, Questerre holds 132,292 common shares, representing approximately
41% of the common share capital of Red Leaf and 288 Series
A Preferred Shares of Red Leaf
representing approximately 16% of the issued and outstanding preferred share capital of Red Leaf on
a non-diluted basis.
58
Questerre Energy Corporation
This is based on several criteria including its current equity interest in Red Leaf and ability to participate
December 31, | December 31, | |
($ thousands ) | 2024 | 2023 |
Balance, beginning of year | $ 4,471 | $ 5,796 |
Loss on equity investment | (474) | (1,232) |
Gain (loss) on foreign exchange | 362 | (93) |
Balance, end of the year | $ 4,359 | $ 4,471 |
The assets, liabilities, and net loss of Red Leaf for the respective years were comprised as follows:
December 31, | December 31, | |
($ thousands ) (1) | 2024 | 2023 |
Cash and Cash Equivalents | $ 17,763 | $ 20,829 |
Other Current Assets | 585 | 281 |
Current Liabilities | 190 | 124 |
Non -current liabilities | 3,043 | 2,797 |
Net Loss (2) | $ (2,546) | $ (4,549) |
(1)
Converted at an exchange rate of US$1=C$1.4389
(2)
Converted at an average exchange rate of US$1=C$1.3698
The issued and outstanding share capital of Red Leaf as of December 31, 2024, is comprised of the
following:
Issued and | Questerre | |
Outstanding | Ownership | |
Common Shares | 321,828 | 132,292 |
Preferred Shares | 1,795 | 288 |
The Series
A Preferred Shares carry voting rights and dividends accrue on a cumulative basis, whether
or not declared, at a rate of 8% per annum compounding annually. On the occurrence of a defined
liquidation event, including certain reorganizations, takeovers, the sale of all or substantially all the
assets of the company, and shareholder distributions, the Series
A Preferred shareholders are entitled
to an amount representing the original issue price plus any accrued dividends. As of December 31,
2024 Annual Report
59
($ thousands ) | Total |
Cost or deemed cost: | |
Balance, December 31, 2022 | $ 303,826 |
Additions including change to asset retirement | 4,188 |
Transfer from exploration and evaluation assets | 6,307 |
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 |
Accumulated
depletion, depreciation and impairment losses:
Balance, December 31, 2022 | $ 162,759 |
Depletion and depreciation | 11,890 |
Impairment | 23,737 |
Balance, December 31, 2023 | 198,386 |
Depletion and depreciation | 11,845 |
Balance, December 31, 2024 | $ 210,231 |
($ thousands ) | Total |
Net book value: | |
At December 31, 2023 | $ 115,935 |
At December 31, 2024 | $ 116,695 |
During the
years ended December 31, 2024, and 2023, the Company did not capitalize any
administrative overhead or share based compensation expense directly related to development
activities. Included in December 31, 2024, depletion calculation are future development costs of
$293.6 million (2023: $319.6 million).
As at December 31, 2024, the future prices used for impairment testing to determine cash flows from
oil and natural gas reserves were as follows:
Average | ||||||
Annual % | ||||||
Change | ||||||
2025 | 2026 | 2027 | 2028 | 2029 | Thereafter | |
WTI (US$/barrel) | 71.58 | 74.48 | 75.81 | 77.66 | 79.22 | 2.00 |
AECO ($/MMbtu) | 2.36 | 3.33 | 3.48 | 3.69 | 3.76 | 2.00 |
60
Questerre Energy Corporation
With respect to the Kakwa CGU an indicator of impairment was identified as a result of the reduction
in the volume of reserves due to technical revisions. The result of the impairment test based on a
FVLCD assessment of the Kakwa CGU was that no impairment or impairment reversals were
recorded. The estimates of FVLCD were determined using a discount rate of 15.8% (2023: 15%) and
forecasted after tax cash flows based on proved plus probable reserves, with escalating prices,
royalties, operating costs and future development costs. No indicators of impairment or impairment
reversals were identified for the other CGUs in 2024.
The table below illustrates the impact of changes to the discount rate and price forecasts:
Five Percent | ||
One Percent | Decrease in the | |
Increase in the | Forward Price | |
($ 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 $5.3 million based on a FVLCD assessment and the Kakwa CGU
Exploration and evaluation assets consist of the Company’s exploration projects which are pending
the determination of technical feasibility and commercial viability. Additions represent the Company’s
share of costs incurred on exploration and evaluation assets during the period.
December 31, | December 31, | |
($ thousands ) | 2024 | 2023 |
Balance, beginning of year | $ 12,287 | $ 14,227 |
Additions | 16,344 | 5,591 |
Transfers to property, plant and equipment | (8,605) | (6,307) |
Undeveloped lease impairments | – | (826) |
Undeveloped lease expiries and farmouts | – | (139) |
Foreign currency translation adjustment - Jordan | 943 | (259) |
Impairment of Jordan asset | (7,863) | – |
Balance, end of period | $ 13,106 | $ 12,287 |
During the
year ended December 31, 2024, the Company capitalized administrative overhead charges
of $0.4 million (2023: $0.4 million) and $0.3 million (2023: $0.2 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
2024 Annual Report
61
expense of $7.9 million representing its E&E assets in the country. No impairments were recorded
for the Company’s other CGUs in 2024. For the prior year, the Company recognized an E&E
The tax on the Company’s net loss before taxes differs from the amount that would arise using the
weighted average tax rate applicable to profits or losses of the consolidated entities as follows:
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Net loss before taxes | $ (7,329) | $ (23,708) |
Combined federal and provincial tax rate | 23.82% | 23.63% |
Computed 'expected' deferred tax expense (recovery) | (1,746) | (5,602) |
Increase in deferred taxes resulting from: | ||
Non-deductible differences and permanent items | 1,567 | 192 |
Change in deferred tax asset not recognized | 179 | 5,410 |
Deferred tax expense | $ - | $ - |
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 2024 and 23.63% in 2023.
The movement in deferred tax assets and liabilities during the
year, without taking into consideration
the valuation allowances, are as follows:
Petroleum and | Asset | ||||
natural gas | retirement | Non-capital | Capital | ||
($ thousands) | properties | Investments | obligation | losses | losses |
December 31, 2023 | $ 36,811 | $ 4,012 | $ 4,506 | $ 2,479 | $ 4,312 |
Change | 2,641 | 26 | 116 | (2,479) | 33 |
December 31, 2024 | $ 39,452 | $ 4,038 | $ 4,622 | $ – | $ 4,345 |
The amount and timing of reversals of temporary differences will be dependent upon, among other
things, the Company’s future operating results, and acquisitions and dispositions of assets and
liabilities.
62
Questerre Energy Corporation
The following temporary differences have not been recognized:
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Petroleum and natural gas properties | $ 165,651 | $ 155,748 |
Investments | 33,908 | 33,955 |
Asset retirement obligation and leases | 19,420 | 19,075 |
Non -capital losses | – | 10,488 |
Capital losses | 36,488 | 36,488 |
Total | $ 255,467 | $ 255,754 |
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 2024.
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 | |
$0.15 - $0.19 | 8,500 | 1.07 | $ 0.18 | 8,500 | 1.07 | $ 0.18 |
$0.20 - $0.25 | 18,850 | 2.51 | 0.23 | 11,171 | 1.62 | 0.22 |
$0.31 - $0.35 | 10,945 | 2.06 | 0.34 | 10,033 | 2.06 | 0.34 |
38,295 | 2.06 | $ 0.25 | 29,704 | 1.61 | $ 0.25 | |
2024 Annual Report
63
The following table summarizes information about stock options outstanding and exercisable at
December 31, 2024:
December 31, 2024 | December 31, 2023 | |||
Weighted | Weighted | |||
Number of | Average | Number of | Average | |
Options | Exercise | Options | Exercise | |
(thousands) | Price | (thousands) | Price | |
Outstanding, beginning of period | 38,140 | $ 0.26 | 35,298 | $ 0.28 |
Granted | 6,950 | 0.25 | 6,000 | 0.24 |
Forfeited | (620) | 0.27 | – | – |
Expired | (6,175) | 0.29 | (3,158) | 0.48 |
Outstanding, end of period | 38,295 | $ 0.25 | 38,140 | $ 0.26 |
Exercisable, end of period | 29,704 | $ 0.25 | 28,153 | $ 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 2024 and
2023:
December 31, | December 31, | |
2024 | 2023 | |
Weighted average fair value per award ($) | 0.19 | 0.18 |
Volatility (%) | 103.47 | 103.83 |
Forfeiture rate (%) | 8.85 | 9.35 |
Expected life (years) | 5.00 | 5.00 |
Risk free interest rate (%) | 3.54 | 3.18 |
This forfeiture rate estimate is adjusted to the actual forfeiture rate. Expected volatility and expected
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. The Company has
estimated the net present value of the asset retirement obligation to be $19.4 million as at December
31, 2024 (2023: $19.1 million) based on an undiscounted total future liability of $24.6 million (2023:
$24.3 million). These payments are expected to be made over the next 31
years. The average discount
factor, being the risk-free rate related to the liabilities, is 3.06% (2023: 3.39%). An inflation rate of 2%
(2023: 2%) over the varying lives of the assets is used to calculate the present value of the asset
retirement obligation.
64
Questerre Energy Corporation
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Balance, beginning of year | $ 19,064 | $ 19,441 |
Liabilities settled | (49) | (255) |
Revisions due to change in discount rates & estimates | (537) | (878) |
Liabilities incurred | 352 | 73 |
Accretion | 580 | 683 |
Balance, end of year | $ 19,410 | $ 19,064 |
Current portion | 799 | 184 |
Non -current portion | 18,611 | 18,880 |
Balance, end of period | $ 19,410 | $ 19,064 |
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 $16 million (“Facility A”). Facility
A can be used for general corporate purposes, ongoing operations, and capital expenditures within
Canada. Any borrowing under the credit facilities, with the exception of letters of credit, bears interest
at the bank’s prime interest rate and an applicable basis point margin based on the ratio of debt to
over all assets of the Company and a general assignment of books debts.
Under the terms of the credit facility, the Company has provided a covenant that it will maintain an
Adjusted Working Capital Ratio greater than 1.0. The ratio is defined as current assets (excluding
unrealized hedging gains and including undrawn Credit Facility A availability) to current liabilities
(excluding outstanding bank debt and unrealized hedging losses). The Adjusted Working Capital Ratio
at December 31, 2024, was 3.92 (2023: 5.76) and the covenant was met. At December 31, 2024, and
2023 effectively nil was drawn on Facility A with an effective average interest rate of 7.74% for 2024
(2023: 7.95%).
2024 Annual Report
65
The following table reconciles the movement in the credit facilities during the year.
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Credit Facilities, beginning of year | $ 36 | $ 33 |
Repayment from Credit Facilities | – | 3 |
Standby Fees | 13 | – |
Credit Facilities, end of year | $ 49 | $ 36 |
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 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, 2024 and 2023, there
were no Class
“B” common voting shares or preferred shares outstanding.
a) Issued and outstanding – Common Shares
Number | Amount | |
(thousands) | ($ thousands) | |
Balance, December 31, 2023 and December 31, 2024 | 428,516 | $ 429,878 |
Basic and Diluted net loss per share is calculated as follows:
December 31, | December 31, | |
(thousands, except as noted) | 2024 | 2023 |
Net loss | $ (7,329) | $ (23,708) |
Weighted average number of Common Shares beginning and | 428,516 | 428,516 |
| outstanding (basic and diluted) | ||
Basic and diluted net loss per share | $ (0.02) | $ (0.06) |
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, 2024, 23.7 million options
(December
31, 2023: 23.4 million) were excluded from the diluted weighted average number of
66
Questerre Energy Corporation
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Oil and liquids | $ 34,148 | $ 36,138 |
Natural gas | 2,699 | 5,438 |
Royalty revenue | 80 | 125 |
$ 36,927 | $ 41,701 |
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Salaries, bonuses and other short -term benefits | $ 2,518 | $ 2,245 |
Share based compensation | 1,205 | 1,381 |
$ 3,723 | $ 3,626 |
Key management includes directors and officers. The compensation paid or payable to key
management is as follows:
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Salaries, bonuses, director fees and other short -term benefits | $ 2,128 | $ 1,875 |
Share based compensation | 1,296 | 1,480 |
$ 3,424 | $ 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 $2.2 million at December 31, 2024. This amount does not include accelerated share-based
2024 Annual Report
67
Changes in non-cash working capital are detailed below:
December 31, | December 31, | |
($ thousands) | 2024 | 2023 |
Accounts receivable | $ (226) | $ 1,584 |
Deposits and prepaid expenses | 16 | (451) |
Accounts payable and accrued liabilities | 3,109 | (1,337) |
Change in non -cash working capital | $ 2,899 | $ (204) |
Related to: | ||
Operating activities | $ (886) | $ 462 |
Investing activities | 3,785 | (666) |
$ 2,899 | $ (204) |
Right-of-use assets
($ thousands ) | Real Estate | Other | Total |
Cost | |||
Balance, December 31, 2023 | $ 511 | $ 25 | $ 536 |
Additions | – | 8 | 8 |
Balance, December 31, 2024 | $ 511 | $ 33 | $ 544 |
Accumulated Depreciation | |||
Balance, December 31, 2023 | $ 331 | $ 25 | $ 356 |
Depreciation | 56 | 4 | 60 |
Balance, December 31, 2024 | $ 387 | $ 29 | $ 416 |
Carrying value | |||
Balance, December 31, 2023 $ | 180 $ | – | $ 180 |
Additions, net of depreciation | (56) | 4 | (52) |
Balance, December 31, 2024 | $ 124 | $ 4 | $ 128 |
68
Questerre Energy Corporation
b)
Lease liabilities
($ thousands ) | |
Balance, January 1, 2023 | $ 250 |
Interest expense | 6 |
Lease payments | (64) |
Balance, December 31, 2023 | $ 192 |
Additional leases acquired during period | 8 |
Interest expense | 4 |
Lease payments | – |
Balance, December 31, 2024 | $ 204 |
Current portion | 56 |
Long term portion | 83 |
Balance, December 31, 2024 | $ 139 |
Amounts related to lease liabilities recognized in profit or loss are as follows: | |
Interest expense on lease liabilities | $ 4 |
A summary of the Company’s net commitments at December 31, 2024, follows:
($ thousands) | 2025 | 2026 | 2027 | Total |
Transportation and Processing | $ 2,515 | $ 1,566 | $ 545 | $ 4,626 |
DIRECTORS
Michael Binnion
Mireille Fontaine
Hans Jacob Holden
Jauvonne Kitto
Dennis Sykora
Bjorn Inge Tonnessen
OFFICERS
Michael Binnion,
President and
Chief Executive Officer
John Brodylo,
VP Exploration
Jason D’Silva,
Chief Financial Officer
Rick Tityk,
VP Land
BANKERS
Canadian Western Bank
200, 606 Fourth Street SW
Calgary, Alberta T2P 1T1
LEGAL COUNSEL
Borden Ladner Gervais LLP
1900, 520 Third Avenue SW
Calgary, Alberta T2P 0R3
TRANSFER AGENT
Computershare Trust
Company of Canada
800, 324 Eighth Avenue SW
Calgary, Alberta T2P 2Z2
DNB Bank ASA
Dronning Eufemias gate 30
0191 Oslo, Norway
AUDITORS
Ernst and Young LLP
2200, 215 Second Street SW
Calgary, Alberta T2P 1M4
CORPORATE INFORMATION
INDEPENDENT
RESERVOIR ENGINEERS
McDaniel & Associates Consultants Ltd.
2000, 525 Eighth Avenue SW
Calgary, Alberta T2P 1G1
GLJ Ltd.
1920, 401 Ninth Avenue SW
Calgary, Alberta T2P 3C5
HEAD OFFICE
1650 AMEC Place
801 Sixth Avenue SW
Calgary, Alberta T2P 3W2
Telephone: (403) 777-1185
Facsimile: (403) 777-1578
Web: www.questerre.com
Email: [email protected]
STOCK INFORMATION
Toronto Stock Exchange
Oslo Stock Exchange
Symbol: QEC
QUESTERRE
ENERGY CORPORATION
1650 AMEC Place
801 Sixth Avenue SW
Calgary, Alberta T2P 3W2
Telephone: (403) 777-1185
Facsimile: (403) 777-1578
Web: www.questerre.com
Email: [email protected]