2022 Annual Report

1

President’s Message

We have been building a foundation for our business that does not rely just on our Utica discovery. Our

successes this year in cementing that foundation, reflect our efforts over the past few years.

We took advantage of higher prices to eliminate debt because we prioritized preserving financial liquidity

during the pandemic. We now have a working capital surplus of close to $25 million, representing mainly cash.

We also have an undrawn credit facility of $16 million. This will fund the upcoming 50/50 drilling program at

Kakwa North. We proved up the value of these lands with a successful farmout for an $80 million investment

four years ago. We recently converted our royalty interest to a working interest in the original farm-in wells,

adding just over 700 boe/d in the fourth quarter.

By focusing on capital preservation, the restructuring of our investee company, Red Leaf, was also successful.

They are now well-positioned to advance their new version of the technology that integrates carbon capture

to facilitate a CCUS project. This is a game changer for the future of what was otherwise an energy intensive

process. Plus, taking over the operatorship and 100% equity position of the niche market wax processing

project in Utah has opened up an exciting opportunity.

Despite our efforts to eliminate emissions and build social acceptability, including an agreement with the

Abenaki First Nation, we did not convince the Government of Quebec who was facing an imminent election.

The Government enacted Bill 21, revoking our exploration licenses and effectively nationalizing our discovery

without just compensation. The value of this discovered giant natural gas field to the province of Quebec is

enormous. It is large enough to satisfy domestic demand and supply LNG to Europe through a nearby permitted

facility. It is an unjust enrichment to nationalize it indirectly by breaching the contracts we made with the

province. We are preserving our legal claim and challenging the validity of the law. However, as we have said

consistently, we prefer a political and business solution. We have discovered an enormous source of secure

and reliable energy for the people of Quebec. We look forward to upcoming consultations in Quebec on solving

the impending electricity energy crisis with our Clean Gas and hydrogen solutions.

Highlights

•

Strong financial position with a working capital surplus of close to $25 million and an unutilized credit

facility of $16 million

•

Conversion of royalty interest in Kakwa North farm-in wells add 700 boe/d in the fourth quarter

•

Government of Quebec enacts Bill 21 to revoke oil and gas exploration licenses

•

Before tax NPV-10% of total proved and probable reserves unchanged at $270 million even with a 10%

decrease in volumes to 30 MMBoe

•

Average daily production of 1,714 boe/d and adjusted funds flow from operations of $26.3 million

2

Questerre Energy Corporation

Quebec

We filed our claim against the Government of Quebec just over one year ago. We assert that the Government

has inter alia, fundamentally breached its duty to act in good faith, and in accordance with the due process of

the law, to honor its contractual commitments and its duty to consult with our First Nation partners and respect

their rights. Furthermore, their decision to ban our Clean Gas and hydrogen project that would eliminate

emissions conflicts with a recent Supreme Court of Canada ruling that emissions asserting that climate change

is a worldwide issue requiring global solutions. We anticipate a hearing date for our claim could be set later

this year.

Many of our shareholders have enquired about quantifying the value of our licenses for our claim. We have

commissioned a report to quantify the value of our multi-Tcf gas discovery on the basis that the Government

abided by the law they passed in 2016 and allowed us to proceed with development. This report is privileged

under Canadian law and must be introduced in accordance with the rules of evidence. It will be disclosed in

due course as we validate with our expert witness the possible scenarios as well as the key assumptions

including the pace and likelihood of development and the appropriate discount rate for the expected cash

flows. However, it cannot be disclosed prior to its finalization it in accordance with the Court requirements.

The looming electricity shortage in Quebec is an opportunity for us to still move forward with the Government.

For a province that generates over 90% of its electricity from hydro, this shortage seemed inconceivable only

a few years ago. Yet the Government has recently publicly acknowledged the province will in fact experience

a shortfall. Part of the longer-term solution is the possible construction of additional hydroelectric dams and

alternative energy projects. However, current demand anticipating electrification of the economy, requires

additional energy sources. The alternative is a severe curtailment of industrial and other demand during peak

periods.

Volkswagen recently announced it will locate its battery plant in Ontario. Minister Fitzgibbon recently stated

this was in part because Quebec did not have sufficient electricity supply. We see our Clean Gas and hydrogen

project as a more viable option to maintain Quebec’s economic competitiveness. It would meet their short-

term needs to free up hydroelectricity for heating demand. It would also offer a cheap and environmentally

friendly way to produce hydrogen in the longer term. We continue to engage with stakeholders and the

Government on how our project could meet their needs.

Red Leaf and Jordan

We are seeing some early successes with the engagement of stakeholders for Red Leaf’s wax processing project

in Utah that will upgrade the value of the local waxy oil. They signed a collaboration agreement with the Ute

Tribe, the largest indigenous landholder in the state to supply crude feedstock, market finished products and

provide utilities. Several of the largest producers in the Uintah Basin have expressed an interest in our project

as an opportunity to maximize the value of the light sweet and waxy oil. Although the learning curve is steep,

we are encouraged by the robust business case and the regulatory path forward. The project falls under state

jurisdiction and holds a grandfathered air permit, with the remaining anticipated permits requiring six to nine

months of lead time. There are many more milestones, including securing financing, but we remain optimistic

about this opportunity.

2022 Annual Report

3

We are also optimistic about the prospects for their technology to produce oil from shale that incorporates

carbon capture. This would leverage the cash tax incentives for carbon capture under the US

Inflation

Reduction Act

. Together with Red Leaf, we formed a consortium with two Jordanian companies to assess a 600

to 1,000 bbl/d facility. Early this year, we met with the Government of Jordan to discuss our approach as well

as the amendments necessary for the proposed concession agreement.

Operating & Financial

With three (0.75 net) wells brought on production at Kakwa Central this year, our volumes increased over the

last year. The higher volumes also reflect the conversion of the Kakwa North royalty interest into a working

interest in the fourth quarter. Higher prices generated adjusted funds flow from operations of $26.3 million.

Net of capital investment of $11.6 million in 2022, this resulted in a working capital surplus of $24.5 million.

This surplus also includes the refund of $7.7 million in restricted cash from the Quebec Government. Pending

a ruling on our claim to have Bill 21 declared invalid, we are segregating these funds internally as we are

responsible for reclamation costs under the pre-existing regulations in Quebec.

We only participated in one (0.25 net) of the two (0.50 net) wells drilled by the operator at Kakwa Central this

winter. The expected return on our capital for the second well was challenged by lower commodity prices,

inflation in well costs and their proposed completion design that might not maximize recoveries. As a result,

we expect our production will experience natural declines this year prior to the commencement of the Kakwa

North drilling program of up to three (1.5 net) wells late this fall.

Outlook

With our current liquidity, we are well positioned to participate in the proposed drilling at Kakwa North. If the

operator drills three (1.5 net) wells, we could see our production materially increase in the second half of next

year by over 1,500 boe/d.

We have redoubled our efforts in Quebec. As we follow the legal process, we have met with several European

countries on how our project can provide near-zero emissions natural gas delivered through a permitted LNG

export facility in Quebec to improve their energy security. We have encouraged them to engage with the

Quebec Government on a path forward. We have discussed with Government of Quebec and local business

and other groups how our project could be a solution to their energy crisis. Though the timeline and outcome

of these initiatives is far from certain, we remain committed to crystallizing value for our discovery. We have

also made significant progress with our high impact projects in the Kingdom of Jordan and Utah. Our future is

now less dependent on the Quebec Utica.

Michael Binnion, President and Chief Executive Officer

4

Questerre Energy Corporation

Environmental, Social and Governance

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

From today to 2050, the world’s population is estimated to grow from 7.5 billion to almost 9.5 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. We refer to this as the ‘7 to 9 challenge.’

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 ‘7 to 9 challenge.’

2022 Annual Report

5

Management’s Discussion and Analysis

This Management’s Discussion and Analysis (“MD&A”) was prepared as of March 23, 2023 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, 2022 and 2021. Additional

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

December 31, 2022 dated March 23, 2023 (“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 timing of case management conferences and a hearing of the Company’s claim made in connection

with Quebec’s Bill 21;

•

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

6

Questerre Energy Corporation

•

future commodity prices in light of decisions by OPEC and non-OPEC member countries, including Saudi

Arabia and Russia on production levels, the war in Ukraine, as well as the lingering impacts of COVID-19;

•

legislative and regulatory developments in the Province of Quebec;

•

the enhancement of existing production through workovers and monitoring of the pilot secondary

recovery scheme at Antler;

•

the transfer of wells drilled in 2022 from the proved undeveloped to the proved producing category;

•

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 non-OPEC member countries, including Saudi Arabia and

Russia, on production levels, the war in Ukraine, as well as the lingering impact of COVID-19;

•

access to capital;

•

general economic conditions;

•

the terms and availability of credit facilities;

•

counterparty credit risk;

•

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

•

liabilities inherent in oil and natural gas operations;

2022 Annual Report

7

•

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

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.

8

Questerre Energy Corporation

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)

2022

2021

Net cash from operating activities

$

28,810

$

14,075

Interest received

(568)

(207)

Interest paid

156

433

Change in non-cash working capital

(2,072)

176

Adjusted funds flow from operations

$

26,326

$

14,477

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 (deficit)”. Working capital surplus (deficit), as

presented, does not have any standardized meaning prescribed by GAAP, and may not be comparable with the

calculation of similar measures for other entities. Working capital surplus (deficit), as used by the Company, is

calculated as current assets less current liabilities excluding any outstanding risk management contracts.

2022 Annual Report

9

Select Annual Information

As at/for the years ended December 31,

2022

2021

2020

Financial ($ thousands, except as noted)

Petroleum and Natural Gas Revenue

51,751

30,404

21,924

Adjusted Funds Flow from Operations

26,325

14,477

6,146

Basic and Diluted ($/share)

0.06

0.03

0.01

Net Income (Loss)

14,111

(4,301)

(117,623)

Basic and Diluted ($/share)

0.03

(0.01)

(0.28)

Capital Expenditures

11,591

4,665

5,622

Working Capital Surplus (Deficit)

(1)

24,491

1,834

(7,705)

Total Non-Current Financial Liabilities

191

1,975

2,025

Total Assets

196,486

184,264

196,177

Shareholders' Equity

166,128

148,961

152,120

Common Shares Outstanding (thousands)

428,516

428,516

427,516

Weighted average - basic (thousands)

428,516

428,034

427,613

Weighted average - diluted (thousands)

430,524

428,034

427,613

Operations (units as noted)

Average Production

Crude Oil and Natural Gas Liquids (bbls/d)

1,020

890

1,278

Natural Gas (Mcf/d)

4,167

3,538

4,126

Total (boe/d)

1,714

1,480

1,966

Average Sales Price

(2)

Crude Oil and Natural Gas Liquids ($/bbl)

121.58

84.81

41.80

Natural Gas ($/Mcf)

6.10

3.84

2.51

Total ($/boe)

82.72

56.34

30.47

Netback ($/boe)

Petroleum and Natural Gas Revenue

(3)

82.72

56.34

30.47

Royalties Expense

(3)

(7.72)

(3.46)

(1.83)

Percentage

9%

6%

6%

Operating Expense

(3)

(24.47)

(21.81)

(16.60)

Operating Netback

50.54

31.06

12.04

General and Administrative Expense

(3)

(7.08)

(4.46)

(3.52)

Cash Netback

43.46

26.59

8.52

Wells Drilled

Gross

1.00

3.00

1.00

Net

0.25

0.75

0.25

(1)

Refer to the Current Assets and Current Liabilities in the Balance Sheet for the years ended December 31, 2022 and 2021.

(2)

Refer to Note 15 in the Consolidated Financial Statements for the years ended December 31, 2022 and 2021.

(3)

Refer to Consolidated Statement of Comprehensive Loss and Comprehensive Loss for the years ended December 31, 2022 and 2021.

10

Questerre Energy Corporation

Highlights

•

Strong financial position with a working capital surplus of close to $25 million and an unutilized credit

facility of $16 million

•

Conversion of royalty interest in Kakwa North farm-in wells add 700 boe/d in the fourth quarter

•

Government of Quebec enacts Bill 21 to revoke oil and gas exploration licenses

•

Before tax NPV-10% of total proved and probable reserves unchanged at $270 million even with a 10%

decrease in volumes to 30 MMBoe

•

Average daily production of 1,714 boe/d and adjusted funds flow from operations of $26.3 million

2022 Activities

Western Canada

Kakwa, Alberta

Following the resumption of drilling at Kakwa Central in late 2021, production volumes increased over the prior

year. These 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.

Capital investment in Kakwa totalled $11 million for the year (2021: $3.2 million) with daily production

averaging 1,404 boe/d (2021: 1,174 boe/d) comprising of 4.2 MMcf/d of natural gas (2021: 3.5 MMcf/d) and

720 bbl/d of condensate and natural gas liquids (2021: 589 bbl/d). Total proved and probable reserves as of

December 31, 2022, were estimated at 28.4 MMBoe (2021: 31.5 MMBoe) with a before tax NPV-10% of $247.2

million (2021: $234.2 million). The Company currently holds 40,960 (18,020 net) acres in the Kakwa area.

At Kakwa Central, the operator completed and tied-in three (0.75 net) wells during 2022. Questerre holds a

25% interest in these wells. The operator subsequently spud two wells including one in the first quarter of this

year. Questerre elected to participate in only one of these two wells. The operator has tentatively proposed to

drill up to three (0.75 net) wells in the fourth quarter of this year.

Effective the end of the third quarter last year, the operator of Kakwa North advised that it had recovered

100% of the capital and operating costs associated with the initial four farm-in wells. The Company

subsequently elected to convert its 5% royalty interest in these wells to a 50% working interest. The operator

is proposing up to three (1.5 net) wells commencing 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, 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.

With the exception of routine operating expenditures, including workovers, nominal capital of $0.5 million was

invested during the year (2021: $0.1 million). Daily production averaged 268 bbl/d (2021: 278 bbl/d). Total

proved and probable reserves as at December 31, 2022 were estimated at 1.2 MMBbls (2021: 1.4 MMBbls)

with a before tax NPV-10% of $25.2 million (2021: $36.1 million). The Company currently holds 11,035 net

acres in the area.

2022 Annual Report

11

In 2023, 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 goal is to protect its legal rights following the enactment of Bill 21,

An Act mainly to

end petroleum exploration and production and the public financing of those activities

(“Bill 21”) by the

Government of Quebec. Concurrently, it continues to seek opportunities to work with the Government of

Quebec to advance its Clean Tech Energy project.

Bill 21 was enacted on August 23, 2022. It revokes petroleum exploration and production licences, including

the 16 exploration licenses held by the Company. It provides that the Government must establish a

compensation program pertaining to the revocation of licences. The Act requires, in particular, the holders of

a revoked licence to permanently close wells and restore sites according to the terms and conditions

determined by the Government. Bill 21 validates the regulations made under the authority of the

Petroleum

Resources Act

, certain decisions which effectively limit or prohibit, directly or indirectly, exploration for

petroleum and underground reservoirs and production of petroleum and brine as well as the collection by the

Minister of the annual fees for oil and gas activities.

As a result of the enactment of Bill 21, the Government of Quebec returned to the Company cash security

deposits in the amount of $7.7 million representing the estimated abandonment and reclamation costs

associated with its wells in the province. 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. The Company also continues to carry an asset

retirement obligation for these wells.

The Company subsequently amended its original claim filed earlier in the year to have the Superior Court

declared Bill 21 invalid. In addition to its claim that the Government’s introduction of the regulations in 2018

represent an expropriation without compensation and with no demonstrated public utility, the claim also notes

the violation of the Company’s rights under the

Quebec Civil Code,

the

Quebec Charter of Rights and the

constitution

. The amended application further details the unclear and ambiguous nature of Bill 21, the

Government’s breach of its duty to act in good faith, its duty to honor its contractual commitments and its duty

to consult.

In the fall of 2022, following the request by the Attorney General, the Superior Court of Quebec appointed a

single judge to separately manage all the litigation by licensee holders, including Questerre. The litigation

includes the judicial review application for the regulations of the

Petroleum Resources Act

and the claim for

expropriation referenced above filed in 2018 and 2022, respectively.

In 2023, the parties anticipate holding a series of case management conferences to determine the next steps

in the proceedings as well as the specific items of the respective claims that can be dealt with collectively and

which must be dealt with individually. Subject to the timing and outcome of these conferences, the Company

anticipates a hearing date for its claim could be set later this year.

12

Questerre Energy Corporation

The Company is pursuing available remedies to protect its legal rights and challenge the validity of Bill 21. It is

seeking just compensation for the value of its licenses including the significant natural gas discovery. The

Company plans to assist other stakeholders and partners, including the First Nations and local royalty holders,

to ensure their rights are also protected against the Government’s unconstitutional actions.

Oil Shale Mining

The Company continued to assist its investee, Red Leaf Resources Inc. (“Red Leaf”), to advance their recently

acquired refinery project and their proprietary technology to produce oil from shale.

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$15 million in unrestricted cash as of

December 31, 2022. It also holds freehold surface rights and a permit for a small-scale refinery project. The

Company currently owns approximately 41% of the common share capital of Red Leaf.

Early in 2022, through the exercise of a security interest, Red Leaf acquired 7,300 acres of surface rights in the

oil-producing Uintah Basin in Utah. The lands include a grandfathered state permit for a 40,000 barrel per day

wax processing refinery. It is situated at the terminus of the proposed Uintah Basin Railway to provide the

basin access to markets on the US Gulf Coast.

Red Leaf’s primary focus has been to validate the business case for the project as well as the preliminary

engineering design and cost estimates. The Company recently entered into a collaboration agreement with the

Ute Tribe, a Federally recognized Indian Tribe to jointly develop this project. The agreement includes the

potential supply of utilities to the project, raw crude and marketing of finished products.

Red Leaf has also been advancing its patented technology that was redesigned to incorporate carbon capture

into the process. The company anticipates it will benefit from the tax incentives under the recently introduced

US

Inflation Reduction Act

for carbon capture. During the year, Hatch, a global engineering firm, validated the

new design and identified a path to commercial development. The company is currently designing a small-scale

commercial project as the first phase.

The Company plans to utilize the Red Leaf technology for its project in the Kingdom of Jordan. Given the

ongoing redesign of the technology, limited third party engineering was conducted on its acreage in the

Kingdom in 2022. In conjunction with Red Leaf, the Company is assessing the potential for a small scale

commercial project in Jordan with local partners that could provide both engineering and fabrication services

as well as offtake for the produced crude oil.

Consistent with the prior year, negotiations with the Government of Jordan for the fiscal and other terms of

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.

2022 Annual Report

13

Drilling Activities

During 2022, one (0.25 net) well was spud at Kakwa Central compared to three (0.75 net) wells last year.

Production

2022

2021

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

720

4,167

1,414

589

3,538

1,179

Saskatchewan and Manitoba

300

–

300

301

–

301

1,020

4,167

1,714

890

3,538

1,480

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

Volumes on average increased by just over 15% over the prior year reflecting the higher production at Kakwa.

This includes the addition of the three (0.75 net) new wells at Kakwa Central that were tied-in during the second

quarter and accounted for over 80% of volumes from the area. Kakwa North accounted for the remainder of

the volumes and increased materially in the fourth quarter following the conversion of the royalty interest to

a working interest. Consistent with prior years, Kakwa represented over 80% of corporate volumes.

The product mix from Kakwa is split equally between condensate and other natural gas liquids and natural gas.

In conjunction with the light oil production from Antler and Manitoba, this contributed to a crude oil and liquids

weighting of 60%, unchanged from prior years. Production volumes from these areas were largely flat over the

prior year with the resumption of workovers in a higher price environment that offset natural declines.

With only one (0.25 net) new well at Kakwa Central, the Company anticipates its production will decline over

the prior year. Subject to the timing and participation in the drilling programs here and at Kakwa North, the

Company could see an increase in its volumes in early 2024.

2022 Financial Results

Petroleum and Natural Gas Revenue

2022

2021

Oil and

Natural

Oil and

Natural

($ thousands)

Liquids

Gas

Total

Liquids

Gas

Total

Alberta

$

29,093

$

9,797

$

38,890

$

16,498

$

5,056

$

21,554

Saskatchewan and Manitoba

12,861

–

12,861

8,850

–

8,850

$

41,954

$

9,797

$

51,751

$

25,348

$

5,056

$

30,404

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

Materially higher prices for all commodities were mainly responsible for the substantial increase in petroleum

and natural gas revenue over the prior year. Of the 70% increase in revenue, over three quarters was due to

higher prices with the remainder due to higher production volumes.

14

Questerre Energy Corporation

Pricing

2022

2021

Benchmark prices:

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

5.15

3.37

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

121.49

82.34

Realized prices:

Natural Gas ($/Mcf)

6.10

3.84

Crude Oil and Natural Gas Liquids ($/bbl)

121.58

84.81

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

Crude oil prices rose by nearly 50% over the prior year with the benchmark West Texas Intermediate (“WTI”)

averaging over US$95/bbl compared to US$67/bbl last year.

In the first half of the year, prices increased to their highest levels in more than a decade. This was largely due

to the Russian invasion of Ukraine and its impact on global supplies. Prices declined in the second half of the

year. This was attributable to concerns of a global economic slowdown, the risk of Chinese demand recovery

and the Strategic Petroleum Reserve releases in the United States in response to rising gasoline prices. Prices

were supported by North American producers exercising capital discipline relative to growth and OPEC’s

compliance with its production quotas. In Canada, increasing export demand contributed to tightening

differentials. In 2022, the discount between WTI and the Canadian benchmark Edmonton Mixed Sweet Blend

(“MSW”) was US$1.82/bbl compared to US$3.88/bbl in 2021.

Realized prices for Questerre’s light oil and natural gas liquids track the MSW benchmark with condensate

receiving a premium and other liquids receiving a discount.

Natural gas prices experienced a similar increase over the prior year. The benchmark Henry Hub averaged

US$6.44/MMBtu compared to US$3.91/MMBtu last year.

Prices reflected the tightening supply demand balance. Although US dry gas production grew over the prior

year by over 3% or 3 Bcf/d, it was outpaced by demand for domestic consumption and exports. Demand grew

by over 5% or 4.4 Bcf/d in all categories including power generation and residential and commercial. US LNG

exports also grew as Europe competed with Asia for supplies to reduce their dependence on Russian gas.

Canadian natural gas prices saw a similar increase but lagged US prices due to volatile differentials. This was

attributable to delayed pipeline expansions and ongoing maintenance issues on the primary pipeline system in

Western Canada, particularly in the third quarter.

Realized natural gas prices, reflecting the higher heat content from Kakwa production, averaged $6.10/Mcf

(2021: $3.84/Mcf) compared to the AECO benchmark price of $5.15/Mcf (2021: $3.37/Mcf).

2022 Annual Report

15

Royalties

($ thousands)

2022

2021

Alberta

$

3,882

$

1,232

Saskatchewan and Manitoba

950

637

$

4,832

$

1,869

% of Revenue:

Alberta

10%

6%

Saskatchewan and Manitoba

7%

7%

Total Company

9%

6%

Gross royalties increased over the prior year due to both higher commodity prices and effective royalty rates

on production in Alberta. As a percentage of revenue this increased to 9% this year from 6% last year.

In Alberta, royalties increased over twofold due to the expiration of prior Crown incentive programs. This

resulted in Crown royalties of 40% on condensate production from older vintage wells. By comparison newer

wells benefit from incentives and record royalty rates of 5% on condensate production.

As the effective rate remained unchanged from last year, royalties on production in Saskatchewan and

Manitoba increased commensurate with the change in revenue.

Operating Costs

($ thousands)

2022

2021

Alberta

$

11,310

$

8,479

Saskatchewan and Manitoba

3,511

2,795

Quebec

485

506

$

15,306

$

11,780

$/boe:

Alberta

21.90

19.71

Saskatchewan and Manitoba

32.15

25.44

Total Company

$

24.47

$

21.81

Inflationary pressures on general industry costs and higher production volumes at Kakwa contributed to an

overall 30% increase over the prior year.

Operating costs at Kakwa reflect both higher costs at the Kakwa Central joint venture, particularly related to

fuel and power and well workovers, as well as operating costs for Kakwa North and an associated area following

the conversion of the royalty interest into a working interest. On a unit of production basis, this increase was

offset by higher production volumes and resulted in a 10% increase to just under $22 per boe from $20 per

boe last year.

16

Questerre Energy Corporation

At Antler, in addition to higher fuel and power expense, higher costs were incurred for workovers as well as

chemicals with a new program designed to mitigate the frequency of workovers. Operating costs in Quebec

remained flat and represent the maintenance costs associated with the assets in the province.

General and Administrative Expenses

($ thousands)

2022

2021

General and administrative expenses, gross

$

4,655

$

3,454

Capitalized expenses and overhead recoveries

(228)

(1,045)

General and administrative expenses, net

$

4,427

$

2,409

Gross General & Administrative expenses (“G&A”) increased by 30% to $4.7 million from $3.5 million last year.

Higher expenses were incurred in several categories, including salaries and benefits, as well as government and

public relations related to the Company’s project in Quebec. Capitalized expenses are overhead costs

associated with the Company’s projects in Montney, Alberta and Jordan. These decreased substantially in the

current year following the impairment of the Quebec assets in 2021.

Depletion, Depreciation, Impairment, Accretion and Lease Expiries

For the year ended December 31, 2022, the Company recorded depletion, depreciation, and accretion expense

of $9.9 million (2021: $6.1 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. The carrying value of its assets in the current year reflect the reversal of

previously incurred impairment expense of $91.7 million last year as detailed below. On a unit of production

basis this increased to $15.25/boe from $10.71/boe last year.

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

31, 2022 for indicators of impairment or indicators to reverse previously recorded 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 the CGUs was estimated based on the fair value less

costs of disposal (“FVLCD”) using a discounted cash flow model. Due to the increase in future operating costs

reducing the value of the reserves at Antler, Saskatchewan the Company recorded an impairment expense of

$0.9 million. No impairment expense was recorded with respect to its other CGUs.

In 2021, due to the higher future commodity prices, the Company recorded a reversal of $91.7 million of

previously impaired expenses. Of this amount, $76 million was attributed to the Kakwa, Alberta CGU and $15.7

million was attributed to the Antler, Saskatchewan CGU. No impairment reversals were recorded for the

Company’s other CGUs.

The Company assessed the carrying value of its exploration and evaluation (“E&E”) assets and noted no

indicators of impairment. In 2021, as a result of the introduction of Bill 21 in Quebec, the Company impaired

the full carrying value of its E&E assets of $104 million.

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

2022 Annual Report

17

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 $1.9 million (2021: $0.5 million) net of $0.3

million (2021: $0.7 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.

During the year as a result of the reduction in the net asset value, the Company recorded an expense of $2.5

million (2021: Nil). For more information, please see Note 7 to the Financial Statements.

Other Income and Expenses

The Company incurred interest expense of $0.2 million (2021: $0.4 million) related to its credit facilities with a

Canadian chartered bank. The amount drawn on the facilities at year-end was essentially nil (2021: $3.4 million)

and the effective interest rate was 5.33% (2021: 3.45%). The Company also earned interest income of $0.04

million on its cash and term deposits (2021: $0.2 million).

Included in other income is $1.8 million reflecting the discharge of a contingent liability related to the

acquisition of assets in Quebec completed in 2019.

Other Comprehensive Income (Loss)

In 2022, the Company recorded other comprehensive income of $0.8 million (2021: $0.1 million loss) related

to the change in foreign exchange rates. A gain of $0.3 million in the current year (2021: $0.04 million loss) was

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

gain of $0.5 million (2021: $0.02 million loss) due to the appreciation in the Jordanian dinar impacting its dinar-

denominated assets in Jordan.

Total Comprehensive Income (Loss)

For the year ended December 31, 2022, the Company recorded net income of $14.1 million compared to a loss

of $4.3 million last year. As expenses in aggregate remained unchanged over the prior year, the increase in the

current year is due to the materially higher petroleum and natural gas revenue.

Including other comprehensive income, total comprehensive income increased to $14.9 million from a loss of

$4.4 million last year.

Cash Flow from Operating Activities

The Company recorded cash flow from operating activities of $28.8 million (2021: $14.1 million). The variance

over last year is due to the higher adjusted flow from operations from higher net income offset partly by the

increase in non-cash working capital compared to a decrease in the prior year.

18

Questerre Energy Corporation

Cash Flow used in Investing Activities

Cash flow used in investing activities increased to $12 million from $3.8 million last year. This is attributable to

the higher capital investment at Kakwa and, to a less extent, the reduction in non-cash working capital

compared to an increase last year.

Cash Flow provided by Financing Activities

In 2022, the Company reported net cash used in financing activities of $3.4 million, representing the net

reduction in borrowing under its credit facility. In the prior year, the Company reduced its borrowings by $11.9

million. Amounts in 2021 also include $0.2 million related to the exercise of stock options.

Capital Expenditures

($ thousands)

2022

2021

Alberta

$

10,955

$

3,220

Saskatchewan, Manitoba and Jordan

522

120

Quebec

114

1,325

Total

$

11,591

$

4,665

Notes:

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

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

;

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.

For the year ended December 31, 2021, the Company incurred capital expenditures of $4.7 million as follows:

In Alberta, $3.3 million for drilling three (0.75 net) wells on the Kakwa Central joint venture;

In Quebec, $1.3 million for well monitoring and capitalized overhead related to advancing social

acceptability and engineering for its Clean Tech Energy project; and

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

In the last quarter of 2022, petroleum and natural gas revenue increased by over 50% to $13.6 million from

$8.9 million in the same period last year. Over 90% of this increase was attributed to the increase in production

volumes with the remainder due to the increase in commodity prices.

The conversion of the royalty interest to a working interest in the four original farm-in wells at Kakwa North

were responsible for the increase in production volumes in the fourth quarter to 2,023 boe/d from 1,398 boe/d

last year. Consistent with the fiscal year, benchmark pricing for both oil and gas increased over the prior year

but decreased over the preceding quarter. The differential between WTI and Canadian condensate prices

remained a premium but decreased over the prior year.

Operating costs for the quarter increased by almost 50% to $5.3 million from $3.7 million last year. While

expenses remained stable in Saskatchewan, Manitoba and Quebec, the increase was attributable to higher

2022 Annual Report

19

costs at Kakwa. These largely reflect the operating costs associated with the new production volumes at Kakwa

North. This increase in gross costs was offset by the higher volumes resulting in no changes on a boe basis from

the prior year.

Including impairment relating to its Antler, Saskatchewan CGU and other income of $2.1 million, the Company

reported a net loss of $0.1 million and total comprehensive loss of $0.5 million for the quarter. By comparison

in 2021, the Company reported a net loss of $10.1 million and total comprehensive loss of $10.2 million. The

quarterly loss in the current year is attributed to the change in foreign exchange related to the carrying value

of its investment in Red Leaf and Jordan. The loss in the prior year was attributable to the impairment of the

full carrying value of its E&E assets in Quebec of $104 million offset by the reversal of previously incurred

impairment of its PP&E assets of $92 million in the quarter due to higher future commodity prices.

In the fourth quarter, net cash from operating activities increased to $5.3 million from $3.8 million last year.

This reflects the higher adjusted funds flow from operations over the prior year and a material increase in non-

cash working capital. Net cash used in investing activities increased over the prior year quarter with higher

capital spending. No cash was used in financing activities compared to the prior year when the Company

reduced borrowings under its credit facility by $4 million.

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, 2022, there were effectively no borrowings under its credit facility (December 31, 2021: $3.4

million) 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, 2022 was 6.13 and the covenant was

met. See Note 13 of the Financial Statements.

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

scheduled during the second quarter of 2023. 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 2023 future development costs associated with proved reserves in its

independent reserves assessment as of December 31, 2022. It anticipates that, as a result, reserves associated

with wells drilled in 2023 will be transferred from the proved undeveloped to the proved producing category.

20

Questerre Energy Corporation

For a detailed discussion of the risks and uncertainties associated with the Company’s business and operations,

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

Share Capital

The Company is authorized to issue an unlimited number of Common Shares. The Company is also authorized

to issue an unlimited number of Class “B” Common voting shares and an unlimited number of preferred shares,

issuable in one or more series. At December 31, 2022, 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 23,

December 31,

December 31,

(thousands)

2023

2022

2021

Common Shares

428,516

428,516

428,516

Stock Options

46,738

35,298

30,308

Weighted average Common Shares

Basic

428,516

428,034

Diluted

430,524

428,034

A summary of the Company’s stock option activity during the years ended December 31, 2022 and 2021

follows:

December 31, 2022

December 31, 2021

Number of

Weighted

Number of

Weighted

Options

Average

Options

Average

(thousands)

Exercise Price

(thousands)

Exercise Price

Outstanding, beginning of period

30,308

$

0.35

25,351

$

0.38

Granted

11,490

0.34

8,350

0.18

Forfeited

–

–

(2,343)

0.18

Expired

(6,500)

0.69

(50)

0.18

Exercised

–

–

(1,000)

0.18

Outstanding, end of period

35,298

$

0.28

30,308

$

0.35

Exercisable, end of period

22,643

$

0.28

20,866

$

0.42

Commitments

A summary of the Company’s net commitments at December 31, 2022 follows:

($ thousands)

2023

2024

2025

2026

Total

Transportation and Processing

$

3,162

$

2,884

$

2,015

$

1,240

$

9,301

2022 Annual Report

21

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, 2022.

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

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.

22

Questerre Energy Corporation

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 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.

2022 Annual Report

23

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 $0.05 million at December 31, 2022 for its expected credit losses related to its accounts receivable.

Receivables from joint venture partners are typically collected within one to three months after the joint

venture bill is issued. The Company mitigates this risk by obtaining pre-approval of significant capital

expenditures.

The Company has issued and may continue in the future to issue flow-through shares to investors. The

Company has historically used its best efforts to ensure that qualifying expenditures of Canadian Exploration

Expense ("CEE") are incurred in order to meet its flow-through obligations. In 2017, the Federal Government

amended the law regarding what expenses constitute CEE. Generally, oil and gas drilling expenses are now

Canadian Development Expense rather than CEE. In the event that the Company has CEE expenditures

reclassified under audit by the Canada Revenue Agency or fails to incur expenditures required under a flow-

through share agreement, the Company may be required to liquidate certain of its assets in order to meet the

indemnity obligations under flow-through share subscription agreements.

Exploration and development drilling risks are managed through the use of geological and geophysical

interpretation technology, employing technical professionals and working in areas where those individuals

have experience. For its non-operated properties, the Company strives to develop a good working relationship

with the operator and monitors the operational activity on the property. The Company also carries appropriate

insurance coverage for risks associated with its operations.

The Company may use financial instruments to reduce corporate risk in certain situations. Questerre’s hedging

policy is up to a maximum of 40% of total production at management’s discretion.

As at December 31, 2022, 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

24

Questerre Energy Corporation

that well and facility sites are abandoned and reclaimed to the satisfaction of provincial authorities. As well,

applicable environmental laws may impose remediation obligations with respect to property designated as a

contaminated site upon certain responsible persons, which include persons responsible for the substance

causing the contamination, persons who caused the release of the substance and any past or present owner,

tenant or other person in possession of the site. Compliance with such legislation can require significant

expenditures, and a breach of such legislation may result in the suspension or revocation of necessary licenses

and authorizations, civil liability for pollution damage, the imposition of fines and penalties or the issuance of

clean-up orders. The Company mitigates the potential financial exposure of environmental risks by complying

with the existing regulations and maintaining adequate insurance. For more information, please refer to the

“Risk Factors” and “Industry Conditions” sections of the AIF.

Climate change policy is evolving at regional, national and international levels, and political and economic

events may significantly affect the scope and timing of climate change measures that are ultimately put in

place. The federal and certain provincial governments have implemented legislation aimed at incentivizing the

use of alternative fuels and in turn reducing carbon emissions. The taxes placed on carbon emissions may have

the effect of decreasing the demand for oil and natural gas products and at the same time, increasing the

Company’s operating expenses, each of which may have a material adverse effect on the Company’s

profitability and financial condition. Further, the imposition of carbon taxes puts the Company at a

disadvantage with the Company’s counterparts who operate in jurisdictions where there are less costly carbon

regulations

.

Interest Rate Risk

Interest rate risk is the risk that changes in the applicable interest rates for its credit facilities will impact the

Company’s interest expense. At December 31, 2022, the Company had credit facilities outstanding effectively

of nil (December 31, 2021: $3.4 million) with an effective rate of 5.33% (2021: 3.45%).

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

2022 Annual Report

25

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

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

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

are evaluated by independent reserve engineers at least annually.

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

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

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

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

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

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

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

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

and the calculation of depletion.

Cash Generating Units

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

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

significant judgment and interpretations. Factors considered in the classification include geography and the

way management monitors and makes decisions about its operations.

Impairment of Property, Plant and Equipment, Exploration and Evaluation 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 higher of value in use (“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.

26

Questerre Energy Corporation

Asset Retirement Obligation

Determination of the Company’s asset retirement obligation is based on Government regulations, operator

estimates, internal estimates using current costs and technology in accordance with existing legislation and

industry practice and must also estimate timing, a risk-free rate and inflation rate in the calculation. These

estimates are subject to change over time and, as such, may impact the charge against profit or loss. The

amount recognized is the present value of estimated future expenditures required to settle the obligation using

a risk-free rate. The associated abandonment and retirement costs are capitalized as part of the carrying

amount of the related asset. The capitalized amount is depleted on a unit of production basis in accordance

with the Company’s depletion policy. Changes to assumptions related to future expected costs, risk-free rates

and timing may have a material impact on the amounts presented.

Share Based Compensation

The Company has a stock option plan enabling employees, officers and directors to receive Common Shares or

cash at exercise prices equal to the market price or above on the date the option is granted. Under the equity

settled method, compensation costs attributable to stock options granted to employees, officers or directors

are measured at fair value using the Black-Scholes option pricing model. The assumptions used in the

calculation are: the volatility of the stock price, risk-free rates of return and the expected lives of the options.

A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that

vest. Changes to assumptions may have a material impact on the amounts presented.

Income Tax Accounting

Deferred tax assets are recognized when it is considered probable that deductible temporary differences will

be recovered in the foreseeable future. To the extent that future taxable income and the application of existing

tax laws in each jurisdiction differ significantly from the Company’s estimate, the ability of the Company to

realize the deferred tax assets could be impacted.

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.

2022 Annual Report

27

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, 2022.

•

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, 2022 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,

2022 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.

.

Quarterly Financial Information

December 31,

September 30,

June 30,

March 31,

($ thousands, except as noted)

2022

2022

2022

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

428,516

428,516

428,516

Diluted (thousands)

428,516

430,727

428,747

432,112

28

Questerre Energy Corporation

December 31,

September 30,

June 30,

March 31,

($ thousands, except as noted)

2021

2021

2021

2021

Production (boe/d)

1,398

1,363

1,479

1,679

Average Realized Price ($/boe)

69.11

58.83

52.72

46.62

Petroleum and Natural Gas Revenue

8,887

7,376

7,095

7,046

Adjusted Funds Flow from Operations

3,790

3,578

4,224

2,885

Net Profit (Loss)

(10,107)

2,006

2,892

908

Basic and Diluted ($/share)

(0.02)

–

0.01

–

Capital Expenditures, net of acquisitions and dispositions

3,177

541

450

497

Working Capital Surplus (Deficit)

1,834

1,698

(1,243)

(5,449)

Total Assets

184,264

192,709

194,053

194,417

Shareholders' Equity

148,961

158,922

156,316

153,108

Weighted Average Common Shares Outstanding

Basic (thousands)

428,516

428,516

427,571

427,516

Diluted (thousands)

428,516

428,516

427,743

427,879

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

•

Petroleum and natural gas revenues and adjusted funds flow from operations have fluctuated with

production volumes and realized commodity prices. Revenue has begun increasing in the last five quarters

due to the recovery in commodity prices.

•

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

quarters. In the fall of 2021, with the increase in prices, capital investment increased in the fourth quarter.

Prior thereto, with non-essential capital investment largely suspended during the pandemic, production

volumes declined.

•

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.

•

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. It

decreased in the fourth quarter of 2021 as a result of the impairment related to its investment in Quebec.

Off-Balance Sheet Transactions

The Company did not engage in any off-balance sheet transactions during the year ended December 31, 2022.

Related Party Transactions

The Company paid fees of $0.1 million in 2022 (2021: $0.2 million) to a law firm where a Director of the

Company is currently a partner.

2022 Annual Report

29

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

Calgary, Alberta, Canada

March 23, 2023

30

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, 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 year then ended, and notes to the consolidated financial statements, including

a summary of significant accounting policies.

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, 2022, and its consolidated financial

performance and its consolidated cash flows for the year 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.

2022 Annual Report

31

Key audit matter

How our audit addressed the key audit matter

Impairment of property, plant and equipment

As at December 31, 2022, the carrying amount of property,

plant and equipment in the Western Canada operating

segment was $141.1 million. Property, plant and equipment

is tested for impairment only when circumstances indicate

that the carrying amount of a Cash Generating Unit (“CGU”)

may

exceed

its

recoverable

amount.

As

impairment

indicators existed 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, 2022, an impairment of

$0.9 million was recorded with respect to property, plant and

equipment in the Antler, Saskatchewan CGU. Refer to Note

2(e) for a description of the Company’s estimates and

judgements relating to impairment and to Note 3(f) for a

description of the Company’s impairment of non-financial

assets accounting policy. Refer to Note 8 for the Company’s

property, plant and equipment impairment disclosures.

Auditing the Company’s estimated recoverable 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 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 a fair value less

costs of disposal model based on expected after-tax future

net cash flows from the production of proved plus probable

reserve volumes using forecast commodity prices and costs,

discounted using market-based rates. Proved plus probable

reserves were determined by the Company’s independent

petroleum engineers (management’s experts).

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

methodology applied, and the various inputs utilized

in

determining

the

after-tax

discount

rate

by

referencing

current

industry,

economic,

and

comparable company information, as well as company

and cash-flow specific risk premiums;

•

With

the

assistance

of

our

internal

valuation

specialists, we compared the market capitalization to

net assets and observed quantitative and qualitative

reconciliations using market data and transactions;

•

Compared forecasted benchmark commodity pricing

against historical realized prices and to other third-

party price forecasts;

•

Assessed forecasted production, royalties, operating

costs, and future development costs by comparing

them to historical results; and

•

Evaluated the adequacy of the impairment note

disclosure included in Note 8 of the accompanying

consolidated financial statements in relation to this

matter.

Other Information

Management is responsible for the other information. The other information comprises:

•

Management’s Discussion and Analysis

•

Annual report, other than the financial statements and our auditor’s report thereon

32

Questerre Energy Corporation

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,

as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of

internal control.

2022 Annual Report

33

•

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.

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

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

that we identify during our audit.

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

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

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

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

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

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

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

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

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

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

/s/ Ernst and Young LLP

Chartered Professional Accountants

Calgary, Alberta Canada

March 23, 2023

34

Questerre Energy Corporation

Consolidated Balance Sheets

December 31,

December 31,

($ thousands)

Note

2022

2021

Assets

Current Assets

Cash and cash equivalents

5

$

29,590

$

8,531

Accounts receivable

6

4,600

4,016

Deposits and prepaid expenses

968

1,068

35,158

13,615

Right-of-use assets

19

238

196

Investments

7

5,796

7,965

Property, plant and equipment

8

141,067

140,120

Exploration and evaluation assets

9

14,227

14,710

Restricted cash

13

–

7,658

$

196,486

$

184,264

Liabilities

Current Liabilities

Lease liabilities

19

$

59

$

52

Accounts payable and accrued liabilities

10,634

8,361

Current portion of asset retirement obligation

12

484

–

Credit Facilities

13

33

3,420

11,210

11,833

Lease liabilities

19

191

155

Contingent liabilities

–

1,820

Asset retirement obligation

12

18,957

21,495

30,358

35,303

Shareholders' Equity

Share capital

14

429,878

429,878

Contributed surplus

26,301

24,068

Accumulated other comprehensive income (loss)

296

(527)

Deficit

(290,347)

(304,458)

166,128

148,961

$

196,486

$

184,264

Commitments (note 20)

Signed on behalf of the Board of Directors

Bjorn Inge Tonnessen, Director

Dennis Sykora, Director

2022 Annual Report

35

Consolidated Statements of Net Income (Loss) and Comprehensive

Income (Loss)

For the year ended December 31,

($ thousands, except per share amounts

)

Note

2022

2021

Revenue

Petroleum and natural gas revenue

15

$

51,751

$

30,404

Royalties

(4,832)

(1,869)

Petroleum and natural gas revenue, net of royalties

46,919

28,535

Expenses

Direct operating

15,306

11,780

General and administrative

4,427

2,409

Depletion, depreciation and accretion

8,12,19

9,900

6,094

Impairment

8,9

857

12,111

Lease expiries

9

129

220

Loss on equity investment

7

2,540

–

Share based compensation

11

1,891

476

Interest expense

156

433

Interest and other income

(2,354)

(680)

Income (loss) before taxes

14,067

(4,308)

Deferred tax expense (recovery)

10

(44)

(7)

Net income (loss)

14,111

(4,301)

Other Comprehensive Income (Loss), Net of Tax

Items that may be reclassified subsequently to profit or loss:

Foreign currency translation adjustment

496

(17)

Income (loss) on foreign exchange on investments

7

327

(37)

823

(54)

Total Comprehensive Income (Loss)

$

14,934

$

(4,355)

Net Income (Loss) per Share

Basic and diluted

14

$

0.03

$

(0.01)

36

Questerre Energy Corporation

Consolidated Statements of Changes in Equity

For the year ended December 31,

($ thousands)

2022

2021

Share Capital

Balance, beginning of year

$

429,878

$

429,703

Options exercised

-

175

Balance, end of year

429,878

429,878

Contributed Surplus

Balance, beginning of year

24,068

23,047

Share based compensation

2,233

1,021

Balance, end of year

26,301

24,068

Accumulated Other Comprehensive Income (Loss)

Balance, beginning of year

(527)

(473)

Other comprehensive income (loss)

823

(54)

Balance, end of year

296

(527)

Deficit

Balance, beginning of year

(304,458)

(300,157)

Net income (loss)

14,111

(4,301)

Balance, end of year

(290,347)

(304,458)

Total Shareholders' Equity

$

166,128

$

148,961

2022 Annual Report

37

Consolidated Statements of Cash Flows

For the years ended December 31,

($ thousands)

Note

2022

2021

Operating Activities

Net income (loss)

$

14,111

$

(4,301)

Adjustments for:

Depletion, depreciation and accretion

8,12,19

9,900

6,094

Impairment

8,9

857

12,111

Lease expiries

8,9

129

220

Loss on equity investment

7

2,540

–

Share based compensation

11

1,891

476

Deferred tax expense (recovery)

10

(44)

(7)

Interest expense

156

433

Interest and other income

(2,336)

(359)

Abandonment expenditures

12

(878)

(190)

26,326

14,477

Interest expense

(156)

(433)

Interest income

568

207

Change in non-cash working capital

18

2,072

(176)

Net cash from operating activities

28,810

14,075

Investing Activities

Property, plant and equipment expenditures

8

(2,779)

(502)

Exploration and evaluation expenditures

9

(8,812)

(4,163)

Change in non-cash working capital

18

(378)

904

Net cash used in investing activities

(11,969)

(3,761)

Financing Activities

Proceeds from issue of share capital

–

175

Principal portion of lease payments

19

(53)

(53)

Increase in credit facilities

13

5,413

17,993

Repayment of credit facilities

13

(8,800)

(30,000)

Net cash used in financing activities

(3,440)

(11,885)

Change in cash, cash equivalents and restricted cash

13,401

(1,571)

Cash, cash equivalents and restricted cash, beginning of year

16,189

17,760

Cash, cash equivalents and restricted cash, end of year

$

29,590

$

16,189

The notes are an integral part of these consolidated financial statements

38

Questerre Energy Corporation