Questerre Energy - Management Reports 2020

This Management’s Discussion and Analysis (“MD&A”) was prepared as of March 20, 2020 and should be read in conjunction with the audited consolidated financial statements of Questerre Energy Corporation (“Questerre” or the “Company”) as at and for the years ended December 31, 2019 and 2018. Additional information relating to Questerre, including Questerre’s Annual Information Form for the year ended December 31, 2019 dated March 20, 2020 (“AIF”), is available on SEDAR under Questerre’s profile at www.sedar.com.

Questerre is 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”.

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.

Certain statements contained within this MD&A constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified 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.

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

The elimination of non-essential capital spending during the next 12 to18 months;
drilling plans and the development and optimization of producing assets;
future production of oil, natural gas and natural gas liquids and the weighting thereof;
future commodity prices in light of recent decisions by OPEC and non-OPEC member countries, including Saudi Arabia and Russia on production levels as well as the coronavirus pandemic;
legislative and regulatory developments in the Province of Quebec;
requirement of significant additional capital to develop the Company’s Quebec assets;

Questerre Energy Corporation

the timing of the development of the Company’s resources in Quebec;
the Company’s focus on engagement with the Government of Quebec to resolve the regulatory uncertainty and secure social acceptability in Quebec;
liquidity and capital resources;
integrating the potential environmental improvements into the economic feasibility assessment in Jordan;
the Company’s negotiations for a concession agreement in Jordan;
the Company’s compliance with the terms of its credit facility;
timing of the next review of the Company’s credit facility by its lender;
identification of additional optimization opportunities for the EcoShale process;
ability of the Company to meet its foreseeable obligations;
expectations regarding the Company’s liquidity increasing over time;
capital expenditures and the funding thereof;
Questerre’s reserves and resources;
impacts of capital expenditures on the Company’s reserves and resources;
the benefits of the joint venture infrastructure in the Kakwa area;
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;
joint venture partner willingness to participate in capital programs;
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:

volatility in market prices for oil, natural gas liquids and natural gas due to, among other things, the production increases by OPEC and non-OPEC member countries, including Saudi Arabia and Russia, on production levels as well as the impact of the coronavirus pandemic;
counterparty credit risk;
access to capital;
the terms and availability of credit facilities;
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;

2019 Annual Report

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 passage of applicable hydrocarbon and environmental legislation and regulations and local acceptability;
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 resources and reserves 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 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.

Barrel of oil equivalent (“boe”) amounts may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil and is based on an energy equivalent conversion method application at the burner tip and does not necessarily represent an economic value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

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

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Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.

This document contains the term “adjusted funds flow from operations”, which is an additional non-GAAP measure. The Company uses this measure to help evaluate its performance.

As an indicator of the Company’s performance, adjusted funds flow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with GAAP. The Company’s determination of adjusted funds flow from operations may not be comparable to that reported by other companies. 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.

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2018
Net cash from operating activities $ 13,091
Interest received (544)
Interest paid 593
Change in non-cash working capital 2,073
Adjusted funds flow from operations $ 15,213
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This document also contains the terms “operating netbacks”, “cash netbacks” and “working capital surplus (deficit)”, 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 (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 the risk management contracts.

2019 Annual Report

			2018	2017
Petroleum and Natural Gas Revenues			32,969	21,361
Adjusted Funds Flow from Operations			15,213	6,780
Basic	and Diluted ($/share)		0.04	0.02
Net Income (Loss)			13,466	(24,821)
Basic	and Diluted ($/share)		0.03	(0.07)
Capital	Expenditures		31,102	27,746
Working		Capital Surplus (Deficit)	(9,078)	9,648
Total Non-Current Financial Liabilities			13,736	15,952
Total Assets			233,372	217,215
Shareholders' Equity			187,291	170,739
Common Shares Outstanding (thousands)			389,007	385,331
Weighted average - basic (thousands)			388,712	350,055
Weighted average - diluted (thousands)			395,715	350,055
Average		Production
Crude Oil and Natural Gas Liquids (bbls/d)			1,263	821
Natural		Gas (Mcf/d)	3,635	3,350
Total (boe/d)			1,869	1,379
Average		Sales Price
Crude Oil and Natural Gas Liquids ($/bbl)			66.27	61.28
Natural		Gas ($/Mcf)	1.82	2.42
Total ($/boe)			48.33	42.44
Netback		($/boe)
Petroleum and Natural Gas Revenues			48.33	42.44
Royalties Expense			(2.76)	(2.17)
Percentage			6%	5%
Operating Expense			(17.09)	(19.93)
Operating Netback			28.48	20.34
General and Administrative Expense			(6.50)	(6.24)
Cash Netback			21.99	14.11
Wells Drilled
Gross			3.00	7.00
Net			0.71	1.60

Questerre Energy Corporation

Focus has turned to addressing the impact of the recent production increases by OPEC and nonOPEC member countries, as well as the coronavirus pandemic
Closed acquisition to regain ownership and operatorship of natural gas discovery in Quebec
Quebec resource assessment includes best estimate of risked economic contingent resources of 1.3 Tcf with a before income tax NPV-10% of $1 billion for approximately 20% of our acreage
Total proved and probable reserves increased over 20% to 35.3 MMBoe with a before income tax NPV-10% of $237.5 million
Advancing engineering and negotiating concession agreement for oil shale project in Jordan
Average daily production of 2,121 boe/d with adjusted funds flow from operations of $14.4 million

Kakwa, Alberta

Consistent with the prior year, development on both joint ventures at Kakwa Central and Kakwa North targeted the condensate-rich Montney formation.

In 2019, the Company invested $19.8 million (2018: $27.7 million) in Kakwa with daily production averaging 1,707 boe/d (2018: 1,474 boe/d). Total proved and probable reserves at December 31, 2019 were estimated at 33.4 MMBoe with a before income tax NPV-10% of $199.5 million. The Company currently holds 40,800 (17,880 net) acres in the Kakwa area.

The investment and production are largely attributable to the Kakwa Central acreage where Questerre holds an approximate 25% interest in 10,080 acres. Five (1.02 net) wells were drilled and six (1.23 net) wells were completed and tied-in during the year. These included the 103/01-29-63-05W6M and the 100/08-29-63-05W6M wells completed in the fourth quarter. During the first thirty days, gross production from these wells averaged a combined 2.0 MMcf/d and 690 bbls/d of condensate and liquids. Questerre holds a 21% working interest in these wells. Though the initial rates from these wells is encouraging, they are not necessarily indicative of long-term performance or ultimate recovery.

In early 2020, the operator spud two wells at Kakwa Central targeting the Lower and Upper Montney. Considering current commodity prices and the limited well results from the Lower Montney to date, the Company did not participate in that well to preserve capital and did participate in the second well targeting the Upper Montney.

Field infrastructure, particularly gas-lift compression and pipelines were also expanded during the year. This investment totalled $6.7 million (2018: $12.4 million). Questerre holds a 25% interest in these and all field facilities. Following a material infrastructure expansion over the last two years, including a new central water storage facility and an addition to the central processing facility, the Company anticipates a limited investment of approximately $2 million in additional facilities in 2020.

At Kakwa North, the operator drilled and completed two additional wells to earn a 50% interest in Kakwa North and Kakwa South. This follows the first two farm-in wells drilled in 2018. Questerre holds a 5% gross overriding royalty in these four wells converting to a 50% working interest after payout. The results from these wells contributed to the material increase in proved and probable reserves in 2019.

2019 Annual Report

In light of the material decline in oil prices in the first quarter of 2020, Questerre will evaluate its selective participation, if any, in the drilling programs proposed by the operators of Kakwa Central and Kakwa North effective January 1, 2020.

At Kakwa Central, this program was to include up to six (1.05 net) wells and the program at Kakwa North was to include up to 3 (1.5 net) wells. In the current environment, the Company anticipates that it will require additional financial liquidity through potential asset dispositions, equity or debt if it plans to participate in the entire drilling programs. There can be no certainty that such financing will be available or on terms acceptable to the Company.

Antler, Saskatchewan

Activities at Antler focused on optimizing existing production and expanding the pilot secondary recovery scheme to increase recovery of the oil in place.

The Company invested $0.4 million (2018: $1.0 million) at Antler with daily production averaging 356 bbl/d (2018: 359 bbl/d). Total proved and probable reserves as at December 31, 2019 were estimated at 1.8 MMBbls (2018: 1.9 MMBbls) with a before income tax NPV-10% of $38.3 million (2018: $40.7 million). The Company currently holds 11,952 net acres in the area.

In 2020, the Company expects to continue its work to enhance existing production through workovers and repairs plus the pilot secondary recovery scheme.

The Company’s main priorities for 2019 were to conclude an agreement to consolidate and regain operatorship of its Quebec acreage and advance its plans to secure social acceptability for its Clean Tech Energy project.

Pursuant to the agreement with a senior exploration and production company, Questerre acquired the exploration rights to 753,000 net acres in the Lowlands, associated wells and equipment, geological and geophysical data and other miscellaneous assets (the “Quebec Acquisition”). Consideration included a mutual release for all claims related to outstanding litigation as described in the Company’s press release dated June 4, 2018. Other consideration included cash, a contingent payment to the vendor on receipt of Government approval to complete a well and security for the assumption of abandonment and reclamation liabilities. Prior to closing adjustments, the total consideration was estimated at $67.1 million in accordance with accounting guidelines. With the payment of consideration and transfer of control, the Quebec Acquisition closed in December 2019 and requisite government approvals received in early 2020.

To advance its Clean Tech Energy project, Questerre signed arrangements with SNC Lavalin and Schlumberger to assist with the engineering and design for this project.

SNC Lavalin, the largest construction company in Canada, will be the lead engineering advisor for the project.

Through its partnership with Schlumberger, the Company has secured access to the Schlumberger Stewardship Tool to model and measure the environmental and social impacts of all stages of natural gas production. By modelling development under the Clean Tech Energy approach and comparing this to a more conventional approach, the tool will calculate the significant reduction in emissions, waste and

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pollution. Questerre intends to make the tool available to all stakeholders to allow them to model and analyze the environmental impacts of its Clean Tech Energy plan for natural gas development.

The Company also engaged Industrial Alliance Securities Inc., a Quebec-based investment firm to provide advisory services with respect to finding Quebec-based strategic investors for its clean-tech energy project. Discussions with the Government of Quebec regarding the closing of the Quebec Acquisition were constructive. Based on the government cooperation, the Company granted deferrals of its scheduled judicial review on the validity of the new oil and gas regulations. These include a selective prohibition on hydraulic fracturing and the increase in setbacks for oil and gas activities. The Company remains of the view that the regulations imposed by the previous Government are ultra vires, or beyond its legal authority.

Securing the social acceptability for its project and engaging with the government to resolve the regulatory situation remain the Company’s priorities for 2020. Should the Company be unsuccessful in its negotiations with the Government or receive an unfavorable ruling for its judicial review, the value of its Quebec assets could be materially impaired.

Following the closing, the Company updated its resource assessment for the acreage as reported on March 16, 2020 (the “Quebec Resource Assessment”). The Quebec Resource Assessment was prepared by GLJ Petroleum Consultants Ltd. effective December 31, 2019. The Quebec Resource Assessment was prepared in accordance with NI 51-101 and the standards contained in the Canadian Oil and Gas Evaluation (“COGE”) Handbook.

The best estimate by the Company’s independent reserve engineers of risked Contingent Resources in the development on hold sub category, net to Questerre, is 1.3 Tcf (214 million barrels of oil equivalent (“MMboe”)) with a before tax NPV-10% of $1 billion. The best estimate of risked Contingent Resources in the development unclarified category, net to Questerre, is 0.4 Tcf (59 MMboe) with a before tax NPV10% of $0.2 billion. The best estimate of risked Prospective Resources net to Questerre is 6.0 Tcf (1,006 MMboe).

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The Quebec Resource Assessment assigned Contingent Resources for approximately 20% of Questerre’s acreage based on the results from several pilot vertical and horizontal wells on Questerre’s acreage that have all encountered pay in the Utica. Furthermore, available test data from these wells in conjunction with offset development and analogy examination of the Utica development in the United States provides sufficient evidence that the evaluated resource is capable of commercial production.

The Company’s Contingent Resources require additional data gathering, the preparation of firm development plans, and regulatory application and approval for development. Therefore the Contingent Resources have been sub-classified as either development on hold or development unclarified. Those areas classified as development on hold are primarily contingent on government and public approval for development. Remaining areas classified as development unclarified have additional contingency or risk

2019 Annual Report

associated with public approval of respective county populations, thereby lowering priority for development by the Company. Additional contingencies include firm development plans, detailed cost estimates and corporate approvals and sanctioning.

Though pilot horizontal development plans have been proposed, the project evaluation scenario for the Contingent Resources is not sufficiently defined by the Company to make an investment decision to proceed to development.

Contingent Resources are evaluated based on the same fiscal conditions used in the assessment of reserves, and as such, are forecasted to be economic. Contingent Resource values are estimated on the basis of established technology, namely multistage hydraulic fracturing recovery technologies that are widely used in the development of the Utica formation in Ohio and in similar plays such as the Marcellus and Western Canadian shale gas plays.

The Contingent Resources have been risked for the chance of commerciality, or commercial development, defined as the product of the chance of discovery and the chance of development. For Contingent Resources, the chance of discovery is equal to one. The chance of development is the estimated probability that once discovered, a known accumulation will be commercially developed. Prospective Resources were also risked for chance of discovery.

Significant positive factors relevant to the estimate of Questerre’s resources include the importation of all natural gas consumed in Quebec creating demand for local production, premium realized pricing due to the transportation costs associated with importing natural gas for consumption, production test data from Questerre’s existing wells and the development of the analogous Utica natural gas field in the United States. Significant negative factors include the limited number of wells on Questerre’s acreage, lack of a developed service sector providing uncertainty regarding estimates of capital and operating costs, hydrocarbon regulations and environmental legislation and the requirement to obtain social acceptability for oil and gas operations.

While Questerre believes it will be able to access sufficient financial capability to fund its share of the costs associated with the development program in the Quebec Resource Assessment, it may not have access to the necessary capital when required.

For more information, please refer to the AIF and the press release dated March 16, 2020 available on the Company’s website at www.questerre.com and on SEDAR at www.sedar.com.

In 2019, Questerre began integrating the goal of minimizing the environmental impacts into the technical and economic feasibility assessment for its oil shale project in Jordan.

The primary objective of the feasibility work is to optimize the processes and improve the economic returns in the current pricing environment. The Company is evaluating several passive drying processes as well as carbon capture and small-scale modular co-generation facilities to achieve these objectives. It is leveraging the engineering work by Hatch Ltd., a global engineering firm, on the EcoShale process to identify additional optimization opportunities.

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During the year, Questerre was advised by the Jordanian Ministry of Energy and Mineral Resources it intends to move forward from a Memorandum of Understanding to a Concession Agreement for the Company’s acreage. This follows the submission and acceptance of the Company’s reports on the exploration work conducted to date. Negotiations on the fiscal and other commercial terms are ongoing. Questerre continues to hold the exclusive exploration rights to the acreage during these negotiations.

Questerre increased its equity interest in Red Leaf Resources Inc., (“Red Leaf”) following a capital restructuring completed by the company in the fourth quarter. Red Leaf concluded an agreement to redeem approximately 96% of its outstanding preferred shares at a discount of over 50% of the face value. The agreement includes the resignation of all the Board nominees for the preferred shareholders and the cancellation of approximately 4% of its issued and outstanding capital.

Post closing of the transaction, Questerre holds common shares representing approximately 33% of the common shares and 16% of the preferred shares outstanding. Red Leaf is a private Utah-based company whose principal assets include approximately US$30 million in cash, their proprietary EcoShale process to produce oil from shale and oil shale leases in the state of Utah.

The Company completed a private placement for gross proceeds of $14.5 million in the second quarter of 2019. The placement consisted on the issuance of 38.9 million Common Shares at a price of $0.39 per Common Share.

Following a review conducted in the fourth quarter, the Company’s credit facilities with a Canadian chartered bank were increased from $18 million to $20 million. The facilities consist primarily of a revolving operating demand loan. Any borrowings under the facilities, except letters of credit, are subject to interest at the Bank’s prime rate and applicable basis point margins based on the ratio of debt to cash flow, measured quarterly. The effective interest rate for 2019 was 4.45%. As at December 31, 2019, approximately $16.4 million was drawn on the facility.

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 scheduled review of the facilities is in the second quarter of 2020.

Five (1.02 net) wells were spud at Kakwa Central during the year. Two additional wells were spud at Kakwa North where the Company holds an overriding royalty interest convertible to a 50% working interest after payout.

2019 Annual Report

		2018
	Oil and	Natural
	Liquids	Gas	Total
	(bbls/d)	(Mcf/d)	(boe/d)
Alberta	879	3,635	1,485
Saskatchewan	359	–	359
Manitoba	25	–	25
	1,263	3,635	1,869

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

Production increased over the prior year with growth in Kakwa from the capital investment and royalty volumes from farm-in wells.

Representing 80% of corporate volumes, Kakwa production increased to 1,707 boe/d from 1,474 boe/d. New royalty volumes at Kakwa North accounted for 189 boe/d or 8% of production over the year. Additionally, at Kakwa Central 6 (1.23 net) wells were brought on production in 2019 with one third at yearend, compared to 5 (1.18 net) wells in the prior year.

Questerre’s oil and liquids production is comprised primarily of light crude oil and condensate and nominal volumes of other natural gas liquids. Natural gas production is shale gas from Kakwa. The liquids weighting decreased marginally over the year to 60% from 68% last year due to higher gas production from Kakwa. Combined production from Saskatchewan and Manitoba increased marginally over the prior year as a result of ongoing optimization and workovers. The Company anticipates its liquids weighting to average approximately 60% reflecting the relative weighting of natural gas liquids to natural gas at Kakwa.

Based on current commodity prices and a focus on preserving balance sheet strength, the Company is considering its participation, if any, in the operators’ original drilling programs of up to six (1.05 net) wells at Kakwa Central and three (1.5 net) wells at Kakwa North.

			2018
		Oil and	Natural
		Liquids	Gas	Total
Alberta	$	20,201	$ 2,414	$ 22,615
Saskatchewan		9,706	–	9,706
Manitoba		648	–	648
	$	30,555	$ 2,414	$ 32,969

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

Year over year, petroleum and natural gas revenue declined by less than 1% to $32.8 million. The increase in total revenue attributable to higher production volumes was almost completely offset by a revenue decrease due to lower realized oil and liquids prices.

Questerre Energy Corporation

	2018
Benchmark prices:
Natural Gas - AECO, daily spot ($/Mcf)	1.34
Crude Oil - Canadian Light Sweet Blend ($/bbl)	69.07
Realized prices:
Natural Gas ($/Mcf)	1.82
Crude Oil and Natural Gas Liquids ($/bbl)	66.27

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

While crude oil prices increased over 2019, the North American benchmark declined over the prior year. West Texas Intermediate (“WTI”) averaged US$57/bbl in 2019 compared to US$65/bbl in the prior year.

Prices generally rose in the first half of the year, supported by commitments from OPEC and Russia to maintain production cuts, declining production from Venezuela and Libya and the US government’s sanction policy towards Iran. In the second half of the year, prices declined in part due to concerns about oversupply with record growth in US production, particularly from the Permian, new major discoveries coming onstream and reduced demand arising from the US-China trade dispute.

In Canada, the mandatory production curtailments in Alberta contributed to a material improvement in the differential between WTI and Canadian condensate and light oil prices in the first half of the year. The condensate differential averaged US$4.20/bbl in 2019 compared to US$13.50/bbl in the fourth quarter of 2018.

In early 2020, crude oil prices experienced the largest decline in almost two decades. This followed the announcement by Saudi Arabia and other OPEC and non-OPEC member countries to increase production above their previously agreed levels after Russia’s decision not to participate in future production cuts. The decline was exacerbated by the reduced global demand due to the coronavirus pandemic.

Realized prices for Questerre’s light oil and natural gas liquids track the Canadian light oil MSW benchmark with condensate often receiving a premium to this price. This is offset by materially lower prices for other natural gas liquids which represent approximately 16% of liquids production.

While US domestic demand and exports of natural gas grew to new highs in 2019, they were surpassed by the continued growth in supply. The benchmark Henry Hub averaged US$2.60/MMBtu in 2019, down from US$3.12/MMBtu in 2018.

US domestic supply grew by almost 8 Bcf/d to over 96 Bcf/d, driven by the Appalachian and Permian basins where new pipelines improved takeaway capacity. This was partly offset by the ongoing growth in LNG from export capacity additions on the Gulf Coast and exports to Mexico, particularly from the Permian Basin. It was also offset by growth for power generation where retirement of coal-fired power plants continues for both economic and environmental reasons.

In Canada, the outlook for natural gas prices improved in the last quarter of the year with changes on the main pipeline system now granting access to storage for all shippers. This materially lowered the

2019 Annual Report

differential between the AECO and Henry Hub benchmarks which exceeded the realized AECO price for the last two years.

The higher heat content natural gas from Kakwa resulted in realized natural gas prices of $1.92/Mcf (2018: $1.82/Mcf) compared to the benchmark AECO price of $1.68/Mcf (2018: $1.34/Mcf).

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2018
Alberta $ 1,223
Saskatchewan 568
Manitoba 94
$ $ 1,885
% of Revenue:
Alberta 5%
Saskatchewan 6%
Manitoba 15%
Total Company 6%
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Gross royalties declined from $1.9 million to $1.6 million in 2019 due to a royalty credit of $0.4 million received during the year for processing the Crown’s share of production through joint facilities at Kakwa.

As a percentage of revenue, royalties decreased to 5% from 6% last year. Royalties on production in Alberta reflect the royalties payable in Kakwa. These include gross overriding royalties and Crown royalties net of the credits for processing the Crown’s share of production and incentive programs.

The Company anticipates its royalty rate on production from Alberta to average approximately 7% reflecting the forecast rate on production from this area.

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2018
Alberta $ 8,325
Saskatchewan 3,129
Manitoba 205
$ 11,659
$/boe:
Alberta 15.36
Saskatchewan 23.88
Manitoba 22.56
Total Company $ 17.09
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Operating costs increased by over 10% to $13.0 million from $11.7 million due to higher costs in Saskatchewan and Kakwa. On a per unit of production basis, these costs decreased marginally to $16.86/boe from $17.09/boe.

Questerre Energy Corporation

With over 80% of the operating costs at Kakwa, including firm transportation and processing commitments, considered fixed, the higher production volumes in the year translated into lower expense on a boe basis. Excluding the effect of royalty production, operating costs on a boe basis remained the same over the prior year.

At Antler, costs increased due to higher maintenance, repair and workover costs. With production volumes relatively unchanged, on a unit of production basis, these costs increased by 26%, commensurate with the increase in gross costs.

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2018
General and administrative expenses, gross $ 5,742
Capitalized expenses and overhead recoveries (1,310)
General and administrative expenses, net $ 4,432
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Gross General & Administrative expenses (“G&A”) decreased by over 10% to $5.1 million from $5.7 million in 2018. Approximately one half of this reduction is due to lower payments under the bonus plan with the remainder attributable to lower overall costs. Capitalized expenses are the administrative costs associated with its projects in Quebec and Jordan and remained unchanged from last year.

On the closing of the Quebec Acquisition, the Company recognized a gain of $58.5 million. This estimate represents the non-cash consideration received by the Company releasing the vendor of the assets from all outstanding litigation. The value of this consideration was based on an independent assessment of its damages related to this litigation. The Company also realized a gain of $6.0 million on the forgiveness of outstanding amounts payable to the vendor as part of the Quebec Acquisition.

For the year ended December 31, 2019, Questerre reported depletion, depreciation and accretion expense of $13.1 million (2018: $12.0 million) with depletion accounting for over 90% of this amount. The higher expense reflects the higher production volumes over the prior year. On a per unit basis, depletion decreased to $16.88/boe from $17.20/boe reflecting the increase in reserve additions relative to property, plant and equipment expenditures and future development costs over the prior year.

At December 31, 2019, the Company reviewed the carrying amounts of its property, plant and equipment and exploration and evaluation assets for indicators of impairment such as changes in future prices, future costs, reserves and discount rates. On the basis of lower future prices, the Company’s CGUs were tested for impairment in accordance with the Company’s accounting policy by comparing the carrying value to the estimated fair value less costs of disposal (“FVLCD”) using a discounted cash flow model. As a result a nominal amount of $0.01 million was recorded for the Other Alberta CGU. In 2018, the Company recorded a reversal of $28.0 million of impairment expense incurred in prior years due to the increase in reserves assigned to the Kakwa area.

2019 Annual Report

Questerre holds approximately one third of the common share capital of Red Leaf. The Company uses the equity method of accounting for its ownership of Red Leaf. Under this method, the Company records its proportionate share of Red Leaf’s net loss and any impairment or reversals of previously recorded impairments are recognized through the income statement.

As a result of the redemption by Red Leaf of most of its preferred shares at less than face value, the Company reassessed the fair value of its investment as at December 31, 2019. The redemption reduced the accrued and unpaid dividends for the preferred shares by over 50%, effectively increasing the net asset value. Consequently, the Company recorded a reversal of previous recorded impairment expense of $8.2 million. By comparison in 2018, the Company recorded an expense of $9.3 million representing its share of the net loss realized by Red Leaf for the year and impairment charges. For more information, please see Note 7 to the Financial Statements.

Pursuant to the Company’s stock option plan, an optionee may request that the Company purchase all or any part of the then vested options of the optionee, for an amount equal to the market price of the Common Shares less the exercise price of the option shares. Notwithstanding the foregoing, the Company may, at its sole discretion, decline to accept and, accordingly, has no obligations with respect to the exercise of this put right at any time. Once the options are cash settled, the options are cancelled.

The Company recorded stock based compensation expense of $1.0 million (2018: $0.7 million), net of $0.7 million (2018: $0.9 million) capitalized for the year ended December 31, 2019.

Questerre reported interest expense of $0.7 million for the year ended December 31, 2019 and $0.6 million for the prior year. The expense primarily relates to the interest on its credit facilities with a Canadian chartered bank. The Company also reported interest income of $0.4 million for the year (2018: $0.5 million). The interest was earned on term deposits held with Canadian chartered institutions.

In the current year, included in Other Comprehensive Income, net of deferred tax, is a loss of $0.2 million due to changes in the foreign exchange for its Jordanian dinar denominated investment in Jordan and its US dollar denominated investment in Red Leaf. In 2018, the Company recorded a gain on foreign exchange of $0.7 million primarily relating to its investment in Red Leaf.

The Company reported a deferred tax expense of $7.0 million for 2019 (2018: $6.1 million).

The expense is due to the net income in the current year and a change in the Alberta provincial tax rate announced in the second quarter of this year. In 2019, the Company assessed the recoverability of this asset using the estimate of before tax cash flows associated with its proved reserves using escalating pricing and future development costs as outlined in its independent reserve report, including an estimate of applicable G&A costs associated with these reserves. Questerre had enough tax pools to offset taxable income in 2019.

Questerre Energy Corporation

Questerre’s total comprehensive income was $65.5 million for 2019 compared to $14.2 million in 2018. The change is attributable to several one-time items related to Quebec Acquisition including the consideration received on the release and the gain on the forgiveness of debt. Additionally in 2019, the Company reversed previously recorded impairment on its investment in Red Leaf. In 2018, the Company’s net income was due to the reversal of impairment expense of $28.0 million offset by the loss related to its investment in Red Leaf.

Questerre’s basic net income was $0.16 per share compared to income of $0.03 per share in 2018. As a result of the gains associated with the Quebec Acquisition, Questerre reported net income was $65.7 million in 2019 compared to net income of $13.5 million in 2018 which reflected the reversal of previously recorded impairment expense of $28.0 million largely offset by the expenses associated with its investment in Red Leaf.

Net cash from operating activities was $11.3 million compared to $13.1 million in 2018. In the current year, this reflects lower adjusted funds flow from operations and a slightly larger reduction in non-cash working capital.

Excluding the Quebec Acquisition, capital expenditures were lower in 2019 compared to 2018. Capital expenditures in both years were predominantly at Kakwa and decreased to $22.1 million in 2019 from $31.1 million in 2018. This resulted in the cash flow used in investing activities decreasing to $24.4 million from $30.4 million in 2018.

The increase in cash from financing activities in the current year is mainly due to the net proceeds of $14.0 million from the private placement completed in the second quarter. The Company also increased its net borrowing under the credit facility by $2.5 million. In the prior year, the company realized proceeds of $0.8 million from the exercise of convertible securities with no material drawdown under its credit facility.

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2018
Alberta $ 27,753
Saskatchewan & Manitoba 1,145
Jordan 1,335
Quebec 869
31,102
Acquisitions –
Total $ 31,102
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Note: Capital expenditures exclude certain non-cash items such as, stock based compensation and asset retirement obligations.

2019 Annual Report

For the year ended December 31, 2019, the Company incurred capital expenditures of $85.4 million as follows:

In Alberta, $19.8 million was invested in wells and infrastructure on the Kakwa Central joint venture acreage;
In Quebec, the Company invested a total of $65 million including $63.4 million for the Quebec Acquisition and the remainder for well maintenance operations and work to secure social acceptability for its Clean Tech Energy project;
In Saskatchewan, $0.5 million to maintain and upgrade production facilities; and
In Jordan, $0.2 million was spent on engineering for its oil shale project.
In 2018, Questerre incurred capital expenditures of $31.1 million as follows:
In Alberta, $27.8 million was to drill, complete and equip wells and expand infrastructure on the Kakwa Central joint venture acreage;
In Jordan, $1.3 million in the technical and economic feasibility assessment of its oil shale project;
In Saskatchewan, $1.1 million to workover wells and expand the secondary recovery pilot; and
In Quebec, $0.9 million to secure social acceptability for its project.

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 significant decline in crude oil price in the first quarter due to the production increases by OPEC and non-OPEC members including, Saudi Arabia and Russia and the fallout from the coronavirus pandemic will have a material impact on the Company’s liquidity in 2020. The Company is evaluating its selective participation, if at all, in the drilling programs at Kakwa as proposed by the operators in January 2020, with the aim of preserving its financial liquidity.

At December 31, 2019, $16.4 million (December 31, 2018: $13.8 million) was drawn on the credit facility and the Company is in compliance with all of 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 its credit facilities. Under the terms of the credit facility, the Company has provided a covenant that it will maintain an Adjusted Working Capital Ratio greater than 1.0. The ratio is defined as current assets (excluding unrealized hedging gains and including undrawn Credit Facility A availability) to current liabilities (excluding bank debt outstanding and unrealized hedging losses). The Adjusted Working Capital Ratio at December 31, 2019 was 2.02 (2018: 1.48) and the covenant was met. See Note 13 to the Financial Statements.

The size of the credit facilities is determined by, among other things, the Company’s current reserve report, results of operations and forecasted commodity prices. The decline in crude prices could have a negative impact on the credit facility review. The next scheduled review is expected to be completed in the second quarter of 2020.

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.

Questerre Energy Corporation

In the current market, the Company may be unable to secure additional financing on acceptable terms, if at all.

Questerre had a working capital deficit of $8.1 million, including amounts due under its credit facilities, of $16.4 million at December 31, 2019, as compared to a deficit $9.1 million at December 31, 2018.

On the assumption that the recent decline in commodity prices does not persist for more than 12 to 18 months, Management believes that with its expected positive operating cash flows from operations and current credit facilities, the Company should generate sufficient cash flows and have access to sufficient financial liquidity to meet its foreseeable obligations in the normal course of operations. The Company intends to eliminate any non-essential capital spending during this period to preserve financial liquidity.

On the basis the current decline in commodity prices is short term, a future improvement in commodity prices should improve cash flow and reduce the working capital deficit. This will likely result in additional adjusted funds flow from operations being available to finance planned capital expenditures. On an ongoing basis, the Company will manage where possible future capital expenditures to maintain liquidity (See “Commitments”).

In light of current market conditions, the Company is assessing its investment in the 2020 future development costs associated with proved reserves in its independent reserves assessment as of December 31, 2019. It anticipates that, as a result, reserves associated with wells not drilled in 2019 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.

The Company is authorized to issue an unlimited number of Common Shares. The Company is also authorized to issue an unlimited number of Class “B” Common voting shares and an unlimited number of preferred shares, issuable in one or more series. At December 31, 2019, there were no Class “B” common voting shares or preferred shares outstanding.

The following table provides a summary of the outstanding Common Shares and options as at the date of the MD&A and the current and preceding year-ends.

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December 31,
2018
Common Shares 389,007
Stock Options 21,412
Weighted average Common Shares
Basic 388,712
Diluted 395,715
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2019 Annual Report

A summary of the Company’s stock option activity during the years ended December 31, 2019 and 2018 follows:


		December 31, 2018
		Number of Weighted Options Average Exercise Price
Outstanding, beginning of period Granted Forfeited Expired Exercised		21,387 $ 0.50 3,288 0.48 (150) 0.52 (3,003) 0.88 (110) 0.42
Outstanding, end of period		21,412 $ 0.44
Exercisable, end of period		10,403 $ 0.34

A summary of the Company’s net commitments at December 31, 2019 follows:

		2020		2021		2022		2023		2024	Thereafter	Total
Transportation, Marketing and Processing	$	4,084	$	4,728	$	3,990	$	3,990	$	3,990	$ 7,982	$ 28,764
	$	4,084	$	4,728	$	3,990	$	3,990	$	3,990	$7,982	$28,764

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.

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 “Industry Conditions” sections of the AIF and Note 6 to the audited consolidated financial statements for the year ended December 31, 2019.

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 the Organization of the Petroleum Exporting Countries (“OPEC”) and non-OPEC member countries’ decisions, including recent decisions by Saudi Arabia and Russia, on production growth and spare capacity, market volatility and disruptions, 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

Questerre Energy Corporation

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 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 to raise funds on unfavourable and highly dilutive terms.

In addition, the global market is also currently volatile due to the uncertainty around how severely the novel coronavirus (COVID-19) pandemic will affect 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. As a result of the pandemic’s impact on the global economy, commodity prices declined prior to the production announcements by members of OPEC and non-OPEC members, including Saudi Arabia and Russia, there may be a further weakening as the effects move through the supply chain. Travel restrictions announced by various countries as a measure to reduce the spread of COVID-19 may also 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.

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 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

2019 Annual Report

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 controlled.
Farm-outs of projects may be arranged if management considers that a project requires too much capital or where the project affects the Company’s risk profile.

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

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

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

Accounts receivable related to the sale of the Company’s petroleum and natural gas production is paid in the following month from major oil and natural gas marketing and infrastructure companies and the Company has not experienced any credit loss relating to these sales to date. Pursuant to IFRS 9, the Company made a provision of $0.3 million at December 31, 2019 for its expected credit losses related to its accounts receivable.

Questerre Energy Corporation

Receivables from joint venture partners are typically collected within one to three months after the joint venture bill is issued. The Company mitigates this risk by obtaining pre-approval of significant capital expenditures.

The Company has issued and may continue in the future to issue flow-through shares to investors. The Company has historically used its best efforts to ensure that qualifying expenditures of Canadian Exploration Expense ("CEE") are incurred in order to meet its flow-through obligations. In 2017, the Federal Government amended the law regarding what expenses constitute CEE. Generally, oil and gas drilling expenses are now Canadian Development Expense rather than CEE. In the event that the Company has CEE expenditures reclassified under audit by the Canada Revenue Agency or fails to incur expenditures required under a flow-through share agreement, the Company may be required to liquidate certain of its assets in order to meet the indemnity obligations under flow-through share subscription agreements.

Exploration and development drilling risks are managed through the use of geological and geophysical interpretation technology, employing technical professionals and working in areas where those individuals have experience. For its non-operated properties, the Company strives to develop a good working relationship with the operator and monitors the operational activity on the property. The Company also carries appropriate insurance coverage for risks associated with its operations.

The Company may use financial instruments to reduce corporate risk in certain situations. Questerre’s hedging policy is up to a maximum of 40% of total production at management’s discretion.

As at December 31, 2019, the Company had no outstanding commodity risk management contract in place.

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 alternatives 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,

2019 Annual Report

increasing the Corporation’s operating expenses, each of which may have a material adverse effect on the Corporation’s profitability and financial condition. Further, the imposition of carbon taxes puts the Corporation at a disadvantage with the Corporation’s counterparts who operate in jurisdictions where there are less costly carbon regulations.

Interest rate risk is the risk that changes in the applicable interest rates for its credit facilities will impact the Company’s interest expense. At December 31, 2019, the Company had credit facilities outstanding of $16.4 million (December 31, 2018: $13.8 million) with an effective rate of 4.45% (2018: 4.14%).

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.

All of Questerre’s petroleum and natural gas reserves and resources are evaluated and reported on by independent petroleum engineering consultants in accordance with NI 51-101 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 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 actually recovered will equal or exceed the estimated proved plus probable reserves and there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.

Reserve and resource estimates impact a number of the areas, in particular, the valuation of property, plant and equipment, exploration and evaluation assets and the calculation of depletion.

Questerre Energy Corporation

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.

The Company assesses its oil and natural gas properties, including exploration and evaluation assets, for possible impairment or reversal of previously recognized impairments if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable or indications that previously recognized losses should be reversed. Determining if there are facts and circumstances present that indicate that carrying values of the assets may not be recoverable requires management’s judgment and analysis of the facts and circumstances.

The recoverable amounts of CGUs have been determined based on the higher of value in use (“VIU”) and the FVLCD. The key assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes, the discount rate, future operating and development costs and recent land transactions. Changes to these assumptions will affect the recoverable amounts of the CGUs and may require a material adjustment to their related carrying value.

Goodwill is the excess of the purchase price paid over the fair value of the net assets acquired. Since goodwill results from purchase accounting, it is imprecise and requires judgment in the determination of the fair value of assets and liabilities. Goodwill is assessed for impairment on an operating segment level based on the recoverable amount for each CGU of the Company. Therefore, impairment of goodwill uses the same key judgments and assumptions noted above for impairment of assets.

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

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

2019 Annual Report

actual number of options that vest. Changes to assumptions may have a material impact on the amounts presented.

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 Company has revised its estimate related to deferred tax assets in the year. Since December 31, 2016, the recoverability of deferred tax assets is assessed using proved reserves including an estimate of G&A associated with the assets.

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

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. The net asset value is based on the net current assets of Red Leaf less the face value and accrued dividends for its preferred shares. The primary risk related to the investment in Red Leaf is the decline in the net current assets of the company without a sufficient advancement in the engineering for the EcoShale process.

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Along with adoption of both IFRS 9 and IFRS 15 effective January 1, 2018, the Company adopted effective January 1, 2019. See Note 19 to the Financial Statements.

The following standards and interpretations have not been illustrated as they will only be applied for the first time in future periods. They may result in consequential changes to the accounting policies and other note disclosures. The Company is currently evaluating the impact of adopting these standards on its consolidated financial statements.

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 Company is currently assessing the impact of this amendment.

Questerre Energy Corporation

Questerre is required to comply with National Instrument 52-109 “

” (“NI 52-109”) and is required to make specific disclosures with respect to NI 52-109 as follows:

The Company has designed and evaluated the effectiveness of Disclosure Controls and Procedures (“DC&P”). The President and Chief Executive Officer and the Chief Financial Officer have concluded that DC&P are designed appropriately and are operating effectively as at December 31, 2019.
The Chief Executive Officer and the Chief Financial Officer have designed, or caused to be designed under their supervision, internal controls over financial reporting (“ICFR”), in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Chief Executive Officer and the Chief Financial Officer have evaluated the effectiveness of the Company’s ICFR as at December 31, 2019 and have concluded that such ICFR have been designed appropriately and are operating effectively.
The Company reports that no changes were made to ICFR during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect the Company’s ICFR.

It should be noted that a control system, including the Company’s disclosure and internal controls and procedures, no matter how well conceived can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met, and it should not be expected that the disclosure and internal controls and procedures will prevent all errors or fraud.

In the last quarter of 2019, petroleum and natural gas revenue increased by 40% to $9.0 million from $6.5 million in the same period in 2018. A nominal increase in production volumes accounted for 20% of the $2.5 million in incremental revenue with materially higher oil and liquids prices account for the remainder.

The increase in production is due to higher volumes from Saskatchewan and Manitoba. Volumes in Kakwa remained relatively flat as the two new wells in 2019 were completed and tied-in late in the quarter. Realized oil prices increased to $61.21/bbl in the current year from $45.96/bbl in the prior year. While benchmark oil prices in the fourth quarter of this year were lower than 2018, the discount between WTI and Canadian condensate prices was materially smaller in 2019, accounting for the higher realized price.

Quarterly operating costs decreased slightly to $3.3 million from $3.5 million, mainly because of lower costs in Saskatchewan while operating costs in Kakwa remained largely flat year over year. On a boe basis the higher volumes resulted in a reduction in operating costs to $16.75/boe from $18.75/boe.

During the quarter the Company reversed previously recorded impairment and realized a gain of $8.2 million (2018: $4.2 million loss) on its investment in Red Leaf. This follows the capital restructuring completed by the company in the quarter which resulted in an increase in the carrying value of Questerre’s investment. The Company also recorded a gain of $58.5 million on the Quebec Acquisition and an additional gain of $6.0 million on the forgiveness of outstanding amounts due to the vendor.

The Company reported total quarterly comprehensive income of $67.2 million due to the one time items related to the Quebec Acquisition and the gain on investment in Red Leaf. By comparison in the fourth quarter of 2018, the quarterly comprehensive income was $15.2 million due to the reversal of previously

2019 Annual Report

recorded impairment expense in Kakwa of $28.0 million offset by the loss on investment in Red Leaf of $4.2 million.

In the fourth quarter, net cash from operating activities increased to $4.1 million from $1.8 million last year. This reflects higher adjusted funds flow from operations in the current year as well as an increase in noncash working capital. Capital expenditures in the quarter decreased to $7.9 million in 2019 from $8.9 million in the same period last year.

		September 30,	June 30,	March 31,
		2019	2019	2019
Production (boe/d)		2,343	2,035	1,944
Average Realized Price ($/boe)		40.33	43.30	40.61
Petroleum and Natural Gas Sales		8,690	8,019	7,105
Adjusted Funds Flow from Operations		5,038	2,662	2,547
Net Profit (Loss)		1,331	(2,099)	(934)
Basic and Diluted ($/share)		–	(0.01)	–
Capital Expenditures, net of acquisitions and dispositions		6,756	7,496	2,941
Working Capital Surplus (Deficit)		(2,573)	(776)	(9,543)
Total Assets		251,454	248,070	231,975
Shareholders' Equity		200,966	199,108	186,812
Weighted Average Common Shares
Outstanding
Basic (thousands)		427,907	417,220	389,007
Diluted (thousands)		428,591	417,220	389,007

	December 31,	September 30,	June 30,	March 31,
	2018	2018	2018	2018
Production (boe/d)	2,033	1,414	2,016	2,013
Average Realized Price ($/boe)	34.35	52.98	54.91	52.66
Petroleum and Natural Gas Sales	6,462	6,892	10,074	9,541
Adjusted Funds Flow from Operations	1,929	2,620	6,012	4,652
Net Profit (Loss)	14,858	(2,023)	572	59
Basic and Diluted ($/share)	(0.01)	(0.01)	–	–
Capital Expenditures, net of acquisitions and dispositions	8,785	6,077	7,452	8,663
Working Capital Surplus (Deficit)	(9,077)	(2,374)	1,239	2,804
Total Assets	233,372	218,630	220,043	218,346
Shareholders' Equity	187,291	171,648	173,464	172,123
Weighted Average Common Shares
Outstanding
Basic (thousands)	388,412	388,412	387,862	387,848
Diluted (thousands)	392,612	388,412	395,552	396,285

Questerre Energy Corporation

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

Petroleum and natural gas revenues and adjusted funds flow from operations have fluctuated with production volumes and realized commodity prices.
Production volumes reflect the capital investment in drilling and completing wells at Kakwa in preceding quarters. Following increased investment in Kakwa in 2017, production has grown to 2,160 boe/d in the most recent quarter. The Company plans to continue to invest at Kakwa, subject to commodity prices and results, and expects a commensurate increase in production.
The level of capital expenditure over the quarter has varied largely due to the timing and number of wells drilled and completed for the Kakwa asset as well as the timing of the infrastructure investment.
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.
Shareholders’ equity increased in the quarters ended December 31, 2019, June 30, 2019 and December 31, 2018 as a result of increases in net income or as a result of the equity issuances completed by the Company during those periods.

The Company did not engage in any off-balance sheet transactions during the year ended December 31, 2019, other than commitments as disclosed.

The Company did not engage in any related party transactions during the year ended December 31, 2019, other than key management compensation as disclosed.

2019 Annual Report

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Questerre Energy Management Reports 2020

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Kakwa, Alberta

Antler, Saskatchewan

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Questerre Energy — Management Reports 2020

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Kakwa, Alberta

Antler, Saskatchewan

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Questerre Energy Management Reports 2020