Questerre Energy

Management Discussion and Analysis • Aug 9, 2025

Management's Discussion and Analysis

This Management's Discussion and Analysis ("MD&A") was prepared as of August 8, 2025. This interim MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements of Questerre Energy Corporation ("Questerre" or the "Company") for the three and six month periods ended June 30, 2025, and 2024, and the audited annual consolidated financial statements of the Company for the year ended December 31, 2024, and the MD&A prepared in connection therewith. Additional information relating to Questerre, including Questerre's Annual Information Form ("AIF") for the year ended December 31, 2024, is available on SEDAR under Questerre's profile at www.sedarplus.ca.

Questerre is an energy technology and innovative company actively involved in the acquisition, exploration and development of oil and gas projects, and, in specific, non-conventional projects such as tight oil, oil shale, shale oil and shale gas. Questerre is committed to the economic development of its resources in an environmentally conscious and socially responsible manner. The Company's Class "A" Common voting shares ("Common Shares") are listed on the Toronto Stock Exchange and the Oslo Stock Exchange under the symbol "QEC".

Basis of Presentation

Questerre presents figures in the MD&A using accounting policies within the framework of International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"), 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 forwardlooking statements. Forward-looking statements are often, but not always, identified using the use of words such as "anticipate", "assume", "believe", "budget", "can", "commitment", "continue", "could", "estimate", "expect", "forecast", "foreseeable", "future", "intend", "may", "might", "plan", "potential", "project", "will" and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Management believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. These statements speak only as of the date of this MD&A.

This MD&A contains forward-looking statements including, but not limited to, those pertaining to the following:

• anticipated benefits of the Acquisition to the Company and its shareholders, including any operational and economic synergies;

• active discussions with prospective local partners for up to 50% of the Acquisition;
• the timing and receipt of any required securityholder, third-party (including, satisfactory waivers by the bondholders and convertible noteholders), stock exchanges, or regulatory approvals required to complete the Acquisition;
• the ability of the Company and PX Energy to satisfy the conditions to, and to negotiate and execute a definitive agreement and to complete, the Acquisition, including due diligence review and board approval;
• the form of the Quebec Spin-out, and any changes to the anticipated structure thereof;
• the closing of the Acquisition and the Quebec Spin-out, including the timing thereof, if it is to close at all;
• PX Energy's predicted production rates, and its production at similar rates upon completion of the Acquisition;
• the achievement of the performance milestones attached to the consideration payable, and the timing thereof, if at all;
• drilling plans and the development and optimization of producing assets;
• the judicial plans to achieve a hearing of the Company's claim made in connection with Quebec's Bill 21 and the questioning of key government representatives;
• working collaboratively to find a political and business solution with the Government of Quebec;
• future production of oil, natural gas and natural gas liquids;
• future commodity prices in light of decisions by OPEC and its allies, including Saudi Arabia and Russia on production levels, the war in Ukraine, and the conflict in the Middle East;
• legislative and regulatory developments in the Province of Quebec;
• the transfer of wells drilled in 2025 from the proved undeveloped to the proved producing category;
• the Company plans for a carbon storage pilot project under Bill 21;
• hedging policy;
• the impact on natural gas prices from the commissioning of the LNG Canada project;
• liquidity and capital resources;
• the Company's plans to utilize the Red Leaf technology for its project in Jordan;
• the Company's compliance with the terms of its credit facility;
• timing of the next review of the Company's credit facility by its lender;
• ability of the Company to meet its foreseeable obligations;
• capital expenditures and the funding thereof;
• impacts of capital expenditures on the Company's reserves;
• commitments and Questerre's participation in future capital programs;
• risks and risk management;
• potential for equity and debt issuances and farm-out arrangements;
• counterparty creditworthiness;
• the timing of receivables from joint venture partners;
• flow-through shares and use of proceeds and renunciation and indemnity obligations associated therewith;
• insurance;
• use of financial instruments; and
• critical accounting estimates.

The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A, the AIF, and the documents incorporated by reference into this document:

• the Acquisition not being completed on the terms anticipated or at all, including due to a closing condition not being satisfied, including, the inability to obtain receipt of all necessary securityholder, third parties (including satisfactory waivers by the bond holders and convertible noteholders), stock exchanges, and regulatory approvals or consents, unsatisfactory due diligence, no receipt of board approval;
• negative impacts if a local partner is not found to participate in 50% of the Acquisition;
• the Quebec Spin-out not being completed on the terms anticipated or at all;
• the synergies expected from the Acquisition not being realized;
• loss of key personnel of PX Energy upon completion of the Acquisition;
• potential tariffs and counter tariffs on trade with the United States and other countries;
• Quebec's Bill 21, the revocation of licenses in Quebec and potential compensation;
• volatility in market prices for oil, natural gas liquids and natural gas due to, among other things, the production agreements between OPEC and its allies, including Saudi Arabia and Russia, on production levels, the war in Ukraine, and the conflict in the Middle East;
• access to capital;
• general economic conditions;
• the terms and availability of credit facilities;
• counterparty credit risk;
• changes or fluctuations in oil, natural gas liquids and natural gas production levels;
• liabilities inherent in oil and natural gas operations;
• adverse judicial rulings, regulatory rulings, orders and decisions;
• attracting, retaining and motivating skilled personnel;
• uncertainties associated with estimating oil and natural gas reserves and resources;
• insufficient advancement by Red Leaf in the engineering of its proprietary process;
• competition for, cost and availability of, among other things, capital, acquisitions of reserves, undeveloped lands, equipment, skilled personnel and services;
• incorrect assessments of the value of acquisitions and targeted exploration and development assets;
• fluctuations in foreign exchange or interest rates;
• stock market volatility, market valuations and the market value of the securities of Questerre;
• failure to realize the anticipated benefits of acquisitions;
• actions by governmental or regulatory authorities, including changes in royalty structures and programs, and income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry;
• limitations on insurance;
• changes in environmental, tax, or other legislation applicable to the Company's operations, and its ability to

comply with current and future environmental and other laws; and

• geological, technical, drilling and processing problems, and other difficulties in producing oil, natural gas liquids and natural gas reserves.

Statements relating to reserves are by their nature deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future.

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 ("Mcf") to one barrel of oil ("bbl"), and the conversion ratio of one barrel to six thousand cubic feet is based on an energy equivalent conversion method application at the burner tip and does not necessarily represent an economic value equivalent 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 six to one, utilizing a conversion on a six to one basis may be misleading as an indication of value.

Non-GAAP Measures

This document contains certain financial measures, as described below, which do not have standardized meanings prescribed under GAAP. As these measures are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.

This document contains the term "adjusted funds flow from operations", which is a 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. 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.

Adjusted Funds Flow From Operations Reconciliation

	Three months ended June 30,			Six months ended June			30,
(\$ thousands)		2025		2024		2025		2024
Net cash from operating activities	\$	6,288	\$	3,141	\$	9,646	\$	5,769
Change in non-cash operating working capital		(1,283)		1,314		(1,099)		1,659
Adjusted Fund Flow from Operations(1)	\$	5,005	\$	4,455	\$	8,547	\$	7,428

(1) Adjusted Funds Flow from Operations is a non-GAAP measure defined as cash flows from operating activities before changes in noncash operating working capital.

This document also contains the terms "operating netbacks", "cash netbacks" and "working capital surplus", which are non-GAAP measures.

The Company considers netbacks a key measure as it demonstrates its profitability relative to current commodity prices. Operating and cash netbacks, as presented, do not have any standardized meaning prescribed by GAAP and may not be comparable with the calculation of similar measures for other entities. Operating netbacks have been defined as revenue less royalties, transportation and operating costs. Cash netbacks have been defined as operating netbacks less general and administrative costs. Netbacks are generally discussed and presented on a per boe basis.

The Company also uses the term "working capital surplus". Working capital surplus, as presented, does not have any standardized meaning prescribed by GAAP, and may not be comparable with the calculation of similar measures for other entities. Working capital surplus, as used by the Company, is calculated as current assets less current liabilities excluding any outstanding risk management contracts and lease liabilities.

Select Information

		Three months ended June 30,
As at/for the period ended,	2025	2024	2025	2024
Financial (\$ thousands, except as noted)
Petroleum and Natural Gas Sales	13,675	8,847	22,805	17,845
Net Income (Loss)	(677)	1,262	(673)	1,087
Adjusted Funds Flow from Operations(1)	5,005	4,455	8,547	7,428
Cash Flow from Operations	6,288	3,141	9,646	5,769
Basic and diluted (\$/share)	0.01	0.01	0.02	0.02
Capital Expenditures	1,048	7,034	18,912	9,664
Working Capital Surplus(2)	13,157	27,620	13,157	27,620
Total Assets	169,976	179,248	169,976	179,248
Shareholders' Equity	138,355	145,941	138,355	145,941
Common Shares Outstanding (thousands)	428,516	428,516	428,516	428,516
Weighted average - basic (thousands)	428,516	428,516	428,516	428,516
Weighted average - diluted (thousands)	431,505	431,327	431,593	431,248
Operations (units as noted)
Average Production
Crude Oil and Natural Gas Liquids (bbls/d)	1,690	931	1,346	955
Natural Gas (Mcf/d)	8,409	3,767	6,412	3,942
Total (boe/d)	3,091	1,559	2,414	1,612
Average Sales Price(3)
Crude Oil and Natural Gas Liquids (\$/bbl)	81.83	98.39	83.39	93.64
Natural Gas (\$/Mcf)	2.00	1.41	2.21	2.06
Total (\$/boe)	48.62	62.36	52.19	60.85
Netback (\$/boe)
Petroleum and Natural Gas Sales	48.62	62.36	52.19	60.85
Royalties Expense	(7.84)	(0.61)	(6.30)	(3.86)
Percentage	16%	1%	12%	6%
Direct Operating Expense	(18.87)	(24.99)	(20.64)	(26.00)
Operating Netback	21.90	36.75	25.24	30.99
Wells Drilled
Gross	–	1.00	–	3.00
Net	–	0.25	–	0.75

(1) Adjusted Funds Flow from Operations is a non-GAAP measure defined as cash flows from operating activities before changes in noncash operating working capital.

(2) Working capital surplus is a non-GAAP measure calculated as current assets less current liabilities excluding the current portion of risk management and lease liabilities.

(3) 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.

Highlights

• Kakwa North wells tied-in and on production
• Questerre filed leave to appeal to the Supreme Court of Canada following Quebec Court of Appeal ruling on Bill 21
• Average daily production of 3,091 boe per day for the quarter almost doubling production from the same period last year
• Net cash from operating activities of \$6.3 million and adjusted funds flow from operations of \$5 million compared to last year despite significantly lower realized prices

Second Quarter 2025 Activities

Kakwa, Alberta

At Kakwa North, three (1.5 net) wells were brought on production during the quarter. Questerre holds a 50% interest in these wells. The operator plans a follow-up program of up to 3 (1.5 net) wells in the fourth quarter of 2026.

At Kakwa Central, the operator completed three wells during the quarter. Questerre elected to not participate in this entire program due to the proposed inter-well spacing that it anticipates could impact overall well recoveries.

The Company plans to participate in future drilling programs at both joint ventures subject to among other things, commodity prices, and the costs and design of the proposed drilling and completion programs.

Quebec

The Company's primary objective remains a business and political solution for the development of its natural gas discovery in the province. Concurrently, it is protecting its legal rights following the enactment in August 2022 of Bill 21, An Act mainly to end petroleum exploration and production and the public financing of those activities in Quebec("Bill 21").

Discussions remain ongoing with the Quebec Ministry of Economy, Innovation and Energy, for the Company's carbon storage pilot project application under Bill 21. The project includes a comprehensive program to assess the carbon storage potential including injection and monitoring wells, compression facilities and a pipeline to an adjacent industrial park. The Company is seeking government funding for this pilot project.

In May 2025, the Quebec Court of Appeal ruled on an appeal by the Attorney General of Quebec of a judgement rendered by the Quebec Superior Court suspending key provisions of Bill 21 in January 2024. The appeal concerns the analysis of the criteria applicable to the suspension of a law. The Court of Appeal dismissed the joint motion by the Company and other license holders for the review and annulment of the judgement granting the appeal and allowed the appeal. Subject to the results of the Company's appeal, the Government of Quebec could move to enforce the specific provisions related to the abandonment and reclamation of existing wells.

The Quebec Court of Appeal noted in its decision that the Justice did not err in law or exercise his discretion in an unjudicial or unreasonable manner in concluding there was a serious question to be decided. The Quebec Court of Appeal noted that the Justice erred in law on the balance of convenience test and did not presume that the suspension of Bill 21 would cause irreparable harm to the public interest. The ruling noted that, in view of the importance of the public interest and the failure to demonstrate the benefits to the public of suspending key provisions of Bill 21, it allowed the appeal and overturned the Justice's original decision.

Questerre has applied for leave to appeal this decision by the Quebec Court of Appeal to the Supreme Court of Canada.

The Company is also proceeding with the main hearing on the merits of the case in accordance with procedural rules in Quebec, including its debate on the constitutional validity of Bill 21. The questioning of key Government representatives is scheduled for this September and October to be followed by the establishment of a trial date for the hearing.

Subsequent Events

Proposed Acquisition of PX Energy

To further development of its portfolio of oil shale assets, in July, Questerre entered into an agreement to acquire 100% of PX Energy, a privately held oil shale production and refining company based on southern Brazil by way of acquisition of the shares of its indirect parent companies (the "Acquisition"). For the three months ended March 31, 2025, PX Energy's reported production of 4,500 boe per day. The Company is in active discussions with prospective local partners for up to 50% of this acquisition.

Subject to the closing of the Acquisition, the purchase consideration will include the issuance of up to 65 million Common Shares as follows:

• 15 million Common Shares subject to a voting and lock up agreement;
• 25 million Common Shares subject to the achievement of US\$30 million in free cash flow or the completion of an equity issue by the Company of \$25 million at a price of \$0.50 per Common Share no later than September 30, 2027; and
• 25 million Common Shares subject to the achievement of US\$40 million in free cash flow or the completion of an equity issue by the Company of \$25 million at a price of \$1.00 per Common Share no later than September 30, 2028.

The Company has retained a Norwegian-based investment banking firm as financial advisor to advise on the existing outstanding debt of PX Energy including US\$80 million in senior secured bonds in Forbes Resources Brazil Holding SA, the parent company of PX Energy. The Company is anticipating that a stronger sponsor will be well received by the bondholders and the holders of US\$8 million in convertible promissory notes in F&M Resources, a related company.

Completion of the Acquisition is subject to several conditions, including satisfactory due diligence review, board approval, standard regulatory approvals (including acceptance from the Toronto Stock Exchange and Oslo Stock Exchange) and third-party approvals including satisfactory waivers by the bond holders and convertible noteholders in favor of Questerre. Where applicable, the proposed Acquisition cannot close until the required shareholder approval is obtained. There can be no assurance that the Acquisition will be completed as proposed or at all.

Quebec asset spin-out

In conjunction with the Acquisition, the Company anticipates its Quebec assets (the "Quebec Assets") could be transferred into a separate sidecar subsidiary company. If completed, Questerre anticipates distributing either preferred shares of Questerre or shares of the new entity to its existing shareholders ahead of the closing of the acquisition of PX Energy in order not to dilute its existing shareholders' position in the Quebec Assets.

Production

Three months ended June 30,		2025			2024
	Oil and	Natural		Oil and	Natural
	Liquids	Gas	Equivalent	Liquids	Gas	Equivalent
	(bbls/d)	(Mcf/d)	(boe/d)	(bbls/d)	(Mcf/d)	(boe/d)
Alberta	1,453	8,409	2,854	630	3,767	1,258
Saskatchewan and Manitoba	237	–	237	301	–	301
	1,690	8,409	3,091	931	3,767	1,559

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

Six months ended June 30,		2025			2024
	Oil and	Natural		Oil and	Natural
	Liquids	Gas	Equivalent	Liquids	Gas	Equivalent
	(bbls/d)	(Mcf/d)	(boe/d)	(bbls/d)	(Mcf/d)	(boe/d)
Alberta	1,102	6,412	2,170	637	3,942	1,294
Saskatchewan and Manitoba	244	–	244	318	–	318
	1,346	6,412	2,414	955	3,942	1,612

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

Average daily production increased in the second quarter and the first half of the year with the tie-in of the three wells at Kakwa North. By comparison, in the first half of last year, no new wells were brought on production at Kakwa.

These incremental volumes contributed to Kakwa accounting for 90% of corporate production in both periods, up from 80% in the prior year. Kakwa production for the quarter also includes 1,054 boe per day from Kakwa Central (2024: 805 boe per day). Crude and liquids accounted for 55% of corporate volumes, down slightly from 60% in prior periods.

With Kakwa production split equally between liquids and natural gas, the overall higher liquids weighting is due to the incremental light oil volumes from Saskatchewan and Manitoba. For both the quarter and year to date, production from these areas decreased over the prior year reflecting natural declines and the conversion of producing wells to injectors for the pilot secondary recovery scheme in Saskatchewan.

For the second half of the year, production is expected to decline with no further wells planned for the remainder of this year.

Second Quarter 2025 Financial Results

Three months ended June 30,		2025			2024
	Oil and	Natural		Oil and	Natural
(\$ thousands)	Liquids	Gas	Total	Liquids	Gas	Total
Alberta	\$ 10,281	\$ 1,598	\$ 11,879	\$ 5,502	\$ 507	\$ 6,009
Saskatchewan and Manitoba	1,796	–	1,796	2,838	–	2,838
	\$ 12,077	\$ 1,598	\$ 13,675	\$ 8,340	\$ 507	\$ 8,847

Petroleum and Natural Gas Sales

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

Six months ended June 30,		2025			2024
	Oil and	Natural		Oil and	Natural
(\$ thousands)	Liquids	Gas	Total	Liquids	Gas	Total
Alberta	\$ 16,339	\$ 2,554	\$ 18,893	\$ 10,692	\$ 1,593	\$ 12,285
Saskatchewan and Manitoba	3,912	–	3,912	5,560	–	5,560
	\$ 20,251	\$ 2,554	\$ 22,805	\$ 16,252	\$ 1,593	\$ 17,845

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

Higher production volumes offset the lower realized oil and liquid prices for both the quarter and year to date periods ended June 30, 2025. For the quarter, revenues rose 55% due to a nearly 100% increase in volumes partly offset by a 44% decline due to lower prices. For the first half of the year, the 28% increase in revenues was caused by a 50% increase in volumes partially offset by a 21% decrease in prices.

Pricing

	Three months ended June	30,	Six months ended June 30,
	2025	2024	2025	2024
Benchmark prices:
Natural Gas - AECO, daily spot (\$/Mcf)	1.60	1.17	1.83	1.74
Crude Oil - Mixed Sweet Blend (\$/bbl)	84.25	105.28	89.79	98.72
Realized prices:
Natural Gas (\$/Mcf)	2.00	1.41	2.21	2.06
Crude Oil and Natural Gas Liquids (\$/bbl)	81.83	98.39	83.39	93.64

Crude oil prices decreased over both the quarter and year to date periods compared to last year. In the second quarter of this year, the benchmark West Texas Intermediate ("WTI") averaged US\$63.74 per barrel (2024: US\$80.57 per barrel) and US\$67.58 per barrel for the first half of the year (2024: US\$78.77 per barrel).

Consistent with the first quarter of this year, prices in part reflected the risks to the global economy from the proposed tariffs by the US administration. Notwithstanding, most Canadian crude and natural gas exports to the US remain exempt under the Canada-United States-Mexico Agreement. Prices were also impacted by the OPEC+ announcement to unwind voluntary production cuts in the quarter and the risk of a broadening conflict in the Middle East.

Questerre's realized liquidity prices in the second quarter of this year averaged \$81.83 per barrel (2024: \$98.39 per barrel) compared to the benchmark Canadian Mixed Sweet Blend price of \$84.25 per barrel (2024: \$105.28 per barrel).

Natural gas prices improved over both the three and six months ended June 30, 2025, compared to last year. The benchmark Henry Hub averaged US\$3.19 per MMBtu for the three months then ended (2024: US\$2.08 per MMBtu) and US\$3.67 per MMBtu for the six months then ended (2024: US\$2.11 per MMBtu). Prices reflect balanced supply and demand with increasing LNG exports offsetting North American production that grew to over 106 Bcf per day in the quarter.

Canadian natural gas prices also improved over the prior year. The benchmark AECO 5A averaged \$1.60 per GJ for the quarter (2024: \$1.17 per GJ) and \$1.83 per GJ for the first half of the year (2024: \$1.74 per GJ). Prices weakened towards the quarter end with growing supply from Western Canada and limited takeaway capacity, resulting in an average price of \$0.75 per GJ in the month of June. Although LNG Canada exported their first cargo in July, the facility is expected to slowly ramp up to full capacity over two years, limiting the impact on gas prices in the near term.

Royalties

	Three months ended June 30,				Six months ended June 30,
(\$ thousands)		2025		2024		2025		2024
Alberta	\$	2,053	\$	(128)	\$	2,431	\$	702
Saskatchewan and Manitoba		152		215		322		432
	\$	2,205	\$	87	\$	2,753	\$	1,134
% of Revenue:
Alberta		17%		-		13%		6%
Saskatchewan and Manitoba		8%		8%		8%		8%
Total Company		16%		1%		12%		6%

For the three and six months ended June 30, 2025, royalty expense increased by \$2.2 million and \$1.6 million respectively over the prior year due to a reduction in the credits received for processing the Crown's share of production in Alberta. The credits are estimated annually based on prior year's costs and revised when the current year information is available.

For the second quarter, the reduction in credits of \$1.2 million increased royalty expense by the same amount. By comparison, in the prior year, the Crown increased the credits received by \$1.2 million. Excluding the impact of this \$1.2 million amount, royalty expense on production in Alberta was \$0.8 million (2024: \$0.8 million) for the quarter and \$1.4 million (2024: \$1.7 million) for the first half of the year.

Gross royalties on production from Saskatchewan and Manitoba decreased commensurately with revenue and remained unchanged as a percentage of revenue.

	Three months ended June 30,			Six months ended June 30,
(\$ thousands)		2025		2024		2025		2024
Alberta	\$	4,429	\$	2,629	\$	7,366	\$	5,648
Saskatchewan and Manitoba		641		730		1,284		1,640
Quebec		239		187		371		336
	\$	5,309	\$	3,546	\$	9,021	\$	7,624
\$/boe:
Alberta	\$	17.05	\$	22.97	\$	18.75	\$	23.98
Saskatchewan and Manitoba		29.77		26.63		29.10		28.39
Total Company	\$	18.87	\$	24.99	\$	20.64	\$	26.00

Operating Expenses

For the second quarter, operating costs increased by nearly 50% over the prior year to \$5.3 million from \$3.5 million last year due mainly to higher production volumes at Kakwa. For the first half of the year, the costs increased by nearly 20% from last year, also reflecting the increased production for the period. On a unit of production basis, the higher production volumes resulted in a decrease on a boe basis due to greater efficiencies associated with higher production levels.

In Kakwa, higher operating costs at Kakwa North were incurred due to the three new wells brought on production. Operating costs in Saskatchewan and Manitoba declined by just over 10% in the quarter, in part, due to lower production volumes. Operating costs in Quebec reflect the ongoing expenditures to maintain the Company's assets in the province.

General and Administrative Expenses

	Three months ended June 30,				Six months ended June 30,
(\$ thousands)		2025		2024		2025		2024
General and administrative expenses, gross	\$	1,422	\$	1,167	\$	2,906	\$	2,447
Capitalized expenses and overhead recoveries		(131)		(89)		(275)		(180)
General and administrative expenses, net	\$	1,291	\$	1,078	\$	2,631	\$	2,267

Gross General and Administrative expenses ("G&A") increased by 20% for both the three and six months ended June 30, 2025 compared to last year.

The increase is directly related to increased legal and advisory services for the Company's assets in Quebec in relation to the legal action. Capitalized expenses are G&A directly attributed to the Company's producing assets in Alberta and Saskatchewan.

Depletion, Depreciation and Accretion Expense

Questerre recorded depletion, depreciation and accretion expense of \$5.5 million for the quarter ended June 30, 2025, (2024: \$2.9 million) and \$8.8 million for the first half of 2025 (2024: \$5.7 million). Depletion accounts for over 95% of these amounts. The variance over the last year is due to both the higher production volumes and the depletable base, increasing on a unit of production basis, to \$19.52 per boe from \$18.32 per boe last year.

Net Interest, Other Income and Share Based Compensation Expense

During the six months ended June 30, 2025, the Company reported net interest and other income of \$0.4 million (2024: \$0.7 million). This represents interest earned on its cash deposits and decreased over the last year due to lower cash deposits and lower interest rates.

For the year to date, the Company recorded share based compensation expense of \$0.7 million (2024: \$0.7 million) net of \$0.1 million in expense capitalized during the period (2024: \$0.2 million).

Other Comprehensive Income (Loss)

For the second quarter of 2025, the Company recorded other comprehensive loss of \$0.2 million (2024: \$0.1 million income). Other comprehensive income (loss) relates to the impact of changes in foreign exchange. The depreciation of the Jordanian dinar resulted in a negligible loss (2024: \$0.1 million income) on the Company's dinar denominated assets in the country for the quarter. Similarly, the depreciation in the US dollar also resulted in a loss of \$0.2 million on its US dollar denominated investment in Red Leaf (2024: \$0.01 million income).

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

For the second quarter of 2025, despite higher revenue, the increase in operating and depletion expenses in the current year realized a net loss of \$0.7 million compared to 2024 net income of \$1.3 million. Including other comprehensive income (loss), the total comprehensive loss for the quarter was \$0.9 million (2024: \$1.4 million income). On a year to date basis the loss was \$0.9 million (2024: \$1.5 million income).

Cash Flow From Operating Activities

For the three months ended June 30, 2025, net cash from operating activities was \$6.3 million compared to \$3.1 million last year. Due to a favourable variance of \$2.6 million in non-cash working capital this year compared to last year.

Likewise, year to date a favourable variance of \$2.8 million in non-cash working capital contributed to cash flow from operating activities rising to \$9.6 million (2024: \$5.8 million).

Excluding the non-cash working capital impact, adjusted funds flow from operations was up 12% for the quarter and 15% year to date due to higher income from operating activities.

Cash Flow Used In Investing Activities

Net cash used in investing activities for the first six months of the year increased to \$23.1 million this year from \$3.7 million last year based on increased capital spending. Total capital expenditures of \$18.9 million for the period include three (1.50 net) new wells at Kakwa North. In both the quarter and year to date periods, the Company reduced its capital expenditure related payables compared to an increase in the prior year periods.

Cash Flow Used In Financing Activities

For the three and six months ended June 30, 2025, the net cash used in financing activities was minimal and represents the principal portion of its operating leases.

Capital Expenditures

	Three months ended June 30,			Six months ended June 30,
(\$ thousands)		2025		2024		2025		2024
Alberta	\$	953	\$	6,185	\$	16,663	\$	8,712
Saskatchewan, Manitoba and Jordan		95		849		2,249		952
Total Company	\$	1,048	\$	7,034	\$	18,912	\$	9,664

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

For the first six months of 2025, the Company incurred capital expenditures of \$18.9 million as follows:

• In Alberta, \$16.7 million was incurred to complete and tie-in three (1.5 net) wells at Kakwa North;
• In Saskatchewan, \$2 million was invested in a pressure maintenance scheme; and
• \$0.2 million was invested in other assets.

For the first six months of 2024, the Company incurred capital expenditures of \$9.7 million as follows:

• In Alberta, \$8.7 million was incurred to drill two (0.5 net) wells at Kakwa Central; and
• \$1 million was invested in other assets.

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 June 30, 2025, there were no Class "B" Common voting shares or preferred shares outstanding. The following table provides a summary of the outstanding Common Shares and options as at the date of the MD&A, the current quarter-end and the preceding year-end.

	Aug 8,	June 30,	December 31,
(thousands)	2025	2025	2024
Common Shares	428,516	428,516	428,516
Stock Options	35,790	35,790	38,295
Weighted average common shares
Basic		428,516	428,516
Diluted		431,593	431,715

A summary of the Company's stock option activity for the six months ended June 30, 2025, and the year ended December 31, 2024, follows:

	June 30, 2025			December 31, 2024
	Weighted					Weighted
	Number of	Average Options Exercise				Number of	Average
				Options	Exercise
	(thousands)		Price	(thousands)		Price
Outstanding, beginning of period	38,295	\$	0.25	38,140	\$	0.26
Granted	6,675		0.23	6,950		0.25
Forfeited/cancelled	(2,880)		0.22	(620)		0.27
Expired	(325)		0.16	(6,175)		0.29
Exercised	(5,975)		0.20	–		–
Outstanding, end of period	35,790	\$	0.25	38,295	\$	0.25
Exercisable, end of period	25,400	\$	0.26	29,704	\$	0.25

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 by ensuring capital expenditures can be financed through a combination of cash flow from operations and available debt facilities.

At June 30, 2025, there were no material borrowings under its credit facilities 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 June 30, 2025, was 3.49 (2024: 3.99) and the covenant was met. See Note 11 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 fourth quarter of 2025. The credit facilities are a demand facility and can be reduced, amended or eliminated by the lender for reasons beyond the Company's control. Should the credit facilities be reduced or eliminated, the Company would need to seek alternative credit facilities or consider the issuance of equity to enhance its liquidity. In the current market, the Company may be unable to secure additional financing on acceptable terms, if at all. The Company believes that it has access to sufficient financial liquidity to meet its foreseeable obligations in the normal course of operations over the next 12 months.

The Company is committed to the 2025 future development costs associated with proved reserves in its independent reserves assessment as of December 31, 2024. It anticipates that, as a result, reserves associated with wells drilled in 2025 will be transferred from the proved undeveloped to the proved producing category.

For a detailed discussion of the risks and uncertainties associated with the Company's business and operations, see the Risk Management section of the MD&A and the AIF.

Commitments

A summary of the Company's net commitments at June 30, 2025, are as follows:

(\$ thousands)	2025	2026	2027	Total
Transportation and Processing	\$ 1,219	\$ 1,566	\$ 545	\$ 3,330

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, 2024.

Volatility in the oil and gas industry is a major risk facing the Company. Market events and conditions, including global oil and natural gas supply and demand, actions taken by OPEC and non-OPEC member countries' decisions on production growth and spare capacity, including recent decisions by Saudi Arabia and Russia, on production growth and spare capacity, market volatility and disruptions, weakening global relationships, the war in Ukraine, conflict between the U.S. and Iran, isolationist and punitive trade policies including potential trade disputes involving Canada, Mexico, China, the European Union various other countries and the U.S., hostilities in the Middle East, Ukraine and Taiwan, U.S. shale production, sovereign debt levels and political upheavals in various countries including growing anti-fossil fuel sentiment, the implementation of new export tariffs or import taxes on Canadian energy resources in the U.S. have caused significant volatility in commodity prices. Russia's invasion of Ukraine has led to sanctions being levied against Russia by the international community and may result in additional sanctions or other international action, any of which may have a destabilizing effect on commodity prices and global economies more broadly. These events and conditions have been a factor in the decrease in the valuation of oil and gas companies and a decrease in confidence in the oil and gas industry. These difficulties have been exacerbated in Canada by political and other actions resulting in uncertainty surrounding regulatory, tax and royalty changes and other environmental regulations.

In addition, the difficulties in obtaining the necessary approvals to build pipelines and other facilities to provide better access to markets for the oil and gas industry in Western Canada has led to additional uncertainty and reduced confidence in the oil and gas industry in Western Canada. Lower commodity prices may also affect the volume and value of the Company's reserves especially as certain reserves become uneconomic. In addition, lower commodity prices have previously reduced the Company's cash flow leading to a reduction in funds available for capital expenditures. As a result, the Company may not be able to replace its production with additional reserves and both the Company's production and reserves could be reduced on a year over year basis. Any decrease in value of the Company's reserves may reduce the borrowing base under its credit facilities, which, depending on the level of the Company's indebtedness, could result in the Company having to repay all or a portion of its indebtedness. Given the current market conditions and the lack of confidence in the Canadian oil and natural gas industry, the Company may have difficulty raising additional funds in the future to raise funds on unfavourable and highly dilutive terms.

Another significant risk for Questerre as a junior exploration company is access to capital. The Company attempts to secure both equity and debt financing on terms it believes are attractive in current markets. Management also endeavors to seek participants to farm-in on the development of its projects on favorable terms. However, there can be no assurance that the Company will be able to secure sufficient capital if required or that such capital will be available on terms satisfactory to the Company.

As future capital expenditures will be financed out of adjusted funds flow from operations, borrowings and possible future equity sales, the Company's ability to do so is dependent on, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry, and the Company's securities. To the extent that external sources of capital become limited or unavailable, or available but on onerous terms, the Company's ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected. Based on current funds available and expected adjusted funds flow from operations, the Company believes it has sufficient funds available to fund its projected capital expenditures. However, if adjusted funds flow from operations is lower than expected, or capital costs for these projects exceed current estimates, or if the Company incurs major unanticipated expense related to development or maintenance of its existing properties, it may be required to seek additional capital to maintain its capital expenditures at planned levels. Failure to obtain any financing necessary for the Company's capital expenditure plans may result in a delay in development or production on the Company's properties.

Questerre faces several financial risks over which it has no control, such as commodity prices, exchange rates, interest rates, access to credit and capital markets, as well as changes to government regulations and tax and royalty policies.

The Company uses the following guidelines to address financial exposure:

• Internally generated cash flow provides the initial source of funding on which the Company's annual capital expenditure program is based.
• Equity, including flow-through shares, if available on acceptable terms, may be raised to fund acquisitions and capital expenditures.
• Debt may be utilized to expand capital programs, including acquisitions, when it is deemed appropriate and where debt retirement can be controlled.
• Farm-outs of projects may be arranged if management considers that a project requires too much capital or where the project affects the Company's risk profile.

Credit risk represents a potential financial loss to the Company if a customer or counterparty to a financial instrument fails to meet or discharge their obligation to the Company. Credit risk arises from the Company's receivables from joint venture partners and oil and gas marketers. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. Credit risk also arises from the Company's cash and cash equivalents. In the past, the Company manages credit risk exposure by investing in Canadian banks and credit unions. Management does not expect any counterparty to fail to meet its obligations.

Poor credit conditions in the industry may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner if possible.

Substantially all of the accounts receivable are with oil and natural gas marketers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by entering into transactions with long-standing, reputable counterparties and partners.

Accounts receivable related to the sale of the Company's petroleum and natural gas production are paid in the following month from major oil and natural gas marketing and infrastructure companies and the Company has not experienced any credit loss relating to these sales to date. Pursuant to IFRS 9, the Company made a provision of \$0.06 million at June 30, 2025, for its expected credit losses related to its accounts receivable.

Receivables from joint venture partners are typically collected within one to six 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 flowthrough 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 June 30, 2025, the Company had no outstanding commodity risk management contracts in place.

Environmental Regulation and Risk

The oil and natural gas industry is currently subject to environmental regulations pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases of emissions and regulation on the storage and transportation of various substances produced or utilized in association with certain oil and natural gas industry operations, which can affect the location and operation of wells and facilities, and the extent to which exploration and development is permitted. In addition, legislation requires that well and facility sites are abandoned and reclaimed to the satisfaction of provincial authorities. As well, applicable environmental laws may impose remediation obligations with respect to property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures, and a breach of such legislation may result in the suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, the imposition of fines and penalties or the issuance of clean-up orders. The Company mitigates the potential financial exposure of environmental risks by complying with the existing regulations and maintaining adequate insurance. For more information, please refer to the "Risk Factors" and "Industry Conditions" sections of the AIF.

Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. The federal and certain provincial governments have implemented legislation aimed at incentivizing the use of alternative fuels and in turn reducing carbon emissions. The taxes placed on carbon emissions may have the effect of decreasing the demand for oil and natural gas products and at the same time, increasing the Company's operating expenses, each of which may have a material adverse effect on the Company's profitability and financial condition. Further, the imposition of carbon taxes puts the Company at a disadvantage with the Company's counterparts who operate in jurisdictions where there are less costly carbon regulations.

Interest Rate Risk

Interest rate risk is the risk that changes in the applicable interest rates will impact the Company's interest expense related to its credit facilities. Given the unutilized credit facility, a 0.5% change in interest rates applicable to its credit facilities would have no impact on net income (loss). At June 30, 2025, the Company had credit facilities outstanding of \$0.02 million (December 31, 2024: \$0.05 million) with an effective rate of 6.10%.

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 the 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. The use of critical accounting estimates made by management in the preparation of the interim financial statements are discussed under the section "Critical Accounting Estimates" in the MD&A for the year ended December 31, 2024.

Design and Evaluation of Internal Controls over Financial Reporting and Disclosure Controls and Procedures

The Company's Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the Company is made known to the Company's CEO and CFO by others, particularly during the period in which the annual and interim filings are being prepared; and (ii) information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed, summarized and reported within the time period specified in securities legislation.

The Company's CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Company is required to disclose herein any change in the Company's internal controls over financial reporting that occurred during the period beginning on April 1, 2025, and ended on June 30, 2025, that has materially affected, or is reasonably likely to materially affect, the Company's internal controls over financial reporting. No material changes in the Company's internal controls over financial reporting were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company's internal controls over financial reporting.

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

			Sep 30
2025	2025	2024	2024
3,091	1,729	1,887	1,913
48.62	58.66	55.43	53.75
13,675	9,130	9,622	9,460
5,005	3,543	3,703	3,428
6,288	3,359	3,844	4,060
(677)	4	(8,143)	(273)
–	–	(0.02)	–
1,048	17,864	7,543	3,433
13,157	9,202	23,091	27,608
169,976	181,519	170,723	178,731
138,355	139,006	138,629	145,887
428,516	428,516	428,516	428,516
431,505	431,700	432,473	431,804
	Jun 30	Mar 31	Dec 31

(1) Adjusted Funds Flow from Operations is a non-GAAP measure defined as cash flows from operating activities before changes in noncash operating working capital.

(2) Working capital surplus is a non-GAAP measure calculated as current assets less current liabilities excluding the current portion of risk management and lease liabilities.

	Jun 30	Mar 31	Dec 31	Sep 30
(\$ thousands, noted) except as	2024	2024	2023	2023
Production (boe/d)	1,559	1,664	1,794	1,830
Average Realized Price (\$/boe)	62.36	59.43	59.04	63.71
Petroleum and Natural Gas Revenue	8,847	8,998	9,743	10,725
Adjusted Funds Flow from Operations(1)	4,455	2,973	3,209	3,034
Cash Flow from Operations	3,141	2,628	5,154	2,382
Net Income (Loss)	1,262	(175)	(26,003)	(337)
Basic and Diluted (\$/share)	–	–	(0.06)	–
Capital Expenditures, net of acquisitions and dispositions	7,034	2,630	3,588	845
Working Capital Surplus(2)	27,620	30,211	29,866	30,191
Total Assets	179,248	172,968	172,346	197,716
Shareholders' Equity	145,941	144,148	143,667	169,636
Weighted Average Common Shares Outstanding
Basic (thousands)	428,516	428,516	428,516	428,516
Diluted (thousands)	431,327	431,175	429,270	429,922

(1) Adjusted Funds Flow from Operations is a non-GAAP measure defined as cash flows from operating activities before changes in noncash operating working capital.

(2) Working capital surplus is a non-GAAP measure calculated as current assets less current liabilities excluding the current portion of risk management and lease liabilities.

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

• Petroleum and natural gas revenues have fluctuated with production volumes and realized commodity prices. Adjusted funds flow from operations has varied in large part by the fluctuating revenues and changes in operating expenses related to production volumes.
• Production volumes reflect the capital investment in new wells at Kakwa in preceding quarters.
• The level of capital expenditures over the quarters has varied largely due to the timing and number of wells drilled and completed primarily at Kakwa, Alberta. In the first half of 2025, \$18.9 million was spent on new drills. Similarly, in the prior year, \$9.6 million was also invested at Kakwa and Antler.
• The working capital position has generally increased when capital expenditures and other investments have been lower than adjusted funds flow from operations and cash from financing activities.
• Shareholders equity generally decreased as a result of overall net loss incurred over the last eight quarters.

Off-Balance Sheet and Related Party Transactions

The Company did not engage in any off-balance sheet transactions nor any related party transactions during the period ended June 30, 2025.