Questerre Energy Corporation

2023 Annual Report

President’s Message

We continued to invest in our conventional assets in Western Canada. This is consistent with our goal of

building a base for our business beyond our Utica discovery. At Antler, we drilled an oil well and expanded our

pilot pressure support program. We also participated in drilling at Kakwa Central. New wells at Kakwa North

could spud late this fall or early next winter when gas prices improve.

Two years ago, the Government of Quebec introduced Bill 21 to revoke our licences and effectively nationalize

our discovery. Since then, preserving our legal rights has been our top priority. A recent pre-trial ruling

concurred that the fundamental legal issues raised in our claim must be heard at trial. The Justice suspended

key elements of Bill 21 until the proceedings are complete. Our goal remains to work collaboratively with the

Government to find a political and business solution. We are hopeful that the impending electricity crisis in

Quebec provides an opportunity for dialogue on energy security.

As the process evolves in Quebec, we are applying the expertise developed here on zero-emissions hubs to our

other projects. Through our interest in Red Leaf, we helped design a similar hub concept in the producing

Uintah Basin in Utah where they hold the rights for carbon storage. They are assessing how their patented

technology, that incorporates carbon capture, can be applied to heat and power generation. Integrating carbon

capture in industrial processes is emerging as a more efficient carbon capture technique. In Canada, the

proposed Clean Electricity Regulations require that any new power generation from non-renewable sources

have abated emissions.

During the year, they also completed the engineering of a small-scale commercial project for their technology

to be built in the Kingdom of Jordan.

St. Lawrence Lowlands, Quebec

Signs of the electricity shortage in Quebec appeared as early as the fall of 2021 when the provincial utility’s

supply plan reported that the ‘era of surpluses is over’ and, it launched a tender to fill the gap expected in

2027. Two years later, it noted the need for more than 100 terawatt hours, or more than half its annual

generating capacity, to reach the province’s goal of carbon neutrality by 2050. While the Government’s solution

relies on additional hydroelectric dams and wind farms in the long term and energy conservation in the near

term, it is far from clear this will solve the energy shortage. We believe our Clean Gas project could be

instrumental in closing this deficit with greater security, lower global emissions and lower costs.

As the Government and other industries seek new solutions to reduce emissions and build the economy,

leaving our gas in the ground for the last decade is a lost opportunity on both fronts.

A 2010 study by the local gas distribution company, GazMetro, now known as Energir, estimated that, on a

business-as-usual basis, replacing imported gas with local gas would reduce emissions by 440,000 tonnes of

carbon dioxide equivalent annually. Using our Clean Gas, which reduces the emissions by 75% over a business

as usual approach, would have had an even larger impact.

A 2018 study for the Quebec Oil & Gas Association, estimated that between 2019 and 2024, our project would

have supported nearly 4,000 jobs, created over $350 million in GDP and increased government revenue by

Questerre Energy Corporation

$160 million annually. Over the next ten years, the report estimates these benefits grow to nearly 7,000 jobs,

$750 million in GDP and increase government revenue by $400 million annually. This one decision alone could

have made a dramatic improvement in climate goals and improved affordability for everyday Quebecers.

In conclusion, with 20/20 hindsight the moratorium on natural gas increased Canadian GHG emissions by over

5.7 megatonnes while reducing government revenue by over $2 billion.

As a first step towards demonstrating our zero-emissions concept, we responded to the Government’s calls for

carbon and hydrogen storage pilot projects under Bill 21. We recently submitted a comprehensive application

to assess the carbon storage potential in Quebec and test new technology to produce hydrogen and power

with zero-emissions. At an estimated cost of over $100 million, we are seeking Provincial and Federal

government funding to move this forward.

Red Leaf Resources

We are also helping Red Leaf design and seek government funding for a similar but smaller scale carbon storage

test in Utah. Proving up the sequestration potential of their lands where they hold the rights for storage will

be essential for the zero-emissions park. The concept is to provide, as a utility, the service of managing

emissions from any industrial tenants at the park as well as the permitted wax processing facility. This service

would include the pipelines and compression to either sequester these emissions underground or recycle the

carbon dioxide using innovative technologies.

Red Leaf is also assessing how their patented technology can produce heat and power for the park. Combusting

gaseous fuel with carbon dioxide produces a stream of pure carbon dioxide and water, dramatically reducing

the costs of capturing carbon dioxide. With limited takeaway capacity for produced natural gas in the basin,

this process could use this excess gas as fuel and improve the air quality in the basin by reducing emissions.

The wax processing facility is a key element of the industrial park. It is a large-scale project with a capital cost

around US$600 million. The lack of takeaway capacity for the highly waxy crude oil creates a market

opportunity for the facility. We continue to work with Red Leaf on the pre-requisites for funding this project

including securing supply contracts and off-take arrangements.

Although it has taken longer than we expected, Red Leaf recently completed the preliminary engineering for a

small-scale commercial project. Discussions are ongoing with a group of companies in the Kingdom of Jordan

to construct and operate the facility in country. We are reviewing the design with the goal of establishing a

project that can be operated at material scale on a continuous basis at a reasonable cost.

Operating & Financial

With a full year of production from our working interest at Kakwa North our production volumes increased by

just under 10% and offset the fewer wells that came on at Kakwa Central this year. Daily production averaged

1,848 boe per day compared to 1,714 boe per day last year.

A 25% drop in realized prices, including a 50% drop in natural gas prices contributed to adjusted funds flow

from operations of $15.9 million compared to $26.7 million last year. Under IFRS, the materially lower future

gas prices and a nominal reduction in our reserves resulted in an impairment in the book value of our assets of

2023 Annual Report

$23 million. This resulted in a loss of $23.7 million this year compared to net income of $14.1 million last year.

Net of capital spending of $10.1 million, we increased our cash position by just over $5 million during the year.

Our approved capital program for this year is nearly $12 million and largely represents the planned drilling at

Kakwa Central.

Outlook

We have built our working capital surplus to just over $30 million of unrestricted cash and have an undrawn

credit facility of $16 million. This should fund the Kakwa North development and provide additional liquidity

should market conditions change. In Quebec, the next major milestone is the completion of discoveries prior

to setting a date for the hearing on the merits of our case. Subject to the court schedule, this could be held

next spring.

We are also taking every opportunity to co-operate with the Government on a project to test carbon storage,

that, on any objective basis, is in our mutual interest. As we noted last year, these discussions do not have any

clear milestones or timelines, which makes it challenging for our shareholders to assess our progress.

Nevertheless, we are confident that this collaborative approach while protecting our rights is the best strategy

to see the value of our discovery.

Michael Binnion

President and Chief Executive Officer

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 8 billion to almost 10 billion people who

will expect a better standard of living. We believe providing the increased energy needed tomorrow, with lower

environmental impacts than today, is the challenge of our times. Transitioning our energy diet to lower

emissions is essential to meet this challenge and we believe the oil and gas industry has the biggest

improvements to make.

Our Clean Tech Energy project to deliver the world’s first zero emissions natural gas production is an example

of meeting this challenge. It will have a dramatic impact on the emissions from production in addition to other

environmental criteria. It will also contribute to reducing the emissions from consumption by providing a

cleaner burning alternative domestically and internationally through LNG exports. We are also looking at

hydrogen production combined with carbon capture to further reduce the emissions from consumption.

It requires a new way of thinking to become leaders on environmental issues.

Our industry runs most of today’s

energy systems. We have the experience, expertise, capital and technology to meet the world’s energy and

environmental challenges. Delivering on projects like our zero emissions natural gas project is just one example

of how our industry can be leaders on transitioning our global energy systems.

Questerre has also taken leadership in working with communities and First Nations for local benefits. We have

committed to share 3% of our profits with them. We have also engaged with local First Nations to include them

in our contracting and benefits program.

We unilaterally made the decision not to work in communities where the plurality of the community does not

want development. Our approach of consulting first and applying for permits second is consistent with this

approach.

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 produced. Questerre is an

entrepreneurial leader in making the seemingly impossible task of producing more with less impact, possible.

Our zero emissions Clean Tech Energy project is our contribution to meeting this challenge.

2023 Annual Report

Management’s Discussion and Analysis

This Management’s Discussion and Analysis (“MD&A”) was prepared as of March 21, 2024 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, 2023 and 2022. Additional

information relating to Questerre, including Questerre’s Annual Information Form for the year ended

December 31, 2023 dated March 21, 2024 (“AIF”), is available on SEDAR under Questerre’s profile at

www.sedar.com.

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;

•

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

Questerre Energy Corporation

•

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 implementation of the Company’s Clean Tech Energy project in Quebec;

•

the transfer of wells drilled in 2024 from the proved undeveloped to the proved producing category;

•

the outlook for heavier crude and demand for condensate as diluent as the TMX pipeline commences

service;

•

hedging policy;

•

liquidity and capital resources;

•

the Company’s assessment of a small-scale commercial 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;

•

Questerre’s reserves;

•

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;

•

joint venture partner willingness to participate in capital programs;

•

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:

•

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;

2023 Annual Report

•

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.

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

Questerre Energy Corporation

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)

2023

2022

Net cash from operating activities

16,317

28,810

Change in non

-cash working capital

(462)

(2,072)

Adjusted funds flow from operations

15,855

26,738

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.

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.

2023 Annual Report

Select Annual Information

As at/for the years ended December 31,

2023

2022

2021

Financial ($ thousands, except as noted)

Petroleum and Natural Gas Revenue

41,701

51,751

30,404

Adjusted Funds Flow from Operations

15,855

26,738

14,477

Basic and Diluted ($/share)

0.04

0.03

Net Income

(Loss)

(23,708)

14,067

(4,301)

Basic and Diluted ($/share)

(0.06)

0.03

(0.01)

Capital Expenditures

10,148

11,591

4,665

Working Capital Surplus

(1)

29,866

24,007

1,834

Total Non

-Current Financial Liabilities

134

191

1,975

Total Assets

172,346

196,486

184,264

Shareholders' Equity

143,667

166,128

148,961

Common Shares Outstanding (thousands)

428,516

Weighted average - basic (thousands)

428,516

428,034

Weighted average - diluted (thousands)

428,516

430,524

428,034

Operations (units as noted)

Average Production

Crude Oil and Natural Gas Liquids (bbls/d)

1,056

1,020

890

Natural Gas (Mcf/d)

4,749

4,167

3,538

Total (boe/d)

1,848

1,715

1,480

Average Sales Price

(2)

Crude Oil and Natural Gas Liquids ($/bbl)

94.01

121.58

84.81

Natural Gas ($/Mcf)

3.02

6.10

3.84

Total ($/boe)

61.83

82.67

56.34

Netback ($/boe)

Petroleum and Natural Gas Revenue

(3)

61.83

82.67

56.34

Royalties Expense

(3)

(8.89)

(7.72)

(3.46)

Percentage

14%

Operating Expense

(3)

(23.84)

(24.47)

(21.81)

Operating Netback

29.10

50.51

31.06

General and Administrative Expense

(3)

(7.54)

(7.07)

(4.46)

Cash Netback

21.56

43.43

26.59

Wells Drilled

Gross

2.00

1.00

3.00

Net

1.35

0.25

0.75

(1)

Refer to the Current Assets and Current Liabilities in the Balance Sheet for the years ended December 31, 2023 and 2022.

(2)

Refer to Note 15 in the Consolidated Financial Statements for the years ended December 31, 2023 and 2022.

(3)

Refer to Consolidated Statement of Comprehensive Loss and Comprehensive Loss for the years ended December 31, 2023 and 2022.

Questerre Energy Corporation

Highlights

•

Quebec Superior Court grants stay on key provisions of Bill 21

•

Questerre presents carbon storage pilot to Quebec Government

•

Average daily production of 1,848 boe per day with adjusted funds flow from operations of $15.9

million

•

Total proved and probable reserves assessed at 26.4 MMboe with a before tax NPV-10% value of $195

million declining 25% due to lower forecast natural gas prices and an 11% decrease in reserves

2023 Activities

Western Canada

Kakwa, Alberta

With ongoing drilling at Kakwa Central, production volumes increased over the prior year. Volumes also reflect

the conversion of the Company’s royalty interest in the farm-in wells at Kakwa North to a working interest in

the fourth quarter of 2022.

Capital investment in Kakwa totalled $3.6 million for the year (2022: $11 million) with daily production

averaging 1,536 boe/d (2022: 1,404 boe/d) comprising of 4.7 MMcf/d of natural gas (2022: 4.2 MMcf/d) and

753 bbl/d of condensate and natural gas liquids (2022: 720 bbl/d). Total proved and probable reserves as of

December 31, 2023, were estimated at 25.0 MMBoe (2022: 28.4 MMBoe) with a before tax NPV-10% of $178.6

million (2022: $247.2 million). The Company currently holds 40,320 (17,700 net) acres in the Kakwa area.

At Kakwa Central, the operator completed and tied-in two wells during 2023. Questerre holds a 25% interest

in one well and elected to forego participation in the second well. The operator has proposed to drill up to

three (0.75 net) wells in 2024. Questerre has participated in the first (0.25 net) well of this program and intends

to participate in the remaining two (0.5 net) wells.

No drilling activities were conducted on the Kakwa North acreage during the year. In the fourth quarter of

2022, Questerre converted its royalty interest in the four farm-in wells into a 50% working interest. The

operator is assessing three (1.5 net) wells that could spud in the fourth quarter of this year.

The Company plans to participate in the 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.

$5.5 million was invested at Antler during the year to drill and complete one 100% well and expand the

secondary recovery scheme (2022: $0.5 million). Daily production averaged 239 bbl/d (2022: 268 bbl/d). Total

proved and probable reserves as at December 31, 2023 were estimated at 1.3 MMBbls (2022: 1.2 MMBbls)

with a before tax NPV-10% of $23.3 million (2022: $25.2 million). The Company currently holds 11,316 net

acres in the area.

2023 Annual Report

In 2024, the Company expects to continue its work to enhance existing production through workovers and

expanding the pilot secondary recovery scheme.

St. Lawrence Lowlands, Quebec

The Company’s primary objective remains the implementation of its Clean Tech Energy project in Quebec

through a business and political solution. 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”)

During the year, the Company presented to the Quebec Ministry of Economy, Innovation and Energy (“MEIE”)

its plans for a carbon storage test on its lands. The prospective storage formation underlying its licenses was

identified by the Company after an assessment of its proprietary seismic and well data. This meeting follows

the request from the MEIE for proposals for pilot projects that would foster the energy transition and attain

targets in the fight against climate change pursuant to Bill 21.

In early 2024, the Company submitted a formal application for a pilot project. 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. The project also includes the test of new technology for zero-emissions

hydrogen and power production that will provide a source of carbon dioxide for the project.

A hearing was held in October 2023 on the application by the Company and other license holders to stay certain

provisions of Bill 21 for the duration of the judicial proceedings. Early in the new year, the Justice ruled that

the Company’s application met the key criteria for a stay and stayed some of these provisions. The Justice also

ruled that the judgement be enforced even if the Attorney General files an appeal, also known as ‘provisional

execution’. He noted that Questerre and the other plaintiffs run the risk of serious and irreparable harm in the

absence of this order for provisional execution. Subsequently, the Attorney General of Quebec has recently

filed an application to appeal this ruling.

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 judicial process is at the

discoveries stage. The next step is pre-trial examinations. Following the completion of pre-trial examinations,

a date will be set for the main hearing.

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 to produce oil from shale that incorporates carbon capture.

Red Leaf is a private Utah based company whose principal assets include its proprietary technology to produce

oil from shale, oil shale leases in the state of Utah and approximately US$12 million in unrestricted cash as of

December 31, 2023. 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.

Questerre Energy Corporation

During the year, the company completed a pre-FEED engineering study on the facility to validate the design

and capital costs. In advance of seeking funding for the project, the company is focused on securing off-take

agreements for the facility’s production, supply contracts with producers and engaging a qualified engineering

firm to manage the construction. Concurrently, the company is assessing the development of an industrial park

on its lands that would provide prospective tenants with both zero-emissions power and takeaway capacity for

any produced emissions utilizing its carbon storage rights.

Red Leaf has also been engineering the design of a small-scale commercial project for a group of local

companies in the Kingdom of Jordan. It is anticipated that these companies could provide both engineering

and fabrication services in-country as well as a potential off-take for the produced crude oil. Red Leaf has

recently been evaluating broader applications of their technology beyond the production of oil from shale.

The Company plans 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 continues to hold the exclusive exploration

rights to the project during the term of these negotiations.

Drilling Activities

During 2023, one net operated well was spud at Antler and one (0.35 net) well at Pierson compared to one

(0.25 net) well last year at Kakwa.

Production

2023

2022

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

753

4,749

1,545

720

4,167

1,415

Saskatchewan and Manitoba

303

–

303

300

–

300

1,056

4,749

1,848

1,020

4,167

1,715

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

With higher production volumes at Kakwa, daily production increased by under 10% for the year ended

December 31, 2023.

Production at Kakwa is split 60/40 between Kakwa Central and Kakwa North. At Kakwa Central one (0.25 net)

well was tied in during the year. At Kakwa North, production is from the Company’s interest in four wells. The

Company converted a royalty interest to a working interest in these wells in the fourth quarter of 2022.

Consistent with prior years, Kakwa represents over 80% of corporate volumes.

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 were flat over the prior year with new

wells in both areas offsetting natural declines.

2023 Annual Report

New wells at Kakwa Central are expected to be on-stream in the fourth quarter of 2024. As a result, the

Company anticipates its volumes will decline over this year. Subject to the timing of a possible drilling program

at Kakwa North, the Company could see incremental volumes in the second quarter of 2025.

2023 Financial Results

Petroleum and Natural Gas Revenue

2023

2022

Oil and

Natural

Oil and

Natural

($ thousands)

Liquids

Gas

Total

Liquids

Gas

Total

Alberta

25,418

5,486

30,904

29,093

9,797

38,890

Saskatchewan and Manitoba

10,797

–

10,797

12,861

–

12,861

36,215

5,486

41,701

41,954

9,797

51,751

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

The effect of increased production volumes on revenue was completely offset by the decline in realized

commodity prices. Petroleum and natural gas revenue dropped by 20% with a nearly 30% drop in prices

reduced by a just under 10% increase in production volumes.

Pricing

2023

2022

Benchmark prices:

Natural Gas - AECO, daily spot ($/Mcf)

2.64

5.15

Crude Oil - Canadian Light Sweet Blend ($/bbl)

100.39

121.49

Realized prices:

Natural Gas ($/Mcf)

3.02

6.10

Crude Oil and Natural Gas Liquids ($/bbl)

94.01

121.58

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

Although crude oil prices remained relatively stable during the year, they declined by almost 20% over last

year. The benchmark West Texas Intermediate averaged US$77.62 per barrel this year compared to US$94.76

per barrel in 2022.

In the first half of the year, prices reflected tightening fundamentals with optimism about demand growth from

developing countries, particularly India and China, and supply cuts by OPEC members. These impacts were

moderated by the rising interest rates, inflation, and the risks of a recession. Later in the year, prices were

supported by US inventories reaching near five-year lows and the concerns of the Israel-Hamas conflict

expanding to the broader region, including reduced crude flows through the Suez Canal. In Canada the outlook

for heavier crude and the associated demand for condensate as a diluent is expected to improve as the TMX

pipeline commences service in 2024.

Questerre Energy Corporation

Mirroring the decline in the WTI price, Questerre’s realized prices fell to $94.01 per barrel from $121.58 per

barrel last year. This compared to the benchmark Edmonton Mixed Sweet blend that averaged $100.39 in 2023

compared to $121.49 last year.

Natural gas prices experienced a more substantial decline and fell over 60% in the year. The benchmark Henry

Hub averaged US$2.54 per MMBtu compared to US$6.44 per MMBtu last year.

The decline was driven by record natural gas production in the United States. This increased to 104 Bcf per day

led by growth in the major producing basins including the Permian and Appalachian. This growth outpaced the

increases in natural gas exports by pipeline and LNG as well as the increased demand for power generation.

Lower residential and commercial demand during a warmer than expected winter also contributed to the lower

prices. In Canada, production levels remained largely flat and prices reflected the increased storage levels and

lack of access to international markets.

With a higher heat content for the natural gas production from Kakwa, realized prices reflect a premium over

the benchmark prices. In 2023, Questerre’s realized price was $3.02 per Mcf (2022: $6.10 per Mcf) compared

to the AECO benchmark of $2.64 per Mcf (2022: $5.15 per Mcf).

Royalties

thousands)

2023

2022

Alberta

5,081

3,882

Saskatchewan and Manitoba

914

950

5,995

4,832

% of Revenue:

Alberta

16%

10%

Saskatchewan and Manitoba

Total Company

14%

Royalties increased over the prior year due mainly to the higher effective rates on production from Alberta. As

a percentage of revenue, this increased from 9% last year to 14% this year.

The higher royalty rates in Alberta reflect the expiry of Crown incentive programs for wells drilled at Kakwa.

Incrementally, the addition of working interest volumes at Kakwa North where these programs previously

expired also contributed to the higher rates. This equates to royalty rates of 40% on condensate production

from older vintage wells compared to effective rates of 5% from wells that meet the applicable incentive

program criteria.

Royalty rates on production in Manitoba and Saskatchewan increased marginally due to the addition of a new

well that attracted higher rates.

2023 Annual Report

Operating Costs

($ thousands)

2023

2022

Alberta

11,499

11,310

Saskatchewan and Manitoba

4,050

3,511

Quebec

533

485

16,082

15,306

$/boe:

Alberta

20.39

21.90

Saskatchewan and Manitoba

36.61

32.15

Total Company

23.84

24.47

Gross operating costs increased by just over 5% because of higher production volumes in the year. On a unit

of production basis, this remained relatively stable at approximately $24 per boe.

In Alberta, operating costs in the current year include a full year of production from Kakwa North compared to

only a single quarter in the prior year. In Saskatchewan, the increase in operating costs is attributable to

unexpected issues with a workover in the third quarter. Operating costs in Quebec reflect the costs associated

with maintaining the Company’s assets in the province.

General and Administrative Expenses

($ thousands)

2023

2022

General and administrative expenses, gross

5,356

4,655

Capitalized expenses and overhead

recoveries

(270)

(228)

General and administrative expenses, net

5,086

4,427

Gross General & Administrative expenses (“G&A”) increased by 20% to $5.4 million from $4.7 million last year.

Nominally higher expenses reflecting, in part, general cost inflation, were incurred in several categories,

including salaries and benefits, consulting as well as legal and government and public relations related to the

Company’s project in Quebec. 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, 2023, the Company recorded depletion, depreciation, and accretion expense

of $12.6 million (2022: $9.9 million) with depletion accounting for over 90% of this amount.

The higher amount reflects both the higher production volumes in the current year as well as increases in the

carrying value of its assets and future development costs. On a unit of production basis this increased to

$17.60/boe from $15.25/boe last year.

The Company assessed the carrying value of its plant, property and equipment assets (“PP&E”) as at December

31, 2023, for indicators of impairment. Based on this review the Company’s Western Canada cash generating

units (“CGUs”) were tested in accordance with the Company’s accounting policy. The recoverable amount of

Questerre Energy Corporation

the CGUs was estimated based on the higher of the fair value less costs of disposal (“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 of $23.7 million (2022: $0.9 million). Of this amount the Antler CGU, recorded an

impairment expense of $5.3 million (2022: $0.9 million) based on a FVLCD assessment and the Kakwa CGU

recorded an impairment expense of $18.4 million (2022: nil) based on a VIU assessment. No impairments were

recorded for the Company’s other CGUs.

The estimates of FVLCD and VIU were determined using discount rates ranging from 12.5% to 15.6% and

forecasted after tax cash flows based on proved plus probable reserves, with escalating prices, future

development costs and an estimate of G&A where applicable.

The Company assessed the carrying value of its exploration and evaluation (“E&E”) assets and impaired its

assets in Saskatchewan by $0.8 million. No other impairment was recorded in the current year.

Share Based Compensation

Pursuant to the Company’s share option plan, an optionee may request that the Company purchase all or any

part of the then vested options of the optionee, for an amount equal to the market price of the Common Shares

less the exercise price of the option shares. Notwithstanding the foregoing, the Company may, at its sole

discretion, decline to accept and, accordingly, has no obligations with respect to the exercise of this put right

at any time. Once the options are cash settled, the options are cancelled.

The Company recorded share based compensation expense of $1.4 million (2022: $1.9 million) net of $0.2

million (2022: $0.3 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.

As a result of the reduction in the net asset value, the Company recorded an expense of $1.2 million (2022:

$2.5 million). For more information, please see Note 7 to the Financial Statements.

Interest and Other Income

The Company earned interest and other income of $1.5 million for the year ended December 31, 2023. The

interest was earned on its cash and term deposits that totaled $35 million at year-end. In the prior year, other

income included $1.8 million for the discharge of a contingent liability related to the 2019 acquisition of assets

in Quebec.

Other Comprehensive Income (Loss)

In 2023, the Company recorded other comprehensive loss of $0.4 million (2022: $0.9 million income) related

to the change in foreign exchange rates. A loss of $0.1 million in the current year (2022: $0.4 million gain) was

attributable to the change in the US dollar denominated investment in Red Leaf. The Company also incurred a

2023 Annual Report

loss of $0.3 million (2022: $0.5 million gain) due to the depreciation in the Jordanian dinar impacting its dinar-

denominated assets in Jordan.

Net Income (Loss) and Total Comprehensive Income (Loss)

For the year ended December 31, 2023, the Company recorded a net loss of $23.7 million compared to net

income of $14.1 million in the prior year. The loss in the current year is due to lower petroleum and natural

gas revenue and higher expenses in all categories, specifically, impairment.

Including other comprehensive loss, the Company reported a total comprehensive loss of $24.1 million

compared to income of $14.9 million last year.

Cash Flow from Operating Activities

The Company reported cash flow from operating activities of $16.3 million (2022: $28.8 million). The variance

over the prior year is attributed to the lower adjusted funds flow from operations and a smaller change in the

non-cash working capital.

Cash Flow used in Investing Activities

Commensurate with nominally lower capital spending, the cash used in investing activities declined to $10.8

million from $12 million last year. Expenditures on PP&E and E&E decreased by $1.5 million to $10.1 million

and the Company recorded a higher decrease in non-cash working capital in the current year.

Cash Flow provided by Financing Activities

In the current year, effectively no cash was used for financing activities. The prior year amount of $3.4 million

reflects the net repayment of drawings under the credit facilities.

Capital Expenditures

($ thousands)

2023

2022

Alberta

3,616

10,955

Saskatchewan, Manitoba and Jordan

6,532

636

Total

10,148

11,591

Notes:

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

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 of one (0.35 net) well in Manitoba and on other

assets.

For the year ended December 31, 2022, the Company incurred capital expenditures of $11.6 million as follows:

•

In Alberta, $11.0 million to finish drilling, complete and tie-in three (0.75 net) wells on the Kakwa

Central joint venture

;

Questerre Energy Corporation

•

In Saskatchewan, $0.5 million was spent on the pressure maintenance scheme; and

•

In Jordan, $0.1 million was spent on advancing the engineering for its oil shale project.

Fourth Quarter 2023 Results

In the fourth quarter of the year, petroleum and natural gas revenue declined by nearly 30% to $9.7 million

from $13.6 million last year. Approximately one third of this decline is due to lower production volumes with

the remainder due to the drop in realized commodity prices.

Production volumes declined over the prior year as only one (0.25 net) well was brought on production at

Kakwa Central in the current year compared to three (0.75 net) wells last year. This was offset by incremental

volumes at Antler as one new well was brought on production. Both crude oil and natural gas prices declined

over the prior year and preceding quarter. The differential between WTI and Canadian condensate prices

declined to a discount compared to a premium last year.

Operating costs decreased materially over the prior year and preceding quarter, both on a gross and unit of

production basis. In the fourth quarter, operating costs totaled $3.5 million compared to $5.3 million last year.

The change is mainly due to lower operating costs at Kakwa in fuel and power along with workovers.

Including impairment expense relating to its Kakwa, Alberta and Antler, Saskatchewan CGUs, the Company

reported a net loss of $26 million for the quarter (2022: $0.1 million loss) and total comprehensive loss of $26

million (2023: $0.5 million). The loss is largely due to the impairment expense in the current year offset by

lower operating expenses. In the prior year, the smaller loss is due to the higher petroleum and natural gas

revenue and smaller impairment expense.

In the fourth quarter, net cash from operating activities was $5.2 million (2022: $5.3 million). This reflects the

lower adjusted funds flow from operations of $3.2 million and a larger increase in non-cash working capital of

$2 million in the current year compared to $4.9 million and $0.4 million respectively last year. Net cash used in

investing activities increased over the prior year due to higher capital spending. There was no change in the

net cash used in financing activities.

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 and available debt facilities.

At December 31, 2023 and 2022, there were effectively no 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, 2023 was 5.76 (2022: 6.13) and the covenant was met. See Note 13 of

the Financial Statements.

2023 Annual Report

While the credit facilities were maintained at $16 million, the facilities could be reduced at their next review

scheduled during the second quarter of 2024. 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 2024 future development costs associated with proved reserves in its

independent reserves assessment as of December 31, 2023. It anticipates that, as a result, reserves associated

with wells drilled in 2024 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, 2023, there were no Class “B” common voting shares or

preferred shares outstanding.

The following table provides a summary of the outstanding Common Shares and options as at the date of the

MD&A and the current and preceding fiscal year end.

March

21,

December

31,

December

31,

(thousands)

2024

2023

2022

Common Shares

428,516

Stock Options

38,420

38,140

35,298

Weighted average Common Shares

Basic

428,516

Diluted

428,516

430,524

Questerre Energy Corporation

A summary of the Company’s stock option activity during the years ended December 31, 2023 and 2022

follows:

December 31, 2023

December 31, 2022

Weighted

Number

Average

Number

Average

Options

Exercise

Options

Exercise

(thousands)

Price

(thousands)

Price

Outstanding, beginning of period

35,298

0.28

30,308

0.35

Granted

6,000

0.24

11,490

0.34

Expired

(3,158)

0.48

(6,500)

0.69

Outstanding, end of period

38,140

0.26

35,298

0.28

Exercisable, end of period

28,153

0.25

22,643

0.28

Commitments

A summary of the Company’s net commitments at December 31, 2023 follows:

thousands)

2024

2025

2026

2027

Total

Transportation and Processing

3,429

2,515

1,566

545

8,055

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 adjusted funds flow from operations and its existing credit facilities.

Risk Management

Companies engaged in the petroleum and natural gas industry face a variety of risks. For Questerre, these

include risks associated with commodity prices, exploration and development drilling as well as production

operations, foreign exchange and interest rate fluctuations. Unforeseen significant changes in such areas as

markets, prices, royalties, interest rates, government regulations and global economic conditions could have

an impact on the Company’s future operating results and/or financial condition. While Management realizes

that all the risks may not be controllable, Questerre believes that they can be monitored and managed. For

more information, please refer to the “Risk Factors” and “Industry Conditions” sections of the AIF and Note 6

to the audited consolidated financial statements for the year ended December 31, 2023.

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, hostilities in the

Middle East, Ukraine and Taiwan, U.S. shale production, sovereign debt levels and political upheavals in various

2023 Annual Report

countries including growing anti-fossil fuel sentiment, 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 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 Energy Corporation

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 the potential financial loss to the Company if a customer or counterparty to a financial

instrument fails to meet or discharge their obligation to the Company. Credit risk arises from the Company’s

receivables from joint venture partners and oil and gas marketers. In the event such entities fail to meet their

contractual obligations to the Company, such failures may have a material adverse effect on the Company’s

business, financial condition, results of operations and prospects. Credit risk also arises from the Company’s

cash and cash equivalents. In the past, the Company manages credit risk exposure by investing in Canadian

banks and credit unions. Management does not expect any counterparty to fail to meet its obligations.

Poor credit conditions in the industry may impact a joint venture partner’s willingness to participate in the

Company’s ongoing capital program, potentially delaying the program and the results of such program until

the Company finds a suitable alternative partner if possible.

Substantially all of the accounts receivable are with oil and natural gas marketers and joint venture partners in

the oil and natural gas industry and are subject to normal industry credit risks. The Company generally extends

unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by

changes in economic or other conditions. Management believes the risk is mitigated by entering into

transactions with long-standing, reputable counterparties and partners.

Accounts receivable related to the sale of the Company’s petroleum and natural gas production is 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, 2023 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

2023 Annual Report

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, 2023, the Company had no outstanding commodity risk management contract in place.

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

Questerre Energy Corporation

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, 2023, and 2022 the Company had credit facilities outstanding

effectively of nil with an effective rate of 7.95% (2022: 5.33%).

Critical Accounting Estimates

The preparation of the consolidated financial statements requires management to make judgments, estimates

and assumptions that affect the application of accounting policies and the reported amounts of assets,

liabilities, income and expenses. Actual results may differ from these estimates. These estimates and

judgments have risk of causing a material adjustment to the carrying amounts of assets and liabilities within

the next financial year.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates

are recognized in the year in which the estimates are revised and in any future years affected.

Petroleum and Natural Gas Reserves

All of Questerre’s petroleum and natural gas reserves are evaluated and reported on by independent

petroleum engineering consultants in accordance with

National Instrument 51-101 Standards of Disclosure for

Oil and Gas Activities

and the COGE Handbook. For further information, please refer to “Statement of Reserves

Data and Other Oil and Gas Information” in the AIF.

The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future

rates of production, commodity prices and the timing of future expenditures, all of which are subject to

numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will

change to reflect updated information. Reserve estimates can be revised upward or downward based on the

results of future drilling, testing, production levels and changes in costs and commodity prices. These estimates

are evaluated by independent reserve engineers at least annually.

Proved and probable reserves are estimated using independent reserve engineer reports and represent the

estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and

engineering data demonstrate with a specified degree of certainty to be recoverable in future years from

known reservoirs and which are considered commercially producible. If probabilistic methods are used, there

should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the

estimated proved plus probable reserves and there should be at least a 90 percent probability that the

quantities actually recovered will equal or exceed the estimated proved reserves.

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

and the calculation of depletion.

Cash Generating Units

A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are largely

independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires

2023 Annual Report

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 and Goodwill

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.

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.

Goodwill is the excess of the purchase price paid over the fair value of the net assets acquired. Since goodwill

results from purchase accounting, it is imprecise and requires judgment in the determination of the fair value

of assets and liabilities. Goodwill is assessed for impairment on an operating segment level based on the

recoverable amount for each CGU of the Company. Therefore, impairment of goodwill uses the same key

judgments and assumptions noted above for impairment of assets.

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.

Questerre Energy Corporation

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.

Since December 31, 2016, the recoverability of deferred tax assets is assessed using proved reserves including

an estimate of G&A associated with the assets.

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.

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, 2023.

•

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, 2023 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,

2023 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.

2023 Annual Report

Quarterly Financial Information

December

31,

September

30,

June

30,

March

31,

($ thousands, except as noted)

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

3,209

3,034

5,335

4,277

Net Profit (Loss)

(26,003)

(337)

1,692

940

Basic and Diluted ($/share)

(0.06)

–

Capital Expenditures, net of acquisitions and

dispositions

3,588

845

2,469

3,246

Working Capital Surplus (Deficit)

29,866

30,191

28,013

25,523

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

Diluted (thousands)

428,516

431,100

431,064

December

31,

September

30,

June

30,

March

31,

($ thousands, except as

noted)

2022

Production (boe/d)

2,023

1,629

1,909

1,288

Average Realized Price ($/boe)

72.87

77.40

97.95

82.56

Petroleum and Natural Gas Revenue

13,562

11,602

17,013

9,574

Adjusted Funds

Flow from Operations

4,670

5,183

12,183

4,290

Net Profit (Loss)

(122)

2,759

9,051

2,423

Basic and Diluted ($/share)

–

0.01

0.02

0.01

Capital Expenditures, net of acquisitions and dispositions

2,169

1,653

2,843

4,926

Working Capital Surplus (Deficit)

24,491

14,433

10,564

1,192

Total Assets

196,486

196,258

194,419

186,201

Shareholders' Equity

166,128

166,235

161,969

151,862

Weighted Average Common Shares Outstanding

Basic (thousands)

428,516

Diluted (thousands)

428,516

430,727

428,747

432,112

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 increased due to the recovery in commodity

prices in 2022 and largely stabilized in 2023.

•

Production volumes reflect the capital investment in drilling and completing wells at Kakwa in preceding

quarters. Additionally, effective the fourth quarter of 2022, the Company converted its royalty interest to a

working interest at Kakwa North.

Questerre Energy Corporation

•

The level of capital expenditures over the quarters has varied largely due to the timing and number of wells

drilled and completed as well as, the timing of the infrastructure investment at Kakwa Alberta. In the fourth

quarter of 2023, $3 million was 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 increased as a result of net income, primarily from higher commodity prices, except in

the last quarter when a net loss reduced shareholders equity.

Off-Balance Sheet Transactions

The Company did not engage in any off-balance sheet transactions during the year ended December 31, 2023.

2023 Annual Report

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 and 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 and 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, Canada

March 21, 2024

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, 2023 and 2022, and the consolidated statement

of net income (loss) and comprehensive income (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, 2023 and 2022, 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.

2023 Annual Report

Key audit matter

How our audit addressed the key audit matter

Impairment of property, plant and equipment

As at December 31, 2023, the carrying amount of property,

plant and equipment in the Western Canada operating

segment was $115.9 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.

impairment

indicators existed for all CGUs in the Western Canada

operating segment, property, plant and equipment for all

CGUs in the segment were tested for impairment.

For the year ended December 31, 2023, an impairment of

$23.7 million was recorded with respect to property, plant

and equipment in the Kakwa and Antler CGUs. 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 amounts for

all CGUs 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

and value in use model

were forecasted production, escalated pricing, royalties,

operating costs, future development costs and an after

tax

discount rate. Determining the amount of impairment

requires an

estimate of a CGU’s respective recoverable

amount. The recoverable amounts of the CGUs were

determined using fair value less costs of disposal and value

in use

models based on expected after-

tax future net cash

flows from the production of

proved plus pro

bable 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)

To test the Company's estimated recoverable amounts of

the significant CGUs 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 m

ethodology 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 ou

r 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 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

Questerre Energy Corporation

•

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 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,

2023 Annual Report

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.

•

Obtain sufficient appropriate audit evidence regarding the financial information of the entities or

business activities within the Group to express an opinion on the consolidated financial statements.

We are responsible for the direction, supervision and performance of the group audit. We remain

solely responsible for our audit opinion.

We communicate with those charged with governance regarding, among other matters, the planned scope

and timing of the audit and significant audit findings, including any significant deficiencies in internal control

that we identify during our audit.

We also provide those charged with governance with a statement that we have complied with relevant ethical

requirements regarding independence, and to communicate with them all relationships and other matters that

may reasonably be thought to bear on our independence, and where applicable, related safeguards.

From the matters communicated with those charged with governance, we determine those matters that were

of most significance in the audit of the consolidated financial statements of the current period and are

therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation

precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a

matter should not be communicated in our report because the adverse consequences of doing so would

reasonably be expected to outweigh the public interest benefits of such communication.

Questerre Energy Corporation

The engagement partner on the audit resulting in this independent auditor’s report is Robert Mitchell.

Chartered Professional Accountants

Calgary, Canada

March 21, 2024

2023 Annual Report

Consolidated Balance Sheets

December 31,

thousands)

Note

2023

2022

Assets

Current Assets

Cash and cash equivalents

35,038

29,590

Accounts receivable

3,016

4,600

Deposits and prepaid expenses

1,419

968

39,473

35,158

Right-of-use assets

180

238

Investments

4,471

5,796

Property, plant and equipment

115,935

141,067

Exploration and evaluation assets

12,287

14,227

172,346

196,486

Liabilities

Current Liabilities

Lease liabilities

Accounts payable and accrued liabilities

9,387

10,634

Current portion of asset retirement obligation

184

484

Credit Facilities

6,13

9,665

11,210

Lease liabilities

134

191

Asset retirement obligation

18,880

18,957

28,679

30,358

Shareholders' Equity

Share capital

429,878

Contributed surplus

27,908

26,301

Accumulated other comprehensive income

(20)

340

Deficit

(314,099)

(290,391)

143,667

166,128

172,346

196,486

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

Questerre Energy Corporation

Consolidated Statements of Net Income (Loss) and Comprehensive

Income (Loss)

For

the year ended December 31,

thousands, except per share amounts

)

Note

2023

2022

Revenue

Petroleum and natural gas revenue

41,701

51,751

Royalties

(5,995)

(4,832)

Petroleum and natural gas revenue, net of royalties

35,706

46,919

Expenses

Direct operating

16,082

15,306

General and administrative

5,086

4,427

Depletion, depreciation and accretion

8,12,19

12,631

9,900

Impairment

8,9

24,449

857

Loss on equity investment

1,232

2,540

Lease expiries

139

129

Share based compensation

1,367

1,891

Interest and other income

(1,572)

(2,198)

Income (loss) before taxes

(23,708)

14,067

Deferred tax (recovery) expense

–

Net income (loss)

(23,708)

14,067

Other Comprehensive Income (Loss), Net of Tax

Items that may be reclassified subsequently to profit or loss:

Foreign currency translation adjustment

(267)

496

Income (loss) on foreign exchange on investments

(93)

371

(360)

867

Total Comprehensive Income (Loss)

(24,068)

14,934

Net Income (Loss) per Share

Basic and diluted

(0.06)

0.03

The notes are an integral part of these consolidated financial statements.

2023 Annual Report

Consolidated Statements of Changes in Equity

For

the year ended December 31,

thousands)

2023

2022

Capital

Balance, beginning and end of year

429,878

Contributed Surplus

Balance, beginning of year

26,301

24,068

Share based compensation

1,607

2,233

Balance, end of year

27,908

26,301

Accumulated Other Comprehensive Income (Loss)

Balance, beginning of year

340

(527)

Other comprehensive income (loss)

(360)

867

Balance, end of year

(20)

340

Deficit

Balance, beginning of year

(290,391)

(304,458)

Net income (loss)

(23,708)

14,067

Balance, end of year

(314,099)

(290,391)

Total Shareholders' Equity

143,667

166,128

The notes are an integral part of these consolidated financial statements.

Questerre Energy Corporation

Consolidated Statements of Cash Flows

For

the years ended December

31,

thousands)

Note

2023

2022

Operating Activities

Net income (loss)

(23,708)

14,067

Adjustments for:

Depletion, depreciation and accretion

8,12,19

12,631

9,900

Impairment

8,9

24,449

857

Lease expiries

139

129

Loss on equity investment

1,232

2,540

Share based compensation

1,367

1,891

Deferred tax (recovery) expense

–

Other income

–

(1,768)

Abandonment expenditures

(255)

(878)

15,855

26,738

Change in non

-cash working capital

462

2,072

Net cash from operating activities

16,317

28,810

Investing Activities

Property, plant and equipment expenditures

(4,650)

(2,779)

Exploration and evaluation expenditures

(5,498)

(8,812)

Acquisition of exploration assets

–

Change in non

-cash working capital

(666)

(378)

Net cash used in investing activities

(10,814)

(11,969)

Financing Activities

Principal portion of lease payments

(58)

(53)

Increase in credit facilities

5,413

Repayment of

credit facilities

–

(8,800)

Net cash used in financing activities

(55)

(3,440)

Change in cash, cash equivalents and restricted cash

5,448

13,401

Cash, cash equivalents and restricted cash, beginning of year

29,590

16,189

Cash, cash equivalents and restricted cash, end of year

35,038

29,590

The notes are an integral part of these consolidated financial statements

Notes to the Consolidated Financial Statements

For the years ended December 31, 2023, and 2022

2023 Annual Report

1. Reporting Entity

Questerre Energy Corporation (“Questerre” or the “Company”) is an energy technology and innovation

company actively engaged in the acquisition, exploration and development of oil and gas projects, specifically,

non-conventional projects such as tight oil, oil shale, shale oil and shale gas. The consolidated financial

statements of the Company as at and for the years ended December 31, 2023, and 2022 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 assets in Jordan.

Questerre is incorporated under the laws of the Province of Alberta and is domiciled in Canada. The address of

its registered office is 1650, 801 Sixth Avenue SW, Calgary, Alberta.

a) Segmented Disclosure

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 a significant natural gas discovery in the

province and plans to develop a clean technology energy project.

•

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 Leaf

Resources Inc. (“Red Leaf”).

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 income (loss) by operating segment to the consolidated statements of net income (loss)

and comprehensive income (loss).

Western

Corporate

Questerre Energy Corporation

($ thousands )	Canada	Quebec	& other	Consolidated
Assets by operating segment
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
Exploration and Evaluation	$ 7,415	$ –	$ 6,812	$ 14,227
Property, Plant & Equipment	141,067	–	–	141,067
Other	5,568	7,658	27,966	41,192
Total Assets, December 31, 2022	$ 154,050	$ 7,658	$ 34,778	$ 196,486
Results by operating segment
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)
Revenues	$ 46,919	$ –	$ –	$ 46,919
Expenses	(25,707)	(485)	(4,120)	(30,312)
Other income	–		(2,540)	(2,540)
Total Income (Loss), December 31, 2022	$ 21,212	$ (485)	$ (6,660)	$ 14,067

2. Basis of Preparation

a) Statement of compliance

The Company prepares its consolidated financial statements in accordance with International Financial

Reporting Standards (“IFRS”) as issued by the International Accounting Standards Boards (“IASB”). The policies

applied in these consolidated financial statements are based on IFRS issued and outstanding as at March 21,

2024, the date the Board of Directors approved the statements.

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 3.

c) Functional and presentation currency

These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional

currency. The Company has a wholly-owned subsidiary with a functional currency of the Jordanian Dinar.

d) Jointly controlled assets

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

2023 Annual Report

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 accounted for under the equity method.

e) Use of estimates and judgments

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.

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.

Questerre Energy Corporation

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 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

2023 Annual Report

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. Notwithstanding, the Company has the right to only equity settle options. While the

Company primarily has equity settled options, it may change this in the future at its discretion. 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.

Investment in Red Leaf

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.

Refer to Note 7 for the carrying amounts related to the Company’s investment in Red Leaf.

Questerre Energy Corporation

3. Material Accounting Policy Information

The accounting policies set out below have been applied consistently to all periods presented in these

consolidated financial statements.

a) Basis of consolidation

Subsidiaries

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern

the financial and operating policies of an entity to obtain benefits from its activities. In assessing control,

potential voting rights that currently are exercisable are considered.

Transactions eliminated on consolidation

Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany

transactions, are eliminated in preparing the consolidated financial statements.

b) Financial instruments

Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions

of the instrument. Financial assets are derecognized when the rights to receive cash flows from the assets have

expired or have been transferred and the Company has transferred substantially all risks and rewards of

ownership. Financial liabilities are derecognized when the obligation specified in the contract is discharged,

cancelled or expires.

Financial assets and liabilities are offset and the net amount is reported in the balance sheet when there is a

legally enforceable right to offset the recognized amounts and there is an intention to settle on a net basis, or

realize the asset and settle the liability simultaneously.

The Company classifies its financial instruments in the following categories, at initial recognition, depending

on the purpose for which the instruments were acquired.

Financial assets and liabilities at fair value through profit or loss

A financial asset or liability is classified in this category if it is held for trading. Derivatives are also included in

this category unless they are designated as hedges. The Company has designated its risk management contracts

in this category.

Financial assets at amortized cost

Financial assets at amortized cost are non-derivative financial assets with fixed or determinable payments that

are not quoted in an active market. They include accounts receivable and deposits. These assets are included

in current assets due to their short-term nature. They are recognized initially at the amount expected to be

received, less, when material, a discount to reduce to fair value. Subsequently, they are measured at amortized

cost using the effective interest method less a provision for impairment.

Cash and cash equivalents include deposits held with banks, less outstanding cheques, and short-term deposits

with original maturities of one year or less.

2023 Annual Report

Financial liabilities at amortized cost

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 months.

c) Investments

For the purposes of testing for 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.

d) Share capital

Common Shares are classified as equity. Incremental costs directly attributable to the issue of Common Shares

are recognized as a deduction from equity, net of any tax effects.

e) Property, plant and equipment and exploration and evaluation assets

Recognition and measurement

Exploration and evaluation expenditures

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.

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

Questerre Energy Corporation

exploration and evaluation well indicators are evaluated. If there are indicators of impairment, the wells are

tested for impairment at the CGU level.

Development and production costs

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 is recognized in profit 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.

Depletion and depreciation

The net carrying value of development and production assets is depleted using the unit of production method

based on estimated proved and probable reserves, considering estimated future development costs necessary

to bring those reserves into production. These estimates are evaluated by independent reserve engineers at

least annually.

For other assets, depreciation is recognized in profit or loss on a straight-line basis over the respective useful

lives.

Depreciation methods and useful lives are reviewed at each reporting date.

f) Impairment

Non-financial assets

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 goodwill an impairment test is completed

each year, or when any indication of impairment exists.

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.

2023 Annual Report

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

respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and

then to reduce the carrying amounts of the other assets in the unit (group of units) on a pro rata basis.

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 been recognized. Impairment reversals

are recognized in profit or loss.

Impairment of financial assets

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 recognized. Also refer to Note 6.

Share based compensation

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 that vest.

g) Provisions

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

Questerre Energy Corporation

pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the

liability.

Asset retirement obligation

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 category.

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 incurred upon settlement of the asset retirement obligations

are charged against the provision.

h) Revenue from commodity sales and royalties

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;

•

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

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

2023 Annual Report

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 period when the actual amounts are received.

i) Income tax

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. In addition, deferred tax is not recognized for taxable temporary differences arising on

the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to

temporary differences when they reverse, based on the laws that have been enacted or substantively enacted

by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset,

and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different

tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and

liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available

against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date

and are reduced to the extent that it is no longer probable that the related tax asset will be realized.

The effect of a change in enacted or substantively enacted income tax rates on future income tax assets and

liabilities is recognized in profit or loss in the period that the change occurs unless the original entry was

recorded to equity.

j) Net profit or loss per share

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.

Questerre Energy Corporation

Since the options may be settled in cash or shares at the Company’s discretion and therefore there is no

obligation to settle in cash, the share units are accounted for as equity-settled share based payment

transactions and included in diluted profit per share if the effect is dilutive.

k) Leases

Under IFRS 16, the Company recognizes right-of-use assets and lease liabilities for most leases. Certain short-

term leases (less than 12 months) and leases of low-value assets are exempt from the requirements and may

continue to be treated as operating leases. The right-of-use assets recognized are subsequently depreciated

using the straight-line method from the commencement date to the earlier of the end of the useful life of the

right-of-use assets or the end of the lease term. The estimated useful lives of right-of-use assets are determined

on the same basis as those of property and equipment. In addition, the right-of-use assets are periodically

reduced by impairment losses, if any, and adjusted for certain re-measurements of the lease liabilities.

The lease liabilities are initially measured at the present value of the lease payments that are not paid at the

commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily

determined, the Company's incremental borrowing rate. The Company uses its incremental borrowing rate as

the discount rate.

The lease liabilities are subsequently measured at amortized cost using the effective interest method. It is re-

measured when there is a change in future lease payments arising from a change in an index or rate, if there is

a change in the Company's estimate of the amount expected to be payable under a residual value guarantee,

or if the Company changes its assessment of whether it will exercise a purchase, extension or termination

option.

When the lease liabilities are re-measured in this way, a corresponding adjustment is made to the carrying

amount of the right-of-use assets or is recorded in profit or loss if the carrying amount of the right-of-use assets

has been reduced to nil. The Company presents right-of-use assets and lease liabilities separately in the balance

sheet.

The application of IFRS 16 requires significant judgments and estimations to be made. Areas that require

judgment include identifying whether a contract (or part of a contract) includes a lease, determining whether

it is reasonably certain that an extension or termination option will be exercised, determining whether variable

payments are in substance fixed, establishing whether there are multiple leases in an arrangement and

determining the stand-alone amounts for lease and non-lease components. Other sources of estimation

uncertainty in the application of IFRS 16 include estimating the lease term, determining the appropriate

discount rate to apply to lease payments and assessing whether a right-of-use assets are impaired.

4. Changes in Accounting Policies and Disclosures

Future Accounting Pronouncements

In January 2021, the IASB issued amendments to IAS 1

Presentation of Financial Statements

, to clarify its

requirements for the presentation of liabilities as current or non-current in the consolidated balance sheet.

The amendment is effective for periods beginning on or after January 1, 2024.

2023 Annual Report

5. Cash and Cash Equivalents

	December 31,	December 31,
($ thousands)	2023	2022
Bank balances	$ 10,283	$ 6,053
Short -term bank deposits	24,755	23,537
	$ 35,038	$ 29,590

6. Financial Risk Management and Determination of Fair Values

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.

b) Fair value of financial instruments

The Company’s financial instruments as at December 31, 2023 included cash and cash equivalents, accounts

receivable, deposits, investments, credit facilities and accounts payable and accrued liabilities. As at December

31, 2023, 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.

Disclosures about the inputs to fair value measurements are required, including their classification 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.

The Company’s has no financial instruments within the Level 3 hierarchy.

c) Credit risk

Credit risk represents the 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

Questerre Energy Corporation

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.

The Company’s accounts receivables are aged as follows:

	December 31,	December 31,
($ thousands)	2023	2022
Current	$ 2,939	$ 4,539
31 - 60 days	–	4
61 - 90 days	46	10
>90 days	265	209
Expected credit loss provision	(234)	(162)
	$ 3,016	$ 4,600

The Company does not anticipate any material default as it transacts with creditworthy customers and

management does not expect any losses from non-performance by these customers. There are no material

financial assets that the Company considers past due that are considered impaired.

Cash and cash equivalents include cash bank balances and short-term deposits. The Company manages the

credit risk exposure by investing in Canadian banks. Management does not expect any counterparty to fail to

meet its obligations.

d) Liquidity risk

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

2023 Annual Report

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.

The timing of cash outflows relating to financial liabilities as at December 31, 2023 and 2022 are as follows:


	Less than	One to three
($ thousands)	one year	years	Total
Credit Facilities	$ 36	$ –	$ 36
Trade and other liabilities	9,387	–	9,387
Lease Liabilities	58	134	192
Current portion of asset retirement obligation	184	–	184
December 31, 2023	$ 9,665	$ 134	$ 9,799


	Less than	One to Three
($ thousands)	one year	Years	Total
Credit Facilities	$ 33	$ –	$ 33
Trade and other liabilities	10,634	–	10,634
Lease Liabilities	59	191	250
Current portion of asset retirement obligation	484	–	484
December 31, 2022	$ 11,210	$ 191	$ 11,401

e) Market risk

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, 2023, the Company had no outstanding commodity risk management contracts.

Currency risk

All of Questerre’s petroleum and natural gas sales are denominated in Canadian dollars; however, the

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

Questerre Energy Corporation

Jordanian Dinar and United States dollars. As at December 31, 2023, the Company had no forward foreign

exchange contracts in place.

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, 2023 and 2022, the Company had credit facilities outstanding of essentially nil.

f) Capital management

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 obligations in the normal course of operations. On an ongoing

basis, the Company reviews its capital expenditures to ensure that funds 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 and any outstanding amounts

under its credit facilities. 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)	2023	2022
Credit facilities	$ 36	$ 33
Shareholders' equity	143,667	166,128

7. Investment in Red Leaf

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 Company also holds

acreage permitted for a wax processing project in the state.

As at December 31, 2023, 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.

Questerre has determined its investment in Red Leaf will be accounted for using the equity method. This is

based on several criteria including its current equity interest in Red Leaf and ability to participate in the decision

making process of Red Leaf through its current Board representation. The Company measures the fair market

value of its investment using a net liquidation approach. The net liquidation value is calculated as the net

2023 Annual Report

current assets of Red Leaf less abandonment and other liabilities, the accrued and unpaid dividends associated

with the preferred shares and an estimate of research and development and general and administrative

expenses for the upcoming fiscal year.

	December 31,	December 31,
($ thousands )	2023	2022
Balance, beginning of year	$ 5,796	$ 7,965
Loss on equity investment	(1,232)	(2,540)
Gain (loss) on foreign exchange	(93)	371
Balance, end of the year	$ 4,471	$ 5,796

The assets, liabilities, and net loss of Red Leaf for the respective years were comprised as follows:

	December 31,	December 31,
($ thousands ) (1)	2023	2022
Cash and Cash Equivalents	$ 20,829	$ 24,285
Other Current Assets	281	–
Current Liabilities	124	268
Non-current liabilities	2,797	4,067
Net Loss (2)	$ (4,549)	$ (2,546)

(1)

Converted at an exchange rate of US$1=C$1.3226

(2)

Converted at an average exchange rate of US$1=C$1.34958

The issued and outstanding share capital of Red Leaf as of December 31, 2023 is comprised of the following:

	Issued and	Questerre
	Outstanding	Ownership
Common Shares	320,928	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, 2023, this priority amount is approximately

US$1.7 million.

Questerre Energy Corporation

8. Property, Plant and Equipment

A reconciliation of the PP&E assets is detailed below.

($ thousands )	Total
Cost or deemed cost:
Balance, December 31, 2021	$ 292,617
Change to asset retirement net of additions	1,361
Transfer from exploration and evaluation assets	9,848
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
Accumulated depletion, depreciation and impairment losses:
Balance, December 31, 2021	$ 152,497
Depletion and depreciation	9,405
Impairment	857
Balance, December 31, 2022	162,759
Depletion and depreciation	11,890
Impairment	23,737
Balance, December 31, 2023	$ 198,386

($ thousands )	Total
Net book value:
At December 31, 2022	$ 141,067
At December 31, 2023	$ 115,935

During the years ended December 31, 2023 and 2022, the Company did not capitalize any administrative

overhead or share based compensation expense directly related to development activities. Included in the

December 31, 2023, depletion calculation are future development costs of $319.6 million (2022: $317.9

million).

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 of $23.7 million

(2022: $0.9 million). Of this amount the Antler CGU, recorded an impairment expense of $5.3 million (2022:

$0.9 million) based on a FVLCD assessment and the Kakwa CGU recorded an impairment expense of $18.4

million (2022: nil) based on a VIU assessment. No impairments were recorded for the Company’s other CGUs.

The estimates of FVLCD and VIU were determined using discount rates ranging from 12.5% to 15.6% and

forecasted after tax cash flows based on proved plus probable reserves, with escalating prices, future

development costs and an estimate of G&A where applicable.

2023 Annual Report

As at December 31, 2023, the future prices used to determine cash flows from crude oil and natural gas

reserves were as follows:

						Average
						Annual %
						Change
	2024	2025	2026	2027	2028	Thereafter
WTI (US$/barrel)	73.67	74.98	76.14	77.66	79.22	2.00
AECO ($/MMbtu)	2.20	3.37	4.05	4.13	4.21	2.00

9. Exploration and Evaluation Assets

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.

A reconciliation of the movements in exploration and evaluation assets is detailed below.

	December 31,	December 31,
($ thousands )	2023	2022
Balance, beginning of year	$ 14,227	$ 14,710
Additions	5,591	8,955
Transfers to property, plant and equipment	(6,307)	(9,849)
Undeveloped lease impairments	(826)	–
Undeveloped lease expiries and farmouts	(139)	(129)
Foreign currency translation adjustment - Jordan	(259)	540
Balance, end of period	$ 12,287	$ 14,227

During the year ended December 31, 2023, the Company capitalized administrative overhead charges of $0.4

million (2022: $0.3 million) and $0.2 million (2022: $0.3 million) for capitalized share based compensation

expense directly related to exploration and evaluation activities.

Due to the change in market value of undeveloped land in the Antler, Saskatchewan, CGU, the Company

recognized an E&E impairment expense of $0.8 million (2022: nil). No impairments were recorded for the

Company’s other CGUs.

Questerre Energy Corporation

10. Deferred Income Taxes

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)	2023	2022
Net loss before taxes	$ (23,708)	$ 14,067
Combined federal and provincial tax rate	23.63%	23.60%
Computed 'expected' deferred tax expense (recovery)	(5,602)	3,320
Increase in deferred taxes resulting from:
Non-deductible differences and permanent items	192	264
Change in deferred tax asset not recognized	5,410	(3,584)
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 23.63%

in 2023 and 23.60% in 2022.

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	Share	Non-capital	Capital
($ thousands)	properties	Investments	obligation	issue costs	losses	losses
December 31, 2022	$ 28,043	$ 3,877	$ 4,588	$ 35	$ 6,041	$ 4,305
Change	8,768	135	(82)	(35)	(3,562)	7
December 31, 2023	$ 36,811	$ 4,012	$ 4,506	$ –	$ 2,479	$ 4,312

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.

Non-capital loss carry-forwards at December 31, 2023, expire from 2036 to 2043.

2023 Annual Report

The following temporary differences have not been recognized:

	December 31,	December 31,
($ thousands)	2023	2022
Petroleum and natural gas properties	$ 155,748	$ 118,822
Investments	33,955	32,862
Asset retirement obligation and leases	19,075	19,453
Share issue costs	–	146
Non -capital losses	10,488	25,598
Capital losses	36,488	36,488
Total	$ 255,754	$ 233,369

11. Share Based Compensation

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 generally expire five years from the grant date or five years from the commencement of vesting.

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 2023

and does not intend to cash settle options in future periods.

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 - $0.25	20,800	2.36	$ 0.20	15,579	1.87	$ 0.19
$0.26 - $0.36	17,340	2.05	0.32	12,574	1.67	0.32
	38,140	2.22	$ 0.26	28,153	1.78	$ 0.25

Questerre Energy Corporation

The following table summarizes information about stock options outstanding and exercisable at December 31,

2023:

	December 31, 2023		December 31, 2022
		Weighted		Weighted
	Number of	Average	Number of	Average
	Options	Exercise	Options	Exercise
	(thousands)	Price	(thousands)	Price
Outstanding, beginning of period	35,298	$ 0.28	30,308	$ 0.35
Granted	6,000	0.24	11,490	0.34
Expired	(3,158)	0.48	(6,500)	0.69
Outstanding, end of period	38,140	$ 0.26	35,298	$ 0.28
Exercisable, end of period	28,153	$ 0.25	22,643	$ 0.28

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 2023 and 2022:

	December 31,	December 31,
	2023	2022
Weighted average fair value per award ($)	0.18	0.26
Volatility (%)	103.83	101.83
Forfeiture rate (%)	9.35	10.24
Expected life (years)	5.00	5.00
Risk free interest rate (%)	3.18	1.63

This forfeiture rate estimate is adjusted to the actual forfeiture rate. Expected volatility and expected life is

based on historical information.

12. Asset Retirement Obligation

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 $19.1 million as at December 31, 2023 (2022: $19.4 million)

based on an undiscounted total future liability of $24.3 million (2022: $23.3 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 3.39% (2022: 3.63%). An inflation rate of 2% (2022: 2%) over the varying lives of the assets is

used to calculate the present value of the asset retirement obligation.

2023 Annual Report

The following table provides a reconciliation of the Company’s total asset retirement obligation:

	December 31,	December 31,
($ thousands)	2023	2022
Balance, beginning of year	$ 19,441	$ 21,495
Liabilities settled	(255)	(878)
Revisions due to change in discount rates & estimates	(878)	(2,330)
Liabilities incurred	73	335
Accretion	683	819
Balance, end of year	$ 19,064	$ 19,441
Current portion	184	484
Non -current portion	18,880	18,957
Balance, end of period	$ 19,064	$ 19,441

13. Credit Facilities

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 cash flow measured quarterly. The

facilities are secured by a debenture with a first floating charge 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 bank debt outstanding

and unrealized hedging losses). The Adjusted Working Capital Ratio at December 31, 2023, was 5.76 (2022:

6.13) and the covenant was met. At December 31, 2023, and 2022 effectively nil was drawn on Facility A with

an effective average interest rate of 7.95% for 2023 (2022: 5.33%).

As at December 31, 2022, the Company was returned the outstanding letters of credit for $7.7 million by the

Quebec Government for abandonment and reclamation liabilities. Consistent with the Company’s legal claim

to have Bill 21 declared invalid and in compliance with its obligations to fund these costs under the pre-existing

Petroleum Resources Act

, the Company continues to segregate these funds internally.

Questerre Energy Corporation

The following table reconciles the movement in the credit facilities during the year.

	December 31,	December 31,
($ thousands)	2023	2022
Credit Facilities, beginning of year	$ 33	$ 3,420
Drawdown from Credit Facilities	3	5,413
Repayment of Credit Facilities	–	(8,800)
Credit Facilities, end of year	$ 36	$ 33

The credit facilities are a demand facility and can be reduced, amended or eliminated by the lender for reasons

beyond the Company’s control. Should the credit facilities, in fact, be reduced or eliminated, the Company

would need to seek alternative credit facilities or consider the issuance of equity to enhance its liquidity. The

next scheduled review will be in the second quarter of 2024.

14. 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, 2023 and 2022, 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, 2022 and December 31, 2023	428,516	$ 429,878

b) Per share amounts

Basic net income (loss) per share is calculated as follows:

	December 31,	December 31,
(thousands, except as noted)	2023	2022
Net income (loss)	$ (23,708)	$ 14,067
Weighted average number of Common Shares beginning and outstanding	428,516	428,516
(basic)	428,516	428,516
Basic net income (loss) per share	$ (0.06)	$ 0.03

2023 Annual Report

Diluted net income (loss) per share is calculated as follows:

	December 31,	December 31,
(thousands, except as noted)	2023	2022
Net income (loss)	$ (23,708)	$ 14,067
Weighted average number of Common Shares outstanding (basic)	428,516	428,516
Effect of outstanding options (diluted)	–	2,008
Weighted average number of Common Shares outstanding (diluted)	428,516	430,524
Diluted net income (loss) per share	$ (0.06)	$ 0.03

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, 2023, 23.4 million options (December 31, 2022: 20.5 million) were

excluded from the diluted weighted average number of Common Shares outstanding calculation as their effect

would have been anti-dilutive.

15. Petroleum and Natural Gas Revenue

	December 31,	December 31,
($ thousands)	2023	2022
Oil and liquids	$ 36,138	$ 40,910
Natural gas	5,438	9,230
Royalty revenue	125	1,611
	$ 41,701	$ 51,751

16. Employee Salaries and Benefits

	December 31,	December 31,
($ thousands)	2023	2022
Salaries, bonuses and other short -term benefits	$ 2,245	$ 2,123
Share based compensation	1,381	1,931
	$ 3,626	$ 4,054

Questerre Energy Corporation

17. Key Management Compensation

Key management includes directors and officers. The compensation paid or payable to key management is as

follows:

	December 31,	December 31,
($ thousands)	2023	2022
Salaries, bonuses, director fees and other short -term benefits	$ 1,875	$ 1,715
Share based compensation	1,480	2,071
	$ 3,355	$ 3,786

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 $2.4 million at December 31, 2023. This

amount does not include accelerated share based compensation expense.

18. Supplemental Cash Flow Information

Changes in non-cash working capital are detailed below:

	December 31,	December 31,
($ thousands)	2023	2022
Accounts receivable	$ 1,584	$ (584)
Deposits and prepaid expenses	(451)	99
Accounts payable and accrued liabilities	(1,337)	2,179
Change in non -cash working capital	$ (204)	$ 1,694
Related to:
Operating activities	$ 462	$ 2,072
Investing activities	(666)	(378)
	$ (204)	$ 1,694

2023 Annual Report

19. Right-of-use Assets and Lease Liabilities

Right-of-use assets
($ thousands )	Real Estate	Other	Total
Cost
Balance, January 1, 2022, and December 31, 2023	$ 511	$ 25	$ 536
Accumulated Depreciation
Balance, December 31, 2022	$ 278	$ 20	$ 298
Depreciation	53	5	58
Balance, December 31, 2023	$ 331	$ 25	$ 356
Carrying value
Balance, January 1, 2022, and December 31, 2023	$ 233	$ 5	$ 238
Additions, net of depreciation	(53)	(5)	(58)
Balance, December 31, 2023	$ 180	$ 0	$ 180

b) Lease liabilities
($ thousands )
Balance, January 1, 2022	$ 302
Interest expense	5
Lease payments	(57)
Balance, December 31, 2022	$ 250
Interest expense	6
Lease payments	(64)
Balance, December 31, 2023	$ 192
Current portion	58
Long term portion	134
Balance, December 31, 2023	$ 192
Amounts related to lease liabilities recognized in profit or loss are as follows:
Interest expense on lease liabilities	$ 6

20. Commitments

A summary of the Company’s net commitments at December 31, 2023, follows:

($ thousands)	2024	2025	2026	2027	Total
Transportation and Processing	$ 3,429	$ 2,515	$ 1,566	$ 545	$ 8,055