Questerre Energy — Interim / Quarterly Report 2021

Nov 11, 2021

Management’s Discussion and Analysis

This Management’s Discussion and Analysis (“MD&A”) was prepared as of November 10, 2021. 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 nine month periods ended September 30, 2021 and 2020, and the audited annual consolidated financial statements of the Company for the year ended December 31, 2020 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, 2020, is available on SEDAR under Questerre’s profile at www.sedar.com.

Questerre is an energy technology and innovation company. It is leveraging its expertise gained through early exposure to low permeability reservoirs to acquire significant high quality resources. 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 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 forwardlooking statements. Forward-looking statements are often, but not always, identified by 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.

Management has not adjusted or revised any forward-looking statements in this MD&A to account for the potential disruption to the Company’s business from the coronavirus (“COVID-19”) pandemic, the impact of which is not immediately known or quantifiable.

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

• clarification by the Government of Quebec of its intentions to end production of fossil fuels in the province

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and potential associated compensation;

• future commodity prices in light of recent decisions by the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC member countries, including Saudi Arabia and Russia, on production levels as well as the impacts of the COVID-19 pandemic;

• securing social acceptability in Quebec for the Clean Tech Energy project;

• further capital investment requiring additional financial liquidity through potential asset dispositions, equity or debt;

• future production of oil, natural gas and natural gas liquids and the weighting thereof;

• production declines and increases;

• development plans for the Company’s Kakwa assets;

• the testing of a reservoir in Quebec for carbon storage;

• the assessment of future development costs;

• the need to continue the development of the Company’s producing assets to execute its business strategy;

• legislative and regulatory developments in the Province of Quebec;

• liquidity and capital resources;

• the Company’s compliance with the terms of its credit facility;

• the 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;

• the Company’s objectives when managing its capital;

• the Company’s methods to address financial exposure;

• Questerre’s reserves and resources;

• impacts of capital expenditures on the Company’s reserves and resources;

• average royalty rates;

• 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, related provisions for credit losses and the fulfillment of obligations by counterparties;

• joint venture partner willingness to participate in capital programs;

• 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:

• clarification by the Government of Quebec of its intentions to end production of fossil fuels in the province and potential associated compensation;

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• volatility in market prices for oil, natural gas liquids and natural gas due to, among other things, the commitments to production levels by OPEC and non-OPEC member countries, including Saudi Arabia and Russia, as well as the impact of the coronavirus pandemic;

• access to capital;

• 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 regulatory rulings, orders and decisions;

• attracting, retaining and motivating skilled personnel;

• uncertainties associated with estimating oil and natural gas reserves and resources;

• 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;

• the outcome of the Company’s challenge of the validity of certain restrictive Regulations;

• 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” or “resources” 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 and resources described can be profitably produced in the future. The discounted and undiscounted net present values of future net revenue attributable to reserves and resources 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 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 laws. 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

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(“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 by 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 Questerre’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. Questerre’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 September 30,	months ended September 30,	months ended September 30,	Nine	months ended September 30,	months ended September 30,	months ended September 30,
($ thousands)		2021		2020		2021		2020
Net cash from operating activities	$	4,202	$	76	$	10,287	$	3,846
Interest received		(54)		(89)		(152)		(261)
Interest paid		111		146		367		477
Change in non-cash operating working capital		(681)		1,490		185		227
Adjusted Funds Flow from Operations	$	3,578	$	1,623	$	10,687	$	4,289

This document also contains the terms “operating netbacks” and “working capital surplus (deficit)”, which are non-GAAP measures. The Company considers operating netbacks to be a key measure as it demonstrates its profitability relative to current commodity prices. Operating 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. 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 current portion of risk management contracts and lease liabilities.

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Select Information

	Three months ended	Three months ended	Nine months ended	Nine months ended
As at/for the period ended September 30,	2021	2020	2021	2020
Financial ($ thousands, except as noted)
Petroleum and Natural Gas Sales	7,376	5,391	21,517	15,819
Net Income (Loss)	2,006	(970)	5,806	(117,548)
Basic and diluted ($/share)	–	–	0.01	(0.27)
Adjusted Funds Flow from Operations	3,578	1,623	10,687	4,289
Basic and diluted ($/share)	0.01	–	0.02	0.01
Capital Expenditures	541	348	1,488	3,738
Working Capital Surplus (Deficit)	1,698	(8,095)	1,698	(8,095)
Total Assets	192,709	195,925	192,709	195,925
Shareholders' Equity	158,922	152,508	158,922	152,508
Common Shares Outstanding (thousands)	428,516	427,516	428,516	427,516
Weighted average - basic (thousands)	428,516	427,516	427,871	427,646
Weighted average - diluted (thousands)	428,516	427,516	427,992	427,646
Operations (units as noted)
Average Production
Crude Oil and Natural Gas Liquids (bbls/d)	833	1,187	898	1,309
Natural Gas (Mcf/d)	3,178	4,127	3,655	4,168
Total (boe/d)	1,363	1,875	1,507	2,004
Average Sales Price
Crude Oil and Natural Gas Liquids ($/bbl)	80.30	40.95	80.12	39.54
Natural Gas ($/Mcf)	4.18	2.42	3.39	2.32
Total ($/boe)	58.83	31.26	52.34	28.82
Netback ($/boe)
Petroleum and Natural Gas Sales	58.83	31.26	52.34	28.82
Royalties Expense	(4.12)	(1.83)	(2.54)	(2.00)
Percentage	7%	6%	5%	7%
Direct Operating Expense	(20.62)	(18.27)	(19.74)	(15.94)
Operating Netback	34.09	11.15	30.05	10.88
Wells Drilled
Gross	1.00	–	1.00	1.00
Net	0.25	–	0.25	0.25

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

(2) Working capital surplus (deficit) 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.

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Highlights

• Quebec Premier announces plans to renounce oil and gas extraction in Quebec

• Submitted application for carbon storage test in Quebec

• Wolinak Abenaki First Nation in Quebec executes letter of interest for Clean Gas project

• Average daily production of 1,363 boe/d and adjusted funds flow from operations of $3.6 million in the quarter

Third Quarter 2021 Activities

Kakwa, Alberta

The operator of the Kakwa Central acreage resumed drilling during the quarter. The Company participated in the first well (0.25 net) that should be completed and tied-in during the first half of 2022. The Company intends to participate in the drilling of up to two (0.5 net) additional wells on this acreage over the next quarter.

The Company’s participation in any future wells will depend on among other things, sustained strength in longterm oil prices. Should the Company participate, it may require additional financial liquidity through potential asset dispositions, equity or debt issuances. There is no certainty that such liquidity will be available when required on terms acceptable to Questerre.

St. Lawrence Lowlands, Quebec

Notwithstanding the Quebec Government’s recent announcement on renouncing hydrocarbon extraction, Questerre continued to advance the first stage of its Clean Tech Energy pilot, carbon storage.

In the opening speech for the second parliamentary session of the 42[nd] legislature of the National Assembly, the Quebec Premier announced the intention of the Government to end production of fossil fuels. The Premier subsequently noted that the Government is investing the legal and financial resources required to assess the potential compensation.

To date, the Government has not provided any further clarification on the details of this renunciation and the compensation. The Company will continue to monitor developments relating to these matters and the impact on its Quebec assets. At the present time, the Company remains committed to working with all stakeholders as well as securing social acceptability and regulatory approvals for its Clean Tech Energy project.

During the quarter, Questerre filed an application with the Ministry of Energy and Natural Resources to test a reservoir for carbon storage. The operation will consist primarily of an injectivity test to gather data on both the safe rate of injection and storage potential. The Company identified the storage formation earlier this year after studying its proprietary seismic and well data. It holds the exclusive right to explore for reservoirs over one million acres in Quebec.

With several stakeholders expressing interest in the Clean Tech Energy project, the Company continued to make progress on social acceptability.

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The Wolinak Abenaki Council in Quebec executed a letter of interest for the Company’s Clean Tech Energy pilot including carbon storage. Earlier this year, a local town adjacent to the Company’s discovery well also expressed interest in a similar pilot project. The Company also received a letter from a local farming group interested in the development of local Clean Gas.

Corporate

The Company’s credit facilities with a Canadian chartered bank were renewed at $16 million during the quarter. Any borrowing under the facilities, except letters of credit are subject to the Bank’s prime rate and applicable basis point margin. The effective interest rate on the facility for the first nine months of 2021 was 3.45% (2020: 3.45%). As at September 30, 2021, $7.4 million (2020: $16.2 million) was drawn on the facility and the Company held unrestricted cash and term deposits of $9.5 million (2020: $9.7 million).

The facilities are secured by a revolving credit agreement, a debenture including a first floating charge over all assets of the Company and a general assignment of book debts. The next review is scheduled for the second quarter of 2022.

Production

Three months ended September 30,		2021			2020
	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	554	3,178	1,084	861	4,127	1,549
Saskatchewan and Manitoba	279	–	279	326	–	326
	833	3,178	1,363	1,187	4,127	1,875
Nine months ended September 30,		2021			2020
	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	602	3,655	1,211	942	4,168	1,637
Saskatchewan and Manitoba	296	–	296	367	–	367
	898	3,655	1,507	1,309	4,168	2,004

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

Production decreased over the prior year both on a quarterly and year to date basis. The variance is attributable to natural declines that were not offset by drilling at Kakwa.

Consistent with prior periods, Kakwa accounted for 80% of corporate volumes with royalty production from Kakwa North accounting for approximately 12% of these volumes (2020: 13%). Approximately 25% of the production decline during the quarter was attributable to a plant turnaround and reduced deep cut processing capacity at Kakwa. The latter reduced natural gas volumes in the last two quarters but increased the heat content, resulting in higher realized prices on a per unit basis.

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The Company’s oil and liquids weighting remained stable at 60% both for the quarter and year to date. Representing the remaining 20% of corporate volumes in the current year, production from Saskatchewan and Manitoba also declined naturally over the prior year.

With no additional wells scheduled to come on production in the next three to six months, the Company anticipates its production volumes will decline. Depending when the new wells at Kakwa are tied-in, the Company expects its production will increase in the second half of 2022.

Third Quarter 2021 Financial Results

Petroleum and Natural Gas Sales

Three months ended September 30,		2021					2020
	Oil and	Natural			Oil and		Natural
($ thousands)	Liquids	Gas	Total		Liquids		Gas		Total
Alberta	$ 4,008	$ 1,201	$ 5,209	$	2,949	$	919	$	3,868
Saskatchewan and Manitoba	2,167	–	2,167		1,523		–		1,523
	$ 6,175	$ 1,201	$ 7,376	$	4,472	$	919	$	5,391

Nine months ended September 30,		2021					2020
	Oil and	Natural			Oil and		Natural
($ thousands)	Liquids	Gas	Total		Liquids		Gas	Total
Alberta	$ 11,868	$ 3,463	$ 15,331	$	8,737	$	2,578	$ 11,315
Saskatchewan and Manitoba	6,186	–	6,186		4,504		–	4,504
	$ 18,054	$ 3,463	$ 21,517	$	13,241	$	2,578	$ 15,819

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

Although production volumes declined in the current year, they were more than offset by higher commodity prices, resulting in a nearly 40% increase in petroleum and natural gas sales for both the quarter and year to date periods.

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Pricing

	Three months ended September 30,	Three months ended September 30,	Nine months ended	Nine months ended	September 30,
	2021	2020		2021	2020
Benchmark prices:
Natural Gas - AECO, daily spot ($/Mcf)	3.38	2.12		3.03	1.98
Crude Oil - Mixed Sweet Blend ($/bbl)	83.93	49.31		78.23	45.02
Realized prices:
Natural Gas ($/Mcf)	4.18	2.42		3.39	2.32
Crude Oil and Natural Gas Liquids ($/bbl)	80.30	40.95		80.12	39.54

Improving materially over last year, rising crude oil prices sustained their momentum into the third quarter of this year. The benchmark West Texas Intermediate averaged US$70.91/bbl (2020: US$40.43/bbl) for the quarter and US$64.75/bbl for the first nine months (2020: US$37.86/bbl).

The supply demand balance has tightened as rising global economic activity restores demand to near prepandemic levels and supply is maintained by OPEC+ compliance with unwinding production cuts and fiscal discipline by North American producers. This has resulted in falling global inventories including those in the United States that were also impacted by the supply disruptions caused by Hurricane Ida. In Canada, differentials remained strong due to reduced supply from major turnarounds and increasing egress capacity including the completion of Enbridge’s Line 3 replacement. The differential in the quarter between WTI and the Canadian condensate prices was a discount of US$1.32/bbl compared to a discount of US$3.38/bbl last year.

Questerre’s liquids production consists primarily of condensate and light oil. As a result, realized prices closely tracked the benchmark price with discounts of less than 10% for both periods in the current year.

Natural gas prices improved more significantly during the quarter. The benchmark Henry Hub price averaged US$4.36/MMBtu for the quarter (2020: US$1.98/MMBtu) and US$3.62/MMBtu for the nine months ended September 30, 2021 (2020: US$1.88/MMBtu).

The price increases in the third quarter reflect a tight market in North America and, to some extent, internationally. Storage levels in the United States are below the five-year average as relatively stable production despite rising rig counts is met by growing demand from exports via LNG and pipeline to Mexico that now account for nearly 18% of total demand. Rising LNG imports in Asia and reduced LNG supplies globally have seen prompt Asian benchmark prices increase to over US$30/MMBtu with recent spikes to US$56/MMBtu. Europe has seen a fourfold increase in prices driven by unreliable renewable power and a shortage of supply due to lower imports from Russia and increased LNG demand from Asia. In Canada, the differential between the NYMEX and AECO benchmark prices increased in part due to pipeline maintenance.

Realized natural gas prices, reflecting the higher heat content from Kakwa gas production, averaged $4.18/Mcf (2020: $2.42/Mcf) compared to the AECO spot price of $3.39/Mcf (2020: $2.12/Mcf).

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Royalties

	Three	months ended September 30,	months ended September 30,	months ended September 30,	Nine	months ended September 30,	months ended September 30,	months ended September 30,
($ thousands)		2021		2020		2021		2020
Alberta	$	362	$	198	$	597	$	720
Saskatchewan and Manitoba		155		119		449		379
	$	517	$	317	$	1,046	$	1,099
% of Revenue:
Alberta		7%		5%		4%		6%
Saskatchewan and Manitoba		7%		8%		7%		8%
Total Company		7%		6%		5%		7%

For the quarter ended September 30, 2021, gross royalties increased over the prior year due to higher commodity prices. For the nine months ended September 30, 2021, these amounts remained largely flat due to a $0.8 million royalty credit received in the second quarter (2020: $0.4 million).

Royalties on Kakwa production include credits from the Crown for processing its share of production through the Company’s facilities. The credit received in 2021 was higher than prior years due to an increase in the facility effective royalty rate at Kakwa. Excluding this credit, royalties on production from Alberta almost doubled due to higher prices and the expiration of royalty incentive programs for older wells.

Royalties on production from Saskatchewan and Manitoba decreased slightly to 7% from 8% for both periods, consistent with the year-end rate of 7%.

Operating Costs

	Three	months ended September 30,	months ended September 30,	months ended September 30,	Nine	months ended September 30,	months ended September 30,	months ended September 30,
($ thousands)		2021		2020		2021		2020
Alberta	$	1,991	$	2,473	$	6,038	$	6,288
Saskatchewan and Manitoba		493		451		1,807		2,078
Quebec		102		227		272		384
	$	2,586	$	3,151	$	8,117	$	8,750
$/boe:
Alberta		19.96		17.35		18.28		14.03
Saskatchewan and Manitoba		19.23		15.03		22.38		20.64
Total Company		20.62		18.27		19.74		15.94

Operating costs for the quarter ended September 30, 2021, decreased by 20% compared to last year. For the nine-month period then ended, the decrease was more nominal at under 10%. As the majority of the operating costs incurred are fixed and not impacted by the lower production volumes, costs on a boe basis increased in both periods.

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In Alberta, Kakwa costs decreased over the prior year due to a restructuring of the Company’s firm transportation and processing commitments completed last year. In the current year, the Company also recorded a 20% increase or approximately $0.15 million for the thirteen-month adjustment that reallocated plant operating costs based on actual volumes. Year to date operating costs declined marginally with reductions in the categories above offset by increases in others including fuel and power.

In Saskatchewan, operating costs in the quarter increased over the prior year due to workovers that were deferred last year due to lower commodity prices. Comparable operating costs in Quebec declined over the prior year as in 2020 they included several one-time items associated with the acquisition that closed effective December 31, 2019.

General and Administrative Expenses

	Three	months ended September 30,	months ended September 30,	months ended September 30,	Nine	months ended September 30,	months ended September 30,	months ended September 30,
($ thousands)		2021		2020		2021		2020
General and administrative expenses, gross	$	951	$	599	$	2,463	$	2,484
Capitalized expenses and overhead recoveries		(210)		(239)		(731)		(779)
General and administrative expenses, net	$	741	$	360	$	1,732	$	1,705

For the quarter ended September 30, 2021, gross general and administrative expenses (“G&A”) increased by approximately 60% from the prior year and remained flat for the nine months ended September 30, 2021. This quarter, the Company did not receive any assistance under the Canada Emergency Wages Subsidy, part of the Government’s pandemic financial assistance program. In the prior year, the company recorded credits of $0.2 million under this program. Year to date, the higher salary expense and legal costs offset by reductions in other categories resulted in no change. Capitalized expenses remained constant and represent the overhead related to the Company’s projects in Quebec and Jordan.

Depletion, Depreciation, Accretion and Impairment

For the three months ended September 30, 2021, Questerre recorded depletion, depreciation and accretion expense of $1.4 million (2020: $2.1 million) with depletion accounting for over 95% of this amount. For the nine months then ended, this totalled $4.6 million (2020: $7.6 million). The variance over the prior year in both periods is due to the lower production volumes. With lower future development costs in the current year, this translated into a decline on a boe basis to $10.81 in 2021 from $12.15 last year.

Upon an assessment of current market conditions, no potential indicators of impairment or reversals of impairment were noted as of September 30, 2021, and the Company did not assess the carrying values of its cash generating units (“CGUs”). As a result, Questerre recorded no impairment expense or reversal of prior period impairment for the period.

By comparison for the nine month period ended September 30, 2020, the material decline in future crude oil prices as at March 31, 2020 was an indicator of potential impairment in the carrying value of its Plant, Property and Equipment (“PP&E”). The Company subsequently tested its CGUs for impairment in accordance with its accounting policy by comparing the carrying value to the estimated fair value less costs of disposal (“FVLCD”)

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using a discounted cash flow model. As a result of the impairment testing, the Company recorded an impairment expense of $96.3 million in aggregate.

Upon an assessment of current market conditions, the Company also determined that there were no impairment indicators relating to its exploration and evaluation (“E&E”) assets as at September 30, 2021. As a result, no impairment was incurred for the period then ended.

For the nine months ended September 30, 2020, the Company incurred an impairment expense of $14.4 million relating to its E&E assets in the Kakwa area. The Company determined that there were no impairment indicators for its Quebec assets and no impairment was incurred. Furthermore, the Company incurred an impairment expense of $2.3 million related to goodwill on the basis that the FVLCD of its PP&E assets was below the carrying value at March 31, 2020.

Interest expense, other income and share based compensation expense

For the nine months ended September 30, 2021, the Company incurred interest expense of $0.4 million, nominally less than the prior year amount of $0.5 million. The amounts relate to its credit facilities with a Canadian chartered bank. As at September 30, 2021, the amount drawn on the facilities was $7.4 million (2020: $16.2 million) and the effective interest rate was 3.45% (2020: 3.45%). The Company also earned interest income of $0.2 million (2020: $0.4 million) on its cash and term deposits for the period.

Year to date, the Company recorded other income of $0.4 million (2020: nil) representing grants received from the provincial governments of Alberta and Saskatchewan for rehabilitation of existing leases, including abandonment and reclamation work.

Year to date, the Company recorded share based compensation expense of $0.4 million (2020: $0.4 million) net of $0.8 million in expense capitalized during the period (2020: $0.7 million).

Other Comprehensive Income (Loss) and Expenses

In 2021, the Company recorded other comprehensive income of $0.4 million for the third quarter (2020: $0.4 million loss) and a negligible loss year to date (2020: $0.3 million income). These amounts relate to the impact of changes in foreign exchange for the respective periods. The appreciation of the Jordanian dinar resulted in a gain of $0.1 million (2020: $0.2 million loss) on the Company’s dinar denominated assets in the country for the quarter. For the same period, the appreciation in the US dollar resulted in a gain of $0.2 million (2020: $0.2 million loss) on its US dollar denominated investment in Red Leaf Resources Inc. (“Red Leaf”).

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

Net income for the current quarter was $2.0 million (2020: $1.0 million loss) and year to date it was $5.8 million (2020: $117.6 million loss). The variance in the quarter is attributable to the higher petroleum and natural gas revenue, lower depletion and higher other income. Year to date, the variance relates to the $113 million impairment expense in 2020. Including other comprehensive income (loss), the total comprehensive income for the third quarter of the year was $2.4 million (2020: $1.3 million loss) and year to date it was $5.8 million (2020: $117.2 million loss).

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Cash Flow from Operating Activities

For the nine months ended September 30, 2021, net cash from operating activities was $10.3 million compared to $3.8 million last year. The variance is due to the higher adjusted funds flow from operations in the current year. For the quarter, the higher adjusted funds flow and increase in non-cash working capital accounted for the difference over the prior year.

Cash Flow used in Investing Activities

Cash flow used in investing activities for the third quarter was $0.4 million and increased over the prior year due to higher capital spending partly offset by a smaller increase in non-cash working capital related to capital investing. Year to date the lower capital spending and a smaller reduction in non-cash working capital in 2021 accounts for the variance over the prior year.

Cash Flow from Financing Activities

For the third quarter of this year, net cash used in financing activities of $4.6 million reflects the net repayment of its credit facilities. Similarly in the prior year, the Company had a net repayment of $3.2 million. For the year to date periods, the cash flow from financing reflects the net repayments in both years.

Capital Expenditures

	Three	months ended September 30,	months ended September 30,	months ended September 30,	Nine	months ended September 30,	months ended September 30,	months ended September 30,
($ thousands)		2021		2020		2021		2020
Alberta	$	306	$	133	$	402	$	2,219
Saskatchewan, Manitoba and Jordan		31		108		88		581
Quebec		204		107		998		938
Total Company	$	541	$	348	$	1,488	$	3,738

For the nine months ended September 30, 2021, the Company incurred capital expenditures of $1.5 million as follows:

• In Quebec, $1 million for capitalized overhead related to engineering and securing social acceptability for its Clean Tech Energy project; and

• $0.5 million was invested in maintenance for the Company’s other assets.

For the nine months ended September 30, 2020, the Company incurred capital expenditures of $3.7 million as follows:

• In Alberta, $2.2 million was invested to drill a well and expand gas-lift infrastructure on the Kakwa Central joint venture acreage with negligible spending in the second and third quarter of the year;

• In Quebec, $0.9 million for capitalized overhead related to engineering and securing social acceptability for its Clean Tech Energy project; and

• $0.6 million for infrastructure for its pressure maintenance pilot in Saskatchewan along with capitalized overhead related to Jordan.

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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 September 30, 2021, 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.

	November 10,	September 30,	December 31,
(thousands)	2021	2021	2020
Common Shares	428,516	428,516	427,516
Stock Options	30,307	30,307	25,351
Weighted average common shares
Basic		427,871	427,613
Diluted		427,992	427,613

A summary of the Company’s stock option activity for the nine months ended September 30, 2021, and the year ended December 31, 2020 follows:

	September	30, 2021	30, 2021	December	31, 2020	31, 2020
		Weighted			Weighted
	Number of		Average	Number of		Average
	Options		Exercise	Options		Exercise
	(thousands)		Price	(thousands)		Price
Outstanding, beginning of period	25,351	$	0.38	27,087	$	0.40
Granted	8,350		0.18	6,475		0.20
Forfeited/cancelled	(2,344)		0.18	(846)		0.43
Expired	(50)		0.18	(7,365)		0.29
Exercised	(1,000)		0.18	–		–
Outstanding, end of period	30,307	$	0.35	25,351	$	0.38
Exercisable, end of period	19,141	$	0.43	16,191	$	0.42

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 prioritize financial liquidity over growth.

At September 30, 2021, $7.4 million (September 30, 2020: $16.2 million) was drawn on the credit facilities and the Company is compliant with all its covenants under the credit facilities. As a consequence of the foregoing, Management does not believe there is a reasonably foreseeable risk of non-compliance with the covenants for its 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

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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 September 30, 2021 was 4.32 and the covenant was met. See Note 11 of the Financial Statements.

The credit facilities were renewed in the third quarter of 2021 for $16 million. 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 next review is scheduled for the second quarter of 2022.

On the assumption that commodity prices continue to remain stable over the next 12 to 18 months, the Company believes that it should have access to sufficient financial liquidity to meet its foreseeable obligations in the normal course of operations.

Subject to the Kakwa operators’ plans for future development, the Company is assessing its investment in the 2021 future development costs associated with proved reserves in its independent reserves assessment as of December 31, 2020. It anticipates that, as a result, reserves associated with wells not drilled in 2021 will remain in the proved undeveloped 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 September 30, 2021 are as follows:

($ thousands)	2021	2022	2023	2024	Thereafter	Total
Transportation and Processing	$ 2,320	$ 3,337	$ 3,062	$ 2,972	$ 3,618	$ 15,309

In order 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 and Government regulations 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

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“Industry Conditions” sections of the AIF and Note 6 to the audited consolidated financial statements for the year ended December 31, 2020.

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, weakening global relationships, conflict between the U.S. and Iran, isolationist and punitive trade policies, 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. 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 last year have 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 or have to raise funds on unfavourable and highly dilutive terms.

A significant risk to Questerre's ability to advance its Clean Tech Energy project and the development of its assets in Quebec is the legal and regulatory environment in the province. In October 2021, the Quebec Premier announced the intention of the Government to end production of fossil fuels. To date, the Government has not provided any further clarification on the details of this renunciation and the compensation. The Company will continue to monitor developments relating to these matters and the impact on its Quebec assets.

In addition, the global market is also currently volatile due to the uncertainty around how severely COVID-19 will affect long-term global energy consumption. The global economy is reliant on the manufacturing and trade of products and the movement of people, and any slowdown in this process has a chain reaction that impacts energy consumption by both manufacturers and consumers. Travel restrictions announced by various countries as a measure to reduce the spread of COVID-19 have impacted and continued to impact global energy consumption.

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.

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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 in particular. 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 essential 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 expenses 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. The Company anticipates that future development of its Quebec assets will require significant additional capital to be financed by potential future equity issuances, asset dispositions or other means.

Questerre faces a number of 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 managed.

• 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. Management does not expect any counterparty to fail to meet its obligations. 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.

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.

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Substantially all the accounts receivable are with oil and natural gas marketers and, to a much lesser extent, 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 Financial Instruments, the Company made a provision of $0.05 million at September 30, 2021 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 uses 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 September 30, 2021, the Company had no outstanding commodity risk management contracts.

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

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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 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. At September 30, 2021, the Company had credit facilities outstanding of $7.4 million (September 30, 2020: $16.4 million) with an effective rate of 3.45% (2020: 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

Questerre’s petroleum and natural gas reserves and resources 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 of the Canadian Securities Administrators 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 and resources is a subjective process. Forecasts are based on engineering data, projected future rates of production, commodity prices and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of

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reserves and resources will change to reflect updated information. Reserve and resource 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.

Proven 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 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 and resource estimates impact a few areas, in particular, the valuation of property, plant and equipment, exploration and evaluation assets 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 manner in which 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 if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable. Determining if there are facts and circumstances present that indicate that carrying values of the assets may not be recoverable requires Management’s judgment and analysis of the facts and circumstances.

The recoverable amounts of CGUs have been determined based on the higher of value in use (“VIU”) and the fair value less cost of disposal (“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. Following the reduction in the recoverable amounts of the Company’s CGUs as of March 31, 2020, goodwill was assessed and fully impaired. This impairment cannot be reversed should the recoverable amount of the Company’s CGUs increase in the future.

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Asset Retirement Obligation

Determination of the Company’s asset retirement obligation is based on internal estimates using current costs and technology in accordance with existing legislation and industry practice and must also estimate timing, a riskfree rate and inflation rate in the calculation. These estimates are subject to change over time and, as such, may impact the charge against profit or loss. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a risk-free rate. The associated abandonment and retirement costs are capitalized as part of the carrying amount of the related asset. The capitalized amount is depleted on a unit of production basis in accordance with the Company’s depletion policy. Changes to assumptions related to future expected costs, risk-free rates and timing may have a material impact on the amounts presented.

Share Based Compensation

The Company has a stock option plan enabling employees, officers and directors to receive Common Shares or cash at exercise prices equal to the market price or above on the date the option is granted. Under the equity settled method, compensation costs attributable to stock options granted to employees, officers or directors are measured at fair value using the Black-Scholes option pricing model. The assumptions used in the calculation are the volatility of the stock price, risk-free rates of return and the expected lives of the options. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Changes to assumptions may have a material impact on the amounts presented.

Income Tax Accounting

Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing tax laws in each jurisdiction differ significantly from the Company’s estimate, the ability of the Company to realize the deferred tax assets could be impacted.

The determination of the Company’s income and other tax assets or liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax asset or liability may differ significantly from that estimated and recorded by Management.

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. For the purposes of impairment testing, the Company measures the fair value of Red Leaf by valuation techniques such as the net asset value approach.

Accounting Policy Changes

IFRS 3 Business Combinations, has been amended to revise the definition of a business to include an input and a substantive process that together significantly contribute to the ability to create outputs. The amendment to IFRS 3 Business Combinations is effective for the years beginning on or after January 1, 2020. The adoption of this amendment did not have a material impact on its financial statements.

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Disclosure Controls and Procedures and Internal Controls over Financial Reporting

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 July 1, 2021 and ended on September 30, 2021 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.

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Quarterly Financial Information

Quarterly Financial Information
	Sept 30	June 30	Mar 31	Dec 31
($ thousands, except as noted)	2021	2021	2021	2020
Production (boe/d)	1,363	1,479	1,679	1,851
Average Realized Price ($/boe)	58.83	52.72	46.62	35.85
Petroleum and Natural Gas Revenue	7,376	7,095	7,046	6,105
Adjusted Funds Flow from Operations	3,578	4,224	2,885	1,857
Net Income (Loss)	2,006	2,892	908	(75)
Basic and Diluted ($/share)	–	0.01	–	–
Capital Expenditures, net of acquisitions and dispositions	541	450	497	1,621
Working Capital Surplus (Deficit)	1,698	(1,243)	(5,449)	(7,705)
Total Assets	192,709	194,053	194,417	196,177
Shareholders' Equity	158,922	156,316	153,108	152,120
Weighted Average Common Shares Outstanding
Basic (thousands)	428,516	427,571	427,516	427,516
Diluted (thousands)	428,516	427,743	427,879	427,516
	Sept 30	June 30	Mar 31	Dec 31
($ thousands, except as noted)	2020	2020	2020	2019
Production (boe/d)	1,875	2,058	2,078	2,160
Average Realized Price ($/boe)	31.26	18.20	37.12	45.52
Petroleum and Natural Gas Revenue	5,391	3,410	7,018	9,033
Adjusted Funds Flow from Operations	1,623	206	2,460	4,108
Net Income (Loss)	(970)	(2,702)	(113,876)	67,414
Basic and Diluted ($/share)	–	(0.01)	(0.27)	0.14
Capital Expenditures, net of acquisitions and dispositions	348	515	2,875	4,868
Working Capital Surplus (Deficit)	(8,095)	(9,272)	(8,603)	(8,111)
Total Assets	195,925	201,255	204,782	318,062
Shareholders' Equity	152,508	153,509	156,263	268,656
Weighted Average Common Shares Outstanding
Basic (thousands)	427,516	427,516	427,907	427,907
Diluted (thousands)	427,516	427,516	427,907	428,022

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. These increased generally in 2021 following the improvement in commodity prices. They declined materially for the quarter ended June 30, 2020, following the collapse in oil prices.

• Production volumes reflect the capital investment in drilling and completing wells at Kakwa in preceding quarters. With limited capital spending in new wells over the last 18 months, the production volumes have declined.

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• The level of capital expenditures over the quarters has generally declined as capital spending has been limited to preserve financial liquidity.

• The working capital deficit has generally increased when capital expenditures and other investments have been higher than adjusted funds flow from operations and cash from financing activities. In the last three quarters, the working capital deficit has been gradually eliminated as adjusted funds flow from operations has exceeded capital expenditures.

• Shareholders’ equity has generally decreased due to the net losses realized. For the last three quarters, it increased due to the net income in the periods. For the quarter ended March 2020, the significant decrease was attributable to the $113 million impairment expense incurred in the period. In December 2019, it increased due to the gain of $58.5 million on the acquisition of assets in Quebec.

Off-Balance Sheet Transactions

The Company did not engage in any off-balance sheet transactions during the period ended September 30, 2021.

Related Party Transactions

The Company did not engage in any related party transactions during the period ended September 30, 2021.

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