XOSL:QEC ESEF Annual Report
QUESTERRE EN PREF (XOSL:QEC)
President’s Message
We were blindsided by the Government’s decision to revoke our licenses in Quebec.
With our zero-emissions gas, we delivered a real solution towards their climate goals and the proof of social acceptability they wanted. So, it is incredibly disappointing to see them take a futile block and ban approach while they continue to import gas that supplies over 13% of their energy needs. Moreover, their proposed compensation by no means recognizes the value of the discovery we made after a significant investment over the last twenty years. While we await the final legislation including any revisions to the provisions for pilot projects such as ours and compensation, we have preserved our legal position to protect our rights.
Resurging demand led to stronger oil prices and higher natural gas prices, particularly in the last quarter, as a result of an LNG shortage and unreliable renewable power in Europe. We took advantage of these prices to almost completely pay off the net borrowings under our credit facility and improve our liquidity. This was one of our main goals during the pandemic. We also resumed drilling at Kakwa late in the year and participated in three (0.75 net) wells.
Higher oil prices also saw renewed interest in Red Leaf, our investee company. They have reengineered their proprietary technology to produce oil at prices below US$40/bbl and near-zero emissions. Engineering is now underway for a small-scale commercial plant to validate this design and the potential to co-produce rare earth elements from their Seep Ridge project. When proven this could be a game-changer for our project in Jordan.
Early this year, they exercised on a secured interest and acquired a 7,000-acre parcel in the oil-producing Uinta basin in Utah. The land is permitted for an upgrader and the terminus for a new rail line. These should improve egress and economics for producers in this captive basin where production currently averages over 80,000 bbl/d.
Though the Government appears to have reneged on their license agreements with us, we not only kept our end of the bargain but fulfilled all their subsequent prerequisites, particularly related to social acceptability.
Our exploration licenses were originally granted by the Government of Quebec under the ‘free mining principle’ as still detailed on their website. It promises that if we made a discovery, we would be entitled to produce the resource. However, after we made the discovery, over the next ten years the Government decided to defer development and conduct a series of environmental assessments as well as introduce new hydrocarbon and environmental legislation. They advised us, even as late as the fall of 2018, that to secure regulatory approval, we must secure social acceptability.
We committed to this goal, engaging in extensive consultation with stakeholders to address their concerns about development. By engineering our project to virtually eliminate emissions, we were able to secure interest from the town offsetting our discovery to host a pilot project and directly participate through our profit-sharing program. A local farming group also expressed interest in our Clean Gas as a reliable and cost-effective alternative to propane for their heating needs. Early this year, we entered into an agreement with the Wolinak of Abenaki First Nation for development on their traditional use lands in the Becancour area in return for a net profit interest and an equity right to participate in future development.
On a broader basis across the province, polling data confirms that decided Quebecers support local development by a margin of 2:1 or over 66%. For production from a pilot project with no GHG emissions, this support increases to just over 77% of decided Quebecers with 12% having no opinion. Nearly 85% of decided Quebecers agree that the Government should give First Nations the opportunity to participate in pilot projects that demonstrate zero-emissions natural gas production with 15% holding no opinion. This has been further substantiated by more recent polls following the Russian invasion of Ukraine.
It is puzzling that after making consultation a prerequisite for us, they did not invite impacted stakeholders, including the First Nations and towns to the parliamentary hearings for Bill 21. This appears to conflict directly with Federal legislation including UNDRIP, the United Nations Declaration on the Rights of Indigenous Peoples Act. This requires the free, prior and informed consent of First Nations on all matters particularly related to resource development.
We never expected the compensation would be equivalent to the value from developing the discovery, but we expected to be treated fairly. We were shocked by the proposal in the draft legislation. Though the Government has acknowledged the potential impact on Quebec’s reputation and the Premier’s comments that the province is not a ‘banana republic’, the legislation effectively confiscates our discovery. Subject to the final law, we will vigorously dispute this compensation as part of pending legal action.
Operating & Financial
The impact of production declines from the lack of drilling in the last two years were more than offset by higher commodity prices. We generated adjusted funds flow from operations of $14.5 million (2021: $6.1 million) with daily production averaging 1,480 boe/d (2020: 1,966 boe/d). With new wells expected onstream in the second quarter this year and the potential reversion of our royalty interest in Kakwa North to a working interest, we anticipate our production could grow materially in the second half of this year.
The outlook for higher commodity prices also increased the value of our proved and probable reserves. We replaced existing production and the NPV-10% increased 70% to $270 million. This led to a reversal of a $92 million impairment charge booked last year which was offset by the $104 million impairment charge related to our entire Quebec assets.
Subject to the operators at Kakwa accelerating development plans, we expect our current capital spending of $9 million in the year to be fully funded by adjusted funds flow from operations.
Outlook
It is still difficult for us to believe that a project that has such strong environmental, social and economic benefits could be banned for what we can only presume is for political reasons. As the European Union seeks reliable and reputable suppliers to cut their dependence on Russian gas, Quebec is missing an incredible opportunity to make a difference.
Our main goal for this year will be to ensure to the best of our ability that our shareholders receive fair, just and adequate compensation for their investment of time and money to make our discovery.
Michael Binnion
President and Chief Executive Officer
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Environmental, Social and Governance
Questerre believes the oil and gas industry can go from laggards to leaders on the global environment.
From today to 2050, the world’s population is estimated to grow from 7.5 billion to almost 9.5 billion people who will expect a better standard of living. We believe providing the increased energy needed tomorrow, with lower environmental impacts than today, is the challenge of our times. We refer to this as the ‘7 to 9 challenge.’ Transitioning our energy diet to lower emissions is essential to meet this challenge and we believe the oil and gas industry has the biggest improvements to make.
Our Clean Tech Energy project to deliver the world’s first zero emissions natural gas production is an example of meeting this challenge. It will have a dramatic impact on the emissions from production in addition to other environmental criteria. It will also contribute to reducing the emissions from consumption by providing a cleaner burning alternative domestically and internationally through LNG exports. We are also looking at hydrogen production combined with carbon capture to further reduce the emissions from consumption.
It requires a new way of thinking to become leaders on environmental issues. Our industry runs most of today’s energy systems. We have the experience, expertise, capital and technology to meet the world’s energy and environmental challenges. Delivering on projects like our zero emissions natural gas project is just one example of how our industry can be leaders on transitioning our global energy systems.
Questerre has also taken leadership in working with communities and First Nations for local benefits. We have committed to share 3% of our profits with them. We have also engaged with local First Nations to include them in our contracting and benefits program.
We unilaterally made the decision not to work in communities where the plurality of the community does not want development. Our approach of consulting first and applying for permits second is consistent with this approach.
People know they need energy to maintain progress for their families and communities. They want to know the providers of that energy are being responsible and sustainable in the way it is produced. Questerre is an entrepreneurial leader in making the seemingly impossible task of producing more with less impact, possible. Our zero emissions Clean Tech Energy project is our contribution to meeting this ‘7 to 9 challenge.’
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Management’s Discussion and Analysis
This Management’s Discussion and Analysis (“MD&A”) was prepared as of March 24, 2022 and should be read in conjunction with the audited consolidated financial statements of
Questerre is an energy technology and innovative company actively involved in the acquisition, exploration and development of oil and gas projects, and, in specific, non-conventional projects such as tight oil, oil shale, shale oil and shale gas. Questerre is committed to the economic development of its resources in an environmentally conscious and socially responsible manner. The Company’s Class “A” Common voting shares (“Common Shares”) are listed on the Toronto Stock Exchange and the Oslo Stock Exchange under the symbol “QEC”.
Basis of Presentation
Questerre presents figures in the MD&A using accounting policies within the framework of International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board, representing generally accepted accounting principles (“GAAP”). All financial information is reported in Canadian dollars, unless otherwise noted.
Forward-Looking Statements
Certain statements contained within this MD&A constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified using the use of words such as “anticipate”, “assume”, “believe”, “budget”, “can”, “commitment”, “continue”, “could”, “estimate”, “expect”, “forecast”, “foreseeable”, “future”, “intend”, “may”, “might”, “plan”, “potential”, “project”, “will” and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Management believes the expectations reflected in those forward-looking statements are reasonable, but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. These statements speak only as of the date of this MD&A.
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:
| ● | drilling plans and the development and optimization of producing assets; |
| ● | the timing of payout on the four original wells drilled on the Kakwa North acreage; |
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| ● | future production of oil, natural gas and natural gas liquids; |
| ● | future commodity prices in light of decisions by OPEC and non-OPEC member countries, including Saudi Arabia and Russia on production levels, the war in Ukraine, as well as the impacts of COVID-19; |
| ● | legislative and regulatory developments in the Province of Quebec; |
| ● | the enhancement of existing production through workovers and monitoring of the pilot secondary recovery scheme at Antler; |
| ● | the transfer of wells drilled in 2022 from the proved undeveloped to the proved producing category; |
| ● | the development of producing assets to execute the Company business strategy; |
| ● | hedging policy; |
| ● | the Company’s focus on securing social acceptability in Quebec; |
| ● | liquidity and capital resources; |
| ● | the Company’s negotiations and finalization of a concession agreement in Jordan and the seeking of partners for a small-scale commercial demonstration project; |
| ● | the Company’s compliance with the terms of its credit facility; |
| ● | timing of the next review of the Company’s credit facility by its lender; |
| ● | ability of the Company to meet its foreseeable obligations; |
| ● | capital expenditures and the funding thereof; |
| ● | Questerre’s reserves; |
| ● | impacts of capital expenditures on the Company’s reserves; |
| ● | 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; |
| ● | the timing of receivables from joint venture partners; |
| ● | flow-through shares and use of proceeds and renunciation and indemnity obligations associated therewith; |
| ● | insurance; |
| ● | use of financial instruments; and |
| ● | critical accounting estimates. |
The actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this MD&A, the AIF, and the documents incorporated by reference into this document:
| ● | Quebec’s Bill 21, the revocation of licenses in Quebec and potential compensation; |
| ● | volatility in market prices for oil, natural gas liquids and natural gas due to, among other things, the production agreements between OPEC and non-OPEC member countries, including Saudi Arabia and Russia, on production levels, the war in Ukraine, as well as the impact of COVID-19; |
| ● | access to capital; |
| ● | the terms and availability of credit facilities; |
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| ● | counterparty credit risk; |
| ● | changes or fluctuations in oil, natural gas liquids and natural gas production levels; |
| ● | liabilities inherent in oil and natural gas operations; |
| ● | adverse judicial rulings, regulatory rulings, orders and decisions; |
| ● | attracting, retaining and motivating skilled personnel; |
| ● | uncertainties associated with estimating oil and natural gas reserves and resources; |
| ● | insufficient advancement by Red Leaf in the engineering of its EcoShale process; |
| ● | competition for, cost and availability of, among other things, capital, acquisitions of reserves, undeveloped lands, equipment, skilled personnel and services; |
| ● | incorrect assessments of the value of acquisitions and targeted exploration and development assets; |
| ● | fluctuations in foreign exchange or interest rates; |
| ● | stock market volatility, market valuations and the market value of the securities of Questerre; |
| ● | failure to realize the anticipated benefits of acquisitions; |
| ● | actions by governmental or regulatory authorities, including changes in royalty structures and programs, and income tax laws or changes in tax laws and incentive programs relating to the oil and gas industry; |
| ● | limitations on insurance; |
| ● | changes in environmental, tax, or other legislation applicable to the Company’s operations, and its ability to comply with current and future environmental and other laws; and |
| ● | geological, technical, drilling and processing problems, and other difficulties in producing oil, natural gas liquids and natural gas reserves. |
Statements relating to reserves are by their nature deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future.
The discounted and undiscounted net present values of future net revenue attributable to reserves do not represent the fair market value thereof.
Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained in this MD&A and the documents incorporated by reference herein are expressly qualified by this cautionary statement. We do not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities law. Certain information set out herein with respect to forecasted results is “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure regarding the Company’s reasonable expectations as to the anticipated results of its proposed business activities. Readers are cautioned that this financial outlook may not be appropriate for other purposes.
BOE Conversions
Barrel of oil equivalent (“boe”) amounts may be misleading, particularly if used in isolation. A boe conversion ratio has been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil, and is based on an energy equivalent conversion method application at the burner tip and does not necessarily represent an economic value equivalency at the wellhead. Given that the value ratio based on the current price
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of crude oil as compared to natural gas is significantly different from the energy equivalent of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.
Non-GAAP Measures
This document contains certain financial measures, as described below, which do not have standardized meanings prescribed under GAAP. As these measures are commonly used in the oil and gas industry, the Company believes that their inclusion is useful to investors. The reader is cautioned that these amounts may not be directly comparable to measures for other companies where similar terminology is used.
This document contains the term “adjusted funds flow from operations”, which is an additional non-GAAP measure. The Company uses this measure to help evaluate its performance.
As an indicator of the Company’s performance, adjusted funds flow from operations should not be considered as an alternative to, or more meaningful than, net cash from operating activities as determined in accordance with GAAP. The Company’s determination of adjusted funds flow from operations may not be comparable to that reported by other companies. 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
($ thousands) |
| 2021 |
| 2020 | ||
Net cash from operating activities | $ | 14,075 | $ | 6,408 | ||
Interest received | (207) | (321) | ||||
Interest paid | 433 | 619 | ||||
Change in non-cash working capital | 176 | (560) | ||||
Adjusted funds flow from operations | $ | 14,477 | $ | 6,146 | ||
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 any outstanding risk management contracts.
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Select Annual Information
As at/for the years ended December 31, |
| 2021 |
| 2020 |
| 2019 |
Financial ($ thousands, except as noted) | ||||||
Petroleum and Natural Gas Revenue | 30,404 | 21,924 | 32,847 | |||
Adjusted Funds Flow from Operations | 14,477 | 6,146 | 14,355 | |||
Basic and Diluted ($/share) | 0.03 | 0.01 | 0.03 | |||
Net Income (Loss) | (4,301) | (117,623) | 65,704 | |||
Basic and Diluted ($/share) | (0.01) | (0.28) | 0.16 | |||
Capital Expenditures | 4,665 | 5,622 | 85,429 | |||
Working Capital Surplus (Deficit) (1) | 1,834 | (7,705) | (8,110) | |||
Total Non-Current Financial Liabilities | 1,975 | 2,025 | 1,838 | |||
Total Assets | 184,264 | 196,177 | 318,062 | |||
Shareholders' Equity | 148,961 | 152,120 | 268,656 | |||
Common Shares Outstanding (thousands) | 428,516 | 427,516 | 427,907 | |||
Weighted average - basic (thousands) | 428,034 | 427,613 | 415,651 | |||
Weighted average - diluted (thousands) | 428,034 | 427,613 | 417,041 | |||
Operations (units as noted) | ||||||
Average Production | ||||||
Crude Oil and Natural Gas Liquids (bbls/d) | 890 | 1,278 | 1,357 | |||
Natural Gas (Mcf/d) | 3,538 | 4,126 | 4,586 | |||
Total (boe/d) | 1,480 | 1,966 | 2,121 | |||
Average Sales Price (2) | ||||||
Crude Oil and Natural Gas Liquids ($/bbl) | 84.81 | 41.80 | 64.12 | |||
Natural Gas ($/Mcf) | 3.84 | 2.51 | 1.92 | |||
Total ($/boe) | 56.34 | 30.47 | 42.43 | |||
Netback ($/boe) | ||||||
Petroleum and Natural Gas Revenue (3) | 56.34 | 30.47 | 42.43 | |||
Royalties Expense (3) | (3.46) | (1.83) | (2.09) | |||
Percentage | 6% | 6% | 5% | |||
Operating Expense (3) | (21.81) | (16.60) | (16.86) | |||
Operating Netback | 31.06 | 12.04 | 23.49 | |||
General and Administrative Expense (3) | (4.46) | (3.52) | (4.93) | |||
Cash Netback | 26.59 | 8.52 | 18.56 | |||
Wells Drilled | ||||||
Gross | 3.00 | 1.00 | 5.00 | |||
Net | 0.75 | 0.25 | 1.02 | |||
(1) Refer to the Current Assets and Current Liabilities in the Balance Sheet for the years ended December 31, 2021 and 2020. | ||||||
(2) Refer to Note 15 in the Consolidated Financial Statements for the years ended December 31, 2021 and 2020. | ||||||
(3) Refer to Consolidated Statement of Comprehensive Loss and Comprehensive Loss for the years ended December 31, 2021 and 2020. | ||||||
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Highlights
| ● | Kakwa drilling activity resumes with higher commodity prices |
| ● | In spite of substantial progress towards achieving social acceptability, the Government of Quebec introduces legislation to revoke licenses |
| ● | Total proved and probable reserves remain unchanged at 33 MMBoe with a before tax NPV-10% increasing by over 70% to $270 million with higher future commodity prices |
| ● | Average daily production of 1,480 boe/d with adjusted funds flow from operations of $14.5 million |
2021 Activities
Western Canada
Kakwa, Alberta
Following a nearly two-year hiatus, drilling activity resumed at Kakwa Central last fall with the improvement in oil prices.
Capital investment in Kakwa totalled $3.2 million for the year (2020: $3.9 million) with daily production averaging 1,174 boe/d (2020: 1,609 boe/d) comprising of 3.5 MMcf/d of natural gas (2020: 4.1 MMcf/d) and 589 bbl/d of condensate and natural gas liquids (2020: 925 bbl/d). Total proved and probable reserves as of December 31, 2021, were estimated at 31.5 MMBoe (2020: 31.5 MMBoe) with a before tax NPV-10% of $234.2 million (2020: $134.5 million). The Company currently holds 40,800 (17,880 net) acres in the Kakwa area.
At Kakwa Central, the operator spud three wells in the year compared to two wells in the prior year. Completion activities are underway in the first quarter and the wells are scheduled to be on production early in the second quarter. The Company participated in all three wells (0.75 net) spud in 2021 compared to only one (0.25 net) well the prior year.
Limited activity was conducted at the Kakwa North acreage, following the acquisition of the operator by a mid-size company in the second quarter. The Company holds a 5% royalty interest in the four original farm-in wells converting into a 50% working interest after payout. The Company anticipates that based on current commodity prices, these wells could achieve payout during the latter part of 2022.
With the improvement in commodity prices, the operators are assessing drilling programs for both joint ventures for the next 12-18 months. The Company’s participation will depend on among other things, available cash flow from operations and incremental financial liquidity through potential asset dispositions, equity or debt issuances. There can be no guarantee that such liquidity will be available when required on terms acceptable to Questerre.
Antler, Saskatchewan
Consistent with prior years, activities at Antler focused on optimizing existing production and expanding the pilot secondary recovery scheme to increase recovery of the oil in place.
With the exception of routine operating expenditures, including workovers, no material capital was invested during the year (2020: $0.3 million). Daily production averaged 278 bbl/d (2020: 319 bbl/d). Total proved and probable reserves as at December 31, 2021 were estimated at 1.4 MMBbls (2020: 1.4 MMBbls) with a before tax NPV-10% of $36.1 million (2020: $22.3 million). The Company currently holds 11,952 net acres in the area.
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In 2022, the Company expects to continue its work to enhance existing production through workovers and monitoring of the pilot secondary recovery scheme.
St. Lawrence Lowlands, Quebec
The Company’s main priorities were to advance its Clean Tech Energy project and secure social acceptability for this net zero-emissions project. Notwithstanding the significant progress made, in February 2022, the Government of Quebec introduced legislation to revoke licenses and ban the exploration and development of oil and gas in the province.
As a result of the extensive consultations with stakeholders over the last five years, the Company continued to build support for its project.
The local municipality adjacent to its discovery well expressed interest in hosting a pilot project that would include a profit-sharing initiative. In early 2022, the Company entered into a joint economic development agreement with the Wolinak of Abenaki First Nation. Pursuant to the agreement, the Abenakis of Wolinak would be granted a net profit interest from development on their traditional territories, the opportunity to acquire a working interest in the Company’s licenses and directly participate in future development.
This support was further validated by polling conducted for the Quebec Energy Association in October 2021. It noted that over 66% of decided Quebecers support local natural gas development and 20% have no opinion. For production from a pilot project with no emissions, this support increases to just over 77% of decided Quebecers with 12% having no opinion. Nearly 85% of decided Quebecers agree that the Government should give First Nations the opportunity to participate in pilot projects that demonstrate zero-emissions natural gas production with 15% holding no opinion. Subsequent polls post the Russian invasion of Ukraine show increasing numbers of Quebecers supporting local oil and gas development.
During the year, the Company continued to expand the design of its Clean Tech Energy project to include zero-emissions hydrogen and carbon capture. It executed a letter of intent with ZEG Power, a private Norwegian company to evaluate their proprietary technology to efficiently produce hydrogen from Clean Gas and capture the associated emissions. It also applied to the Ministry of Energy and Natural Resources in Quebec for a permit to test a reservoir for carbon storage potential. The Company holds the exclusive right to explore for storage reservoirs over its licenses in the province.
In February 2022, the Government of Quebec tabled Bill 21 - An Act mainly to end petroleum exploration and production and the public financing of those activities (“Bill 21”). Bill 21 proposes to revoke all exploration licenses in Quebec. It proposes three main categories of compensation, including personal compensation for qualifying exploration and development expenses incurred between October 2015 to October 2021, and general compensation for acquisition costs, regulatory compliance costs and up to 75% of costs for well abandonments. The third category is contingent and includes expenses in the above categories for other time periods.
In its submission to the parliamentary committee studying Bill 21, the Company outlined its objections to among other items, the nominal compensation offered, the ineffectiveness of Bill 21 in reducing Quebec’s emissions and the economic and fiscal implications of the ban. The Company intends to pursue available remedies to protect its legal rights.
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As a result of the proposed legislation, the Company has impaired the full carrying amount of its exploration and evaluation assets in Quebec of $104 million as of December 31, 2021.
The Company estimates qualifying exploration and development expenditures of $164.6 million were incurred on its exploration licenses from 2006 to 2021. Of this amount $156.7 million was incurred on permits where the Company is currently the operator, $4 million was incurred on permits where it is non-operator and $3.9 million incurred on permits that have been surrendered. In addition, the Company incurred mineral and surface rentals totalling $3.9 million and has placed deposits with the Government for abandonment and reclamation liabilities of $7.2 million. Total expenditures in Quebec for oil and gas activities would be much higher due to non-qualifying expenses such as securing social license and administration.
The Company will seek just compensation for the value of its licenses in the event the legislation is enacted and will object to the revocation of its licenses until just compensation is received.
For more information, please refer to the AIF available on the Company’s website at www.questerre.com and on SEDAR at www.sedar.com.
Oil Shale Mining
With a focus on capital preservation during the year, limited third party engineering was conducted on its oil shale project in the Kingdom of Jordan. An internal assessment of the project design is ongoing, focusing on reducing the initial capital investment to improve break-even pricing. The Company is also evaluating a small-scale commercial project and a more modular design to further improve economics.
Negotiations with the Government of Jordan for the fiscal and other terms of the concession agreement for the project remain ongoing. Questerre continues to hold the exclusive exploration rights to the project during the term of these negotiations.
The Company continued to work with its investee, Red Leaf Resources Inc. (“Red Leaf”), to advance their proprietary technology.
Red Leaf is a private Utah based company whose principal assets include its proprietary EcoShale technology to produce oil from shale, oil shale leases in the state of Utah and approximately US$20 million in unrestricted cash as of December 31, 2021. The Company currently owns approximately 41% of the common share capital of Red Leaf.
Red Leaf has been focused on redesigning their process to target improved economics and a lower emissions footprint. Their new process incorporates the production of industrial grade carbon dioxide which can be either sequestered or used for enhanced oil recovery in adjacent oilfields. Red Leaf is also evaluating the potential to co-produce rare earth elements along with zero-emissions oil from their project in Utah.
Through the exercise of a security interest, Red Leaf recently acquired a 7,000-acre parcel in the Uinta Basin, Utah. They are pursuing plans to develop this acreage as an industrial park with rail access. The proposed plans include an oil loading facility for existing production in the surrounding area.
Corporate
During the year the Company’s facilities with a Canadian chartered bank were reduced from $20 million to $16 million. The renewed facilities consist of a revolving operating demand loan. Any borrowing under the facilities,
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except letters of credit, are subject to the Bank’s prime rate and applicable basis point margin. The effective interest rate on the facilities for the year was 3.45% (2020: 3.45%). As at December 31, 2021, $3.4 million (2020: $15.4 million) was drawn on the facilities and the Company held unrestricted cash and term deposits of $8.5 million (2020: $10.4 million).
Drilling Activities
During 2021, three (0.75) net wells were spud at Kakwa Central compared to one (0.25) net well last year.
Production
2021 | 2020 | |||||||||||
Oil and | Natural | Oil and | Natural | |||||||||
Liquids | Gas | Total | Liquids | Gas | Total | |||||||
| (bbls/d) |
| (Mcf/d) |
| (boe/d) |
| (bbls/d) |
| (Mcf/d) |
| (boe/d) | |
Alberta | 589 | 3,538 | 1,179 | 926 | 4,126 | 1,614 | ||||||
Saskatchewan and Manitoba | 301 | – | 301 | 352 | – | 352 | ||||||
890 | 3,538 | 1,480 | 1,278 | 4,126 | 1,966 | |||||||
Note: Oil and liquids includes light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.
With no new wells brought on production during the year, volumes declined by 25% over the prior year.
This reflected the focus on restricting capital investment to preserve financial liquidity during the pandemic. In addition to its working interest volumes at Kakwa Central, the Company also holds royalty interest production at Kakwa North. During the year this averaged approximately 128 boe/d (2020: 201 boe/d) or 11% of volumes (2020: 12%). Consistent with prior years, Kakwa continued to account for over 80% of corporate volumes.
As well as natural gas liquids from Kakwa, primarily condensate, Questerre also produces light oil from Saskatchewan and Manitoba. Combined production from this area was lower than last year, reflecting natural declines and a deferral of workovers until oil prices improved. These volumes contributed to an oil and liquids weighting that averaged 60% for the year (2020: 65%).
The Company anticipates production volumes will increase in the second quarter of this year, subject to the completion and tie-in of wells underway at Kakwa Central. Participation in future drilling at Kakwa will depend on among other things, available cash flow from operations and incremental financial liquidity through potential asset dispositions, equity or debt issuances.
2021 Financial Results
Petroleum and Natural Gas Revenue
2021 | 2020 | |||||||||||||||||
Oil and | Natural | Oil and | Natural | |||||||||||||||
($ thousands) |
| Liquids |
| Gas |
| Total |
| Liquids |
| Gas |
| Total | ||||||
Alberta | $ | 16,498 | $ | 5,056 | $ | 21,554 | $ | 12,299 | $ | 3,681 | $ | 15,980 | ||||||
Saskatchewan and Manitoba | 8,850 | – | 8,850 | 5,944 | – | 5,944 | ||||||||||||
$ | 25,348 | $ | 5,056 | $ | 30,404 | $ | 18,243 | $ | 3,681 | $ | 21,924 | |||||||
Note: Oil and liquids includes light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.
2021 Annual Report | 13 |
The material improvement in both oil and natural gas prices was responsible for the higher petroleum and natural gas sales. The nearly two thirds increase in revenue due to higher prices which was offset by the 25% decline in production volumes, resulting in an almost 40% increase over the prior year.
Pricing
| 2021 |
| 2020 | |
Benchmark prices: | ||||
Natural Gas - AECO, daily spot ($/Mcf) | 3.37 | 2.11 | ||
Crude Oil - Canadian Light Sweet Blend ($/bbl) | 82.34 | 46.60 | ||
Realized prices: | ||||
Natural Gas ($/Mcf) | 3.84 | 2.51 | ||
Crude Oil and Natural Gas Liquids ($/bbl) | 84.81 | 41.80 |
Note: Oil and liquids includes light & medium crude oil and natural gas liquids. Natural gas includes conventional and shale gas.
Crude oil prices strengthened over the prior year with the benchmark West Texas Intermediate averaging US$67/bbl compared to US$39/bbl last year.
The supply demand balance improved during the year as reopening economies gradually restored demand to near pre-pandemic levels. This was bolstered by OPEC+ compliance with unwinding production cuts and fiscal discipline by North American producers. In North America, weather-related events also played a role including winter storm Uri and Hurricane Ida that shut in production and refining capacity and reduced inventories. In Canada, differentials improved due to reduced supply from facility turnarounds and increased egress including the completion of Enbridge’s Line 3 replacement. Over the year, the differential between WTI and condensate prices was a nominal premium of US$0.29/bbl compared to a discount of US$2.24/bbl in 2020.
Realized prices for Questerre’s light oil and natural gas liquids track the Canadian light oil MSW benchmark. Condensate often receives a premium and other liquids receive a discount.
Natural gas prices also improved materially over the year with the benchmark Henry Hub averaging US$3.91/MMBtu compared to US$2.06/MMBtu in 2020.
In the United States, a nominal 3% increase in production over the year to just under 100 Bcf/d was more than offset by the growth in exports via pipeline to Mexico and LNG. Combined these averaged over 17% of total domestic demand for the year, almost double compared to the prior year. This accelerated in the second half of the year in part driven by rising LNG imports in Asia, reduced LNG supplies globally and increased demand in Europe due to unreliable renewable power and lower imports from Russia. Global LNG prices reaching a high of US$60/MMBtu in December. In Canada, the differential between the benchmark AECO and NYMEX price was volatile because of maintenance outages on the main transmission line but improved in the fourth quarter with colder weather in Western Canada.
The higher heat content natural gas from Kakwa resulted in realized prices of $3.84/Mcf (2020: $2.51/Mcf) compared to the AECO benchmark price of $3.37/Mcf (2020: $2.11/Mcf).
14 | Questerre Energy Corporation |
Royalties
($ thousands) |
| 2021 |
| 2020 | ||
Alberta | $ | 1,232 | $ | 850 | ||
Saskatchewan and Manitoba | 637 | 465 | ||||
$ | 1,869 | $ | 1,315 | |||
% of Revenue: | ||||||
Alberta | 6% | 5% | ||||
Saskatchewan and Manitoba | 7% | 8% | ||||
Total Company | 6% | 6% | ||||
Excluding credits received from the Crown in Alberta, gross royalties increased over the prior year with the increase in petroleum and natural gas sales and the expiry of Crown incentive programs.
Royalties in Alberta include a credit for $0.8 million (2020: $0.2 million) from the Government for processing its share of production through the Company’s facilities. The increase in the credit over the prior year is due to the higher effective royalty rate for production from Kakwa. The expiration of incentive programs also resulted in Crown royalties of 40% on condensate production from older vintage wells. By comparison, newer wells benefit from incentives and record royalty rates of 5% on condensate.
Royalties on production in Saskatchewan and Manitoba declined slightly as percentage of revenue from 8% in 2020 to 7% in 2021.
Operating Costs
($ thousands) |
| 2021 |
| 2020 | ||
Alberta | $ | 8,479 | $ | 8,687 | ||
Saskatchewan and Manitoba | 2,795 | 2,670 | ||||
Quebec | 506 | 588 | ||||
$ | 11,780 | $ | 11,945 | |||
$/boe: | ||||||
Alberta | 19.71 | 14.71 | ||||
Saskatchewan and Manitoba | 25.44 | 20.68 | ||||
Total Company | $ | 21.81 | $ | 16.60 | ||
Although operating costs remained largely flat over the prior year at $11.8 million, the higher proportion of fixed costs and lower production volumes translated into an increase on a boe basis from $17/boe to $22/boe.
At Kakwa, fixed costs including firm transportation and processing commitments represent over 80% of total operating costs. In 2021, these increased by approximately 10% due to higher fuel and power and workover expense. At Antler, fixed costs including workovers represent nearly 90% of total operating costs for the area. These also increased by 10% due to higher workover expense. Operating costs in Quebec remained stable, representing maintenance costs for the Company’s assets in the province.
2021 Annual Report | 15 |
General and Administrative Expenses
($ thousands) |
| 2021 |
| 2020 | ||
General and administrative expenses, gross | $ | 3,454 | $ | 3,542 | ||
Capitalized expenses and overhead recoveries | (1,045) | (1,008) | ||||
General and administrative expenses, net | $ | 2,409 | $ | 2,534 | ||
Gross and net general and administrative expenses (“G&A”) remained stable. In both years, they include cost-cutting measures implemented in response to the pandemic in early 2020. These included implementing a four day work week, a 20% to 50% reduction in salaries and a 20% reduction in directors fees. In 2020, these included $0.3 million in credits from the Government as part of its pandemic assistance program. Capitalized expenses are overhead costs associated with the Company’s projects in Quebec and Jordan.
Depletion, Depreciation, Impairment, Accretion and Lease Expiries
For the year ended December 31, 2021, the Company recorded depletion, deprecation, and accretion expense of $6.1 million (2020: $9.4 million) with depletion accounting for over 90% of this amount. The lower amount reflects the lower production volumes in the current year. On a unit of production basis this declined marginally to $10.71/boe from $12.83/boe.
The Company assessed the carrying value of its plant, property and equipment assets (“PP&E”) as at December 31, 2021 for indicators of impairment or indicators to reverse previously recorded impairment. Based on this review, the Company’s Montney and Antler cash generating units (“CGUs”) were tested in accordance with the Company’s accounting policy. The recoverable amount of the CGUs was estimated based on the fair value less costs of disposal (“FVLCD”) using a discounted cash flow model. Due to the higher future commodity prices, the Company recorded a reversal of $91.7 million (2020: $96.3 million) in impairment expense. Of this amount, $76 million was attributed to the Kakwa, Alberta CGU and $15.7 million was attributed to the Antler, Saskatchewan CGU. No impairment reversals were recorded for the Company’s other CGUs.
In the prior year, the Company recorded an impairment expense of $113 million as a result of lower future commodity prices. The variance between the carrying value of its PP&E and the FVLCD using a discounted cash flow model resulted in an impairment of a $96.3 million representing a $78.4 million impairment in the Kakwa CGU and a $17.9 million impairment in the Antler CGU.
As a result of the introduction of Bill 21 in Quebec, the Company impaired the full carrying value of its exploration and evaluation (“E&E”) assets of $104 million. In 2020, The Company incurred an impairment of $14.4 million related to the carrying value of its E&E assets in the Kakwa area where the Company had no plans for operated development. Impairment expense in 2020 also includes $2.3 million relating to goodwill on the basis that the FVLCD of its PP&E assets was below carrying value at March 31, 2020.
Share Based Compensation
Pursuant to the Company’s share option plan, an optionee may request that the Company purchase all or any part of the then vested options of the optionee, for an amount equal to the market price of the Common Shares less the exercise price of the option shares. Notwithstanding the foregoing, the Company may, at its sole
16 | Questerre Energy Corporation |
discretion, decline to accept and, accordingly, has no obligations with respect to the exercise of this put right at any time. Once the options are cash settled, the options are cancelled.
The Company recorded share-based compensation expense of $0.5 million (2020: $0.5 million) net of $0.7 million (2020: $0.9 million) in expense that was capitalized during the year. The Company also made a payment of $0.1 million for the cash settlement of 2.34 million expiring options during the year (2020: nil).
Other Income and Expenses
The Company incurred interest expense of $0.4 million (2020: $0.6 million) related to its credit facilities with a Canadian chartered bank. The amount drawn on the facilities at year-end was $3.4 million (2020: $15.4 million) and the effective interest rate was 3.45% (2020: 3.45%). The Company also earned interest income of $0.2 million on its cash and term deposits (2020: $0.3 million).
Included in other income is $0.3 million (2020: Nil) representing grants received from the provincial governments of Alberta and Saskatchewan for rehabilitation of existing leases, including abandonment and reclamation work. To date $0.2 million (2020: Nil) in expenditures have been incurred against these grants.
Other Comprehensive Loss
In 2021, the Company recorded other comprehensive loss of $0.1 million (2020: $0.3 million) related to the change in foreign exchange rates.
A loss of $0.02 million in the current year (2020: $0.02 million) was attributable to the change in the US dollar denominated investment in Red Leaf. The Company also incurred a nominal loss of $0.04 million (2020: $0.2 million) due to the depreciation in the Jordanian dinar impacting its dinar-denominated assets in Jordan.
Total Comprehensive Loss
For the year ended December 31, 2021, the Company recorded a total comprehensive loss of $4.4 million compared to a loss of $117.9 million in the prior year. The loss in the current year is attributable largely to the impairment expense related to its entire Quebec E&E assets of $104 million offset by the reversal of previously recorded impairment of $92 million related to its PP&E assets. To a lesser extent, the loss was also offset by higher petroleum and natural gas revenue.
Cash Flow from Operating Activities
The Company recorded cash flow from operating activities of $14.1 million (2020: $6.4 million). The variance over last year is attributable to higher adjusted funds flow from operations due to the materially higher petroleum and natural gas revenue. This was offset partly by the decrease in non-cash working capital compared to the increase in the prior year.
Cash Flow used in Investing Activities
Cash flow used in investing activities decreased to $3.8 million over the prior year of $10.2 million due to the lower capital investment in the current year and the increase in non-cash working capital compared to a material decrease in the prior year.
2021 Annual Report | 17 |
Cash Flow provided by Financing Activities
In 2021, the Company reported net cash used in financing activities of $11.9 million, largely representing a net reduction in borrowing under its credit facility. The amounts in the current year also include $0.2 million related to the exercise of stock options. In the prior year, net cash used of $1.0 million represented a net reduction in its credit facilities of $1.0 million.
Capital Expenditures
($ thousands) |
| 2021 |
| 2020 | ||
Alberta | $ | 3,220 | $ | 3,935 | ||
Saskatchewan, Manitoba and Jordan | 120 | 644 | ||||
Quebec | 1,325 | 780 | ||||
4,665 | 5,359 | |||||
Quebec Acquisition | – | 263 | ||||
Total | $ | 4,665 | $ | 5,622 | ||
Notes: | ||||||
1. Capital expenditures exclude certain non-cash items such as, stock based compensation and asset retirement obligations. | ||||||
2. See note 9 to the 2020 Financial Statements for additional information on the Quebec Acquisition completed in 2019. | ||||||
For the year ended December 31, 2021, the Company incurred capital expenditures of $4.7 million as follows:
| ● | In Alberta, $3.3 million for drilling three (0.75 net) wells on the Kakwa Central joint venture; |
| ● | In Quebec, $1.3 million for well monitoring and capitalized overhead related to advancing social acceptability and engineering for its Clean Tech Energy project; and |
| ● | In Jordan, $0.1 million was spent on advancing the engineering for its oil shale project. |
For the year ended December 31, 2020, the Company incurred capital expenditures of $5.6 million as follows:
| ● | In Alberta, $3.9 million for drilling, completing and equipping one (0.25 net) well on the Kakwa Central joint venture and expanding field infrastructure; |
| ● | In Quebec, $1.1 million for well monitoring and capitalized overhead related to advancing social acceptability and engineering for its Clean Tech Energy project, including closing adjustments relating to the acquisition in Quebec; |
| ● | In Saskatchewan, $0.3 million for infrastructure related to its secondary recovery scheme; and |
| ● | In Jordan, $0.3 million was spent on advancing the engineering for its oil shale project. |
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.
Although commodity prices have recovered from the collapse in 2020, they remain volatile as a result of recent geopolitical events. The Company continues to manage its financial liquidity through ensuring capital expenditures can be financed through a combination of cash flow from operations and available debt facilities.
At December 31, 2021, $3.4 million (December 31, 2020: $15.4 million) was drawn on the credit facilities and the Company is compliant with all its covenants under the credit facilities. Under the terms of the credit facilities, the Company has provided a covenant that it will maintain an Adjusted Working Capital Ratio greater
18 | Questerre Energy Corporation |
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, 2021 was 3.05 and the covenant was met. See Note 13 of the Financial Statements.
While the credit facilities were renewed during the year at $16 million, the facilities could be reduced at their next review scheduled during the second quarter of 2022. The credit facilities are a demand facility and can be reduced, amended or eliminated by the lender for reasons beyond the Company’s control. Should the credit facilities be reduced or eliminated, the Company would need to seek alternative credit facilities or consider the issuance of equity to enhance its liquidity. In the current market, the Company may be unable to secure additional financing on acceptable terms, if at all.
The Company believes that it has access to sufficient financial liquidity to meet its foreseeable obligations in the normal course of operations over the next 12 months.
The Company is committed to the 2022 future development costs associated with proved reserves in its independent reserves assessment as of December 31, 2021. It anticipates that, as a result, reserves associated with wells drilled in 2022 will be transferred from the proved undeveloped to the proved producing category.
For a detailed discussion of the risks and uncertainties associated with the Company’s business and operations, see the Risk Management section of the MD&A and the AIF.
Share Capital
The Company is authorized to issue an unlimited number of Common Shares. The Company is also authorized to issue an unlimited number of Class “B” Common voting shares and an unlimited number of preferred shares, issuable in one or more series. At December 31, 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 and the current and preceding fiscal year end.
March 24, | December 31, | December 31, | ||||
(thousands) |
| 2022 |
| 2021 |
| 2020 |
Common Shares | 428,516 | 428,516 | 427,516 | |||
Stock Options | 41,747 | 30,307 | 25,351 | |||
Weighted average Common Shares | ||||||
Basic | 428,034 | 427,613 | ||||
Diluted | 428,034 | 427,613 |
2021 Annual Report | 19 |
A summary of the Company’s stock option activity during the years ended December 31, 2021 and 2020 follows:
December 31, 2021 | December 31, 2020 | |||||||||
Number of | Weighted | Number of | Weighted | |||||||
Options | Average | Options | Average | |||||||
| (thousands) |
| Exercise Price |
| (thousands) |
| Exercise Price | |||
Outstanding, beginning of period | 25,351 | $ | 0.38 | 27,087 | $ | 0.40 | ||||
Granted | 8,350 | 0.18 | 6,475 | 0.20 | ||||||
Forfeited | (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 | 20,866 | $ | 0.42 | 16,191 | $ | 0.42 | ||||
Commitments
A summary of the Company’s net commitments at December 31, 2021 follows:
($ thousands) |
| 2022 |
| 2023 |
| 2024 |
| 2025 |
| Thereafter |
| Total | ||||||
Transportation and Processing | $ | 2,977 | $ | 3,162 | $ | 2,884 | $ | 2,015 | $ | 1,240 | $ | 12,278 | ||||||
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 “Industry Conditions” sections of the AIF and Note 6 to the audited consolidated financial statements for the year ended December 31, 2021.
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, including recent decisions by Saudi Arabia and Russia, on production growth and spare capacity, market volatility and disruptions, weakening global relationships, the war in Ukraine, conflict between the U.S. and Iran, isolationist and punitive trade policies, U.S. shale production, sovereign debt levels and political upheavals in various countries including growing anti-fossil fuel sentiment, have caused significant volatility in
20 | Questerre Energy Corporation |
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 previously reduced the Company’s cash flow leading to a reduction in funds available for capital expenditures. As a result, the Company may not be able to replace its production with additional reserves and both the Company’s production and reserves could be reduced on a year over year basis. Any decrease in value of the Company’s reserves may reduce the borrowing base under its credit facilities, which, depending on the level of the Company’s indebtedness, could result in the Company having to repay all or a portion of its indebtedness. Given the current market conditions and the lack of confidence in the Canadian oil and natural gas industry, the Company may have difficulty raising additional funds in the future to raise funds on unfavourable and highly dilutive terms.
Another significant risk for Questerre as a junior exploration company is access to capital. The Company attempts to secure both equity and debt financing on terms it believes are attractive in current markets. Management also endeavors to seek participants to farm-in on the development of its projects on favorable terms. However, there can be no assurance that the Company will be able to secure sufficient capital if required or that such capital will be available on terms satisfactory to the Company.
As future capital expenditures will be financed out of adjusted funds flow from operations, borrowings and possible future equity sales, the Company’s ability to do so is dependent on, among other factors, the overall state of capital markets and investor appetite for investments in the energy industry, and the Company’s securities. To the extent that external sources of capital become limited or unavailable, or available but on onerous terms, the Company’s ability to make capital investments and maintain existing assets may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected. Based on current funds available and expected adjusted funds flow from operations, the Company believes it has sufficient funds available to fund its projected capital expenditures. However, if adjusted funds flow from operations is lower than expected, or capital costs for these projects exceed current estimates, or if the Company incurs major unanticipated expense related to development or maintenance of its existing properties, it may be required to seek additional capital to maintain its capital expenditures at planned levels. Failure to obtain any financing necessary for the Company’s capital expenditure plans may result in a delay in development or production on the Company’s properties.
Questerre faces several financial risks over which it has no control, such as commodity prices, exchange rates, interest rates, access to credit and capital markets, as well as changes to government regulations and tax and royalty policies.
2021 Annual Report | 21 |
The Company uses the following guidelines to address financial exposure:
| ● | Internally generated cash flow provides the initial source of funding on which the Company’s annual capital expenditure program is based. |
| ● | Equity, including flow-through shares, if available on acceptable terms, may be raised to fund acquisitions and capital expenditures. |
| ● | Debt may be utilized to expand capital programs, including acquisitions, when it is deemed appropriate and where debt retirement can be controlled. |
| ● | Farm-outs of projects may be arranged if management considers that a project requires too much capital or where the project affects the Company’s risk profile. |
Credit risk represents the potential financial loss to the Company if a customer or counterparty to a financial instrument fails to meet or discharge their obligation to the Company. Credit risk arises from the Company’s receivables from joint venture partners and oil and gas marketers. In the event such entities fail to meet their contractual obligations to the Company, such failures may have a material adverse effect on the Company’s business, financial condition, results of operations and prospects. Credit risk also arises from the Company’s cash and cash equivalents. In the past, the Company manages credit risk exposure by investing in Canadian banks and credit unions. Management does not expect any counterparty to fail to meet its obligations.
Poor credit conditions in the industry may impact a joint venture partner’s willingness to participate in the Company’s ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner if possible.
Substantially all of the accounts receivable are with oil and natural gas marketers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by entering into transactions with long-standing, reputable counterparties and partners.
Accounts receivable related to the sale of the Company’s petroleum and natural gas production is paid in the following month from major oil and natural gas marketing and infrastructure companies and the Company has not experienced any credit loss relating to these sales to date. Pursuant to IFRS 9, the Company made a provision of $0.04 million at December 31, 2021 for its expected credit losses related to its accounts receivable.
Receivables from joint venture partners are typically collected within one to three months after the joint venture bill is issued. The Company mitigates this risk by obtaining pre-approval of significant capital expenditures.
The Company has issued and may continue in the future to issue flow-through shares to investors. The Company has historically used its best efforts to ensure that qualifying expenditures of Canadian Exploration Expense ("CEE") are incurred in order to meet its flow-through obligations. In 2017, the Federal Government amended the law regarding what expenses constitute CEE. Generally, oil and gas drilling expenses are now Canadian Development Expense rather than CEE. In the event that the Company has CEE expenditures reclassified under audit by the Canada Revenue Agency or fails to incur expenditures required under a flow-
22 | Questerre Energy Corporation |
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, 2021, the Company had no outstanding commodity risk management contract in place.
Environmental Regulation and Risk
The oil and natural gas industry is currently subject to environmental regulations pursuant to provincial and federal legislation. Environmental legislation provides for restrictions and prohibitions on releases of emissions and regulation on the storage and transportation of various substances produced or utilized in association with certain oil and natural gas industry operations, which can affect the location and operation of wells and facilities, and the extent to which exploration and development is permitted. In addition, legislation requires that well and facility sites are abandoned and reclaimed to the satisfaction of provincial authorities. As well, applicable environmental laws may impose remediation obligations with respect to property designated as a contaminated site upon certain responsible persons, which include persons responsible for the substance causing the contamination, persons who caused the release of the substance and any past or present owner, tenant or other person in possession of the site. Compliance with such legislation can require significant expenditures, and a breach of such legislation may result in the suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, the imposition of fines and penalties or the issuance of clean-up orders. The Company mitigates the potential financial exposure of environmental risks by complying with the existing regulations and maintaining adequate insurance. For more information, please refer to the “Risk Factors” and “Industry Conditions” sections of the AIF.
Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. The federal and certain provincial governments have implemented legislation aimed at incentivizing the use of 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, increasing the Company’s operating expenses, each of which may have a material adverse effect on the Company’s profitability and financial condition. Further, the imposition of carbon taxes puts the Company at a disadvantage with the Company’s counterparts who operate in jurisdictions where there are less costly carbon regulations.
2021 Annual Report | 23 |
Interest Rate Risk
Interest rate risk is the risk that changes in the applicable interest rates for its credit facilities will impact the Company’s interest expense. At December 31, 2021, the Company had credit facilities outstanding of $3.4 million (December 31, 2020: $15.4 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
All of Questerre’s petroleum and natural gas reserves are evaluated and reported on by independent petroleum engineering consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities and the COGE Handbook. For further information, please refer to “Statement of Reserves Data and Other Oil and Gas Information” in the AIF.
The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production, commodity prices and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and changes in costs and commodity prices. These estimates are evaluated by independent reserve engineers at least annually.
Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the estimated proved plus probable reserves and there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.
Reserve estimates impact a number of the areas, in particular, the valuation of property, plant and equipment and the calculation of depletion.
Cash Generating Units
A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations. Factors considered in the classification include geography and the way management monitors and makes decisions about its operations.
24 | Questerre Energy Corporation |
Impairment of Property, Plant and Equipment, Exploration and Evaluation and Goodwill
The Company assesses its oil and natural gas properties, including exploration and evaluation assets, for possible impairment or reversal of previously recognized impairments if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable or indications that previously recognized losses should be reversed. Determining if there are facts and circumstances present that indicate that carrying values of the assets may not be recoverable requires management’s judgment and analysis of the facts and circumstances.
The recoverable amounts of CGUs have been determined based on the higher of value in use (“VIU”) and the FVLCD. The key assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes, the discount rate, future operating and development costs and recent land transactions. Changes to these assumptions will affect the recoverable amounts of the CGUs and may require a material adjustment to their related carrying value.
Goodwill is the excess of the purchase price paid over the fair value of the net assets acquired. Since goodwill results from purchase accounting, it is imprecise and requires judgment in the determination of the fair value of assets and liabilities. Goodwill is assessed for impairment on an operating segment level based on the recoverable amount for each CGU of the Company. Therefore, impairment of goodwill uses the same key judgments and assumptions noted above for impairment of assets.
Asset Retirement Obligation
Determination of the Company’s asset retirement obligation is based on Government regulations, operator estimates, internal estimates using current costs and technology in accordance with existing legislation and industry practice and must also estimate timing, a risk-free rate and inflation rate in the calculation. These estimates are subject to change over time and, as such, may impact the charge against profit or loss. The amount recognized is the present value of estimated future expenditures required to settle the obligation using a risk-free rate. The associated abandonment and retirement costs are capitalized as part of the carrying amount of the related asset. The capitalized amount is depleted on a unit of production basis in accordance with the Company’s depletion policy. Changes to assumptions related to future expected costs, risk-free rates and timing may have a material impact on the amounts presented.
Share Based Compensation
The Company has a stock option plan enabling employees, officers and directors to receive Common Shares or cash at exercise prices equal to the market price or above on the date the option is granted. Under the equity settled method, compensation costs attributable to stock options granted to employees, officers or directors are measured at fair value using the Black-Scholes option pricing model. The assumptions used in the calculation are: the volatility of the stock price, risk-free rates of return and the expected lives of the options. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Changes to assumptions may have a material impact on the amounts presented.
Income Tax Accounting
Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing
2021 Annual Report | 25 |
tax laws in each jurisdiction differ significantly from the Company’s estimate, the ability of the Company to realize the deferred tax assets could be impacted.
Since December 31, 2016, the recoverability of deferred tax assets is assessed using proved reserves including an estimate of G&A associated with the assets.
The determination of the Company’s income and other tax assets or liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax asset or liability may differ significantly from that estimated and recorded by management.
Investment in Red Leaf
Questerre has investments in certain private companies, including Red Leaf, which it classifies as an equity investment and assesses for indicators of impairment at each period end. The primary risk related to the investment in Red Leaf is the decline in the net current assets of the company without a sufficient advancement in the engineering for the EcoShale process.
Design and Evaluation of Internal Controls over Financial Reporting and Disclosure Controls and Procedures
Questerre is required to comply with National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings” (“NI 52-109”) and is required to make specific disclosures with respect to NI 52-109 as follows:
| ● | The Company has designed and evaluated the effectiveness of Disclosure Controls and Procedures (“DC&P”). The President and Chief Executive Officer and the Chief Financial Officer have concluded that DC&P are designed appropriately and are operating effectively as at December 31, 2021. |
| ● | 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, 2021 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, 2021 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.
Fourth Quarter 2021 Results
In the last quarter of 2021, petroleum and natural gas revenue increased by approximately 46% to $8.9 million from $6.1 million in the same period last year. Consistent with the fiscal year results, the 24% decrease in volumes was more than offset by the 70% increase in commodity prices.
26 | Questerre Energy Corporation |
Natural declines were responsible for daily production in the fourth quarter averaging 1,398 boe/d compared to 1,851 boe/d last year. Benchmark pricing for both oil and gas increased over the preceding quarters of 2021 and more materially over the same period last year. The improved pricing environment also saw the differential between WTI and Canadian condensate prices increase to a premium from a discount last year.
Operating costs for the quarter increased by 15% to $3.7 million from $3.2 million last year. While expenses remained stable in Alberta and Quebec, the increase was attributable to higher workover costs in Antler with the higher oil prices. The lower production volumes and high proportion of fixed costs contributed to costs on a boe basis increasing by over one third to $28.50/boe compared to $18.77/boe last year.
The Company reported a total comprehensive loss of $10.2 million for the quarter. By comparison in 2020, the Company recorded total comprehensive loss of $0.6 million. The loss was attributable to the impairment of the full carrying value of its E&E assets in Quebec of $104 million offset by the reversal of previously incurred impairment of its PP&E assets of $92 million in the quarter due to higher future commodity prices.
In the fourth quarter, net cash from operating activities increased to $3.8 million from $2.6 million last year. This reflects the materially higher adjusted funds flow from operations over the prior year.
Net cash used in investing activities decreased over the prior year quarter as higher capital spending was offset by an increase in non-cash working capital. The Company also reduced its borrowings under its credit facilities by $4 million compared to $0.8 million last year.
Quarterly Financial Information
December 31, | September 30, | June 30, | March 31, | |||||
($ thousands, except as noted) |
| 2021 |
| 2021 |
| 2021 |
| 2021 |
Production (boe/d) | 1,398 | 1,363 | 1,479 | 1,679 | ||||
Average Realized Price ($/boe) | 69.11 | 58.83 | 52.72 | 46.62 | ||||
Petroleum and Natural Gas Revenue | 8,887 | 7,376 | 7,095 | 7,046 | ||||
Adjusted Funds Flow from Operations | 3,790 | 3,578 | 4,224 | 2,885 | ||||
Net Profit (Loss) | (10,107) | 2,006 | 2,892 | 908 | ||||
Basic and Diluted ($/share) | (0.02) | – | 0.01 | – | ||||
Capital Expenditures, net of acquisitions and dispositions | 3,177 | 541 | 450 | 497 | ||||
Working Capital Surplus (Deficit) | 1,834 | 1,698 | (1,243) | (5,449) | ||||
Total Assets | 184,264 | 192,709 | 194,053 | 194,417 | ||||
Shareholders' Equity | 148,961 | 158,922 | 156,316 | 153,108 | ||||
Weighted Average Common Shares Outstanding | ||||||||
Basic (thousands) | 428,516 | 428,516 | 427,571 | 427,516 | ||||
Diluted (thousands) | 428,516 | 428,516 | 427,743 | 427,879 |
2021 Annual Report | 27 |
December 31, | September 30, | June 30, | March 31, | |||||
($ thousands, except as noted) |
| 2020 |
| 2020 |
| 2020 |
| 2020 |
Production (boe/d) | 1,851 | 1,875 | 2,058 | 2,078 | ||||
Average Realized Price ($/boe) | 35.85 | 31.26 | 18.20 | 37.12 | ||||
Petroleum and Natural Gas Revenue | 6,105 | 5,391 | 3,410 | 7,018 | ||||
Adjusted Funds Flow from Operations | 1,857 | 1,623 | 206 | 2,460 | ||||
Net Profit (Loss) | (75) | (970) | (2,702) | (113,876) | ||||
Basic and Diluted ($/share) | – | (0.01) | (0.27) | |||||
Capital Expenditures, net of acquisitions and dispositions | 1,621 | 348 | 515 | 2,875 | ||||
Working Capital Surplus (Deficit) | (7,705) | (8,095) | (9,272) | (8,603) | ||||
Total Assets | 196,177 | 195,925 | 201,255 | 204,782 | ||||
Shareholders' Equity | 152,120 | 152,508 | 153,509 | 156,263 | ||||
Weighted Average Common Shares Outstanding | ||||||||
Basic (thousands) | 427,516 | 427,516 | 427,516 | 427,907 | ||||
Diluted (thousands) | 427,516 | 427,516 | 427,516 | 427,907 |
The general trends over the last eight quarters are as follows:
| ● | Petroleum and natural gas revenues and adjusted funds flow from operations have fluctuated with production volumes and realized commodity prices. Revenue has begun increasing in the last four quarters due to the recovery in commodity prices. |
| ● | Production volumes reflect the capital investment in drilling and completing wells at Kakwa in preceding quarters. In 2021, with the increase in prices, capital investment increased in the fourth quarter. In 2020, with non-essential capital investment largely suspended, production volumes declined in the subsequent quarters. |
| ● | The level of capital expenditures over the quarters 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 decreased significantly in the first quarter of 2020 with materially lower commodity prices resulting in an impairment expense of $113 million. In the preceding quarter, shareholder’s equity increased due to the $58.5 million gain realized by the Company on the release of litigation related to the Quebec Acquisition. |
Off-Balance Sheet Transactions
The Company did not engage in any off-balance sheet transactions during the year ended December 31, 2021.
Related Party Transactions
The Company paid fees of $0.2 million (2020: $0.1 million) to a law firm where a Director of the Company is currently a partner.
28 | Questerre Energy Corporation |
Management’s Report
The consolidated financial statements of Questerre Energy Corporation were prepared by management in accordance with International Financial Reporting Standards. The financial and operating information presented in this annual report is consistent with that shown in the consolidated financial statements.
Management has designed and maintains a system of internal accounting controls that provide reasonable assurance that all transactions are accurately recorded, that the financial statements reliably report the Company’s operations and that the Company’s assets are safeguarded. Timely release of financial information sometimes necessitates the use of estimates when transactions affecting the current accounting period cannot be finalized until future periods. Such estimates are based on careful judgments made by management.
Ernst and Young LLP , an independent firm of Chartered Professional Accountants, to audit the consolidated financial statements of the Company and provide an independent opinion. They have conducted an independent examination of the Company’s accounting records in order to express their opinion on the consolidated financial statements.
The Board of Directors is responsible for ensuring that management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility through its Audit Committee. The Audit Committee, which consists of non-management directors, has met with Ernst and Young LLP and management in order to determine that management has fulfilled its responsibilities in the preparation of the consolidated financial statements. The Audit Committee has reported its findings to the Board of Directors, who have approved the consolidated financial statements.
|
|
Michael Binnion | Jason D’Silva |
President and Chief Executive Officer | Chief Financial Officer |
Calgary, Alberta, Canada
March 24, 2022
2021 Annual Report | 29 |
Independent Auditor’s Report
To the Shareholders of Questerre Energy Corporation
Our Opinion
We have audited the consolidated financial statements of Questerre Energy Corporation (the Company), which comprise the consolidated balance sheet as at December 31, 2021, and the consolidated statement of net loss and comprehensive loss, consolidated statement of changes in equity and consolidated statement of cash flows for the year then ended, and notes to the consolidated financial statements, including a summary of significant accounting policies.
In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as at December 31, 2021, and its consolidated financial performance and its consolidated cash flows for the year then ended in accordance with International Financial Reporting Standards (IFRS).
Basis for Opinion
We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the consolidated financial statements section of our report. We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Key Audit Matters
Key audit matters are those matters that, in our professional judgment, were of most significance in the audit of the consolidated financial statements of the current period. This matter was addressed in the context of the audit of the consolidated financial statements as a whole, and in forming the auditor’s opinion thereon, and we do not provide a separate opinion on this matter. For the matter below, our description of how our audit addressed the matter is provided in that context.
We have fulfilled the responsibilities described in the Auditor’s responsibilities for the audit of the consolidated financial statements section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the consolidated financial statements. The results of our audit procedures, including the procedures performed to address the matter below, provide the basis for our audit opinion on the accompanying consolidated financial statements.
30 | Questerre Energy Corporation |
Key audit matter | How our audit addressed the key audit matter |
Reversal of impairment of property and equipment As at December 31, 2021, the carrying value of property, plant and equipment (PP&E) for the Western Canadian operating segment was $140.1 million. For the year ended December 31, 2021, an impairment reversal of $91.7 million was recorded with respect to PP&E in the Montney and Antler Cash Generating Units (“CGU”). Refer to Note 2(e) for a description of the Company’s estimates and judgements relating to impairment and to Note 3(g) for a description of the Company’s impairment of non-financial assets accounting policy. Refer to Note 8 for the Company’s PP&E impairment disclosures. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount of a CGU that indicates a previous impairment loss no longer exists or may have decreased. Determining the amount of an impairment reversal requires an estimate of a CGU’s respective recoverable amount. The recoverable amount of the CGUs was determined using a fair value less cost to sell model based on based on expected after-tax future net cash flows from the production of proved and probable reserve volumes using forecast commodity prices and costs, discounted using market-based rates. Proved and probable reserves were determined by the Company’s independent petroleum engineers (management’s experts). Auditing the Company’s estimated recoverable amount was complex due to the subjective nature of the various management inputs and assumptions and the significant effect changes in these could have on the recoverable amount. Additionally, the evaluation of this estimate required specialized skills and knowledge. The primary inputs noted in the fair value less cost to sell model were the discount rate and the proved and probable reserve volumes, forecasted commodity prices, and forecasted production royalties, operating and future development costs. | To test the Company's estimated recoverable amounts of the CGUs within the Western Canada operating segment, we performed the following procedures, among others: ● Evaluated management’s experts’ competence, capability and objectivity as well as obtained an understanding of the work they performed. The appropriateness of their work as audit evidence was evaluated by considering the relevance and reasonableness of the methods and assumptions utilized. ● Involved our internal valuation specialists to assess the methodology applied, and the various inputs utilized in determining the after-tax discount rate by referencing current industry, economic, and comparable company information, as well as company and cash-flow specific risk premiums; ● With the assistance of our internal valuation specialists, we also compared the market capitalization to net assets and observed quantitative and qualitative reconciliations using market data and transactions; ● Compared forecasted benchmark commodity pricing against historical realized prices and to other third-party price forecasts; ● Assessed forecasted production, royalties, operating costs, and future development costs by comparing them to historical results; and ● Evaluated the adequacy of the impairment note disclosure included in Note 8 of the accompanying consolidated financial statements in relation to this matter. |
Other Matter
The consolidated financial statements of the Company for the year ended December 31, 2020, were audited by another auditor who expressed an unmodified opinion on those consolidated financial statements on March 24,
2021 Annual Report | 31 |
2021.
Other Information
Management is responsible for the other information. The other information comprises:
| ● | Management’s discussion and analysis |
| ● | Annual report |
Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon.
In connection with our audit of the consolidated financial statements, our responsibility is to read the other information, and in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated.
We obtained Management’s Discussion & Analysis and the Annual Report prior to the date of this auditor’s report. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact in this auditor’s report. We have nothing to report in this regard.
Responsibilities of management and those charged with governance for the consolidated financial statements
Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so.
Those charged with governance are responsible for overseeing the Company’s financial reporting process.
Auditor’s responsibilities for the audit of the consolidated financial statements
Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements.
As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:
32 | Questerre Energy Corporation |
| ● | Identify and assess the risks of material misstatement of the consolidated financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. |
| ● | Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. |
| ● | Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. |
| ● | Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern. |
| ● | Evaluate the overall presentation, structure and content of the consolidated financial statements, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation. |
We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.
We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.
From the matters communicated with those charged with governance, we determine those matters that were of most significance in the audit of the consolidated financial statements of the current period and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.
The engagement partner on the audit resulting in this independent auditor’s report is Janet Huang.
/s/ Ernst and Young LLP
2021 Annual Report | 33 |
Chartered Professional Accountants
Calgary, Canada
March 24, 2022
34 | Questerre Energy Corporation |
Consolidated Balance Sheets
December 31, | December 31, | |||||||
($ thousands) |
| Note |
| 2021 |
| 2020 | ||
Assets | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | 5 | $ | | $ | | |||
Accounts receivable | 6 | | | |||||
Deposits and prepaid expenses | | | ||||||
| | |||||||
Right-of-use assets | 19 | | | |||||
Investments | 7 | | | |||||
Property, plant and equipment | 8 | | | |||||
Exploration and evaluation assets | 9 | | | |||||
Restricted cash | 13 | | | |||||
$ | | $ | | |||||
Liabilities | ||||||||
Current Liabilities | ||||||||
Lease liabilities | 19 | $ | | $ | | |||
Accounts payable and accrued liabilities | | | ||||||
Credit Facilities | 13 | | | |||||
| | |||||||
Lease liabilities | 19 | | | |||||
Contingent liabilities | | | ||||||
Asset retirement obligation | 12 | | | |||||
| | |||||||
Shareholders' Equity | ||||||||
Share capital | 14 | | | |||||
Contributed surplus | | | ||||||
Accumulated other comprehensive loss | ( | ( | ||||||
Deficit | ( | ( | ||||||
| | | ||||||
$ | | $ | | |||||
Commitments (note 20)
The notes are an integral part of these consolidated financial statements.
Signed on behalf of the Board of Directors
|
|
Bjorn Inge Tonnessen, Director | Dennis Sykora, Director |
2021 Annual Report | 35 |
Consolidated Statements of Net Loss
and Comprehensive Loss
For the year ended December 31, | ||||||||
($ thousands, except per share amounts) |
| Note |
| 2021 |
| 2020 | ||
Revenue | ||||||||
Petroleum and natural gas revenues | 15 | $ | | $ | | |||
Royalties | ( | ( | ||||||
Petroleum and natural gas revenue, net of royalties | | | ||||||
Expenses | ||||||||
Direct operating | | | ||||||
General and administrative | | | ||||||
Depletion, depreciation and accretion | 8,12,19 | | | |||||
Impairment | 9 | | | |||||
Lease expiries | 9 | | | |||||
Share based compensation | 11 | | | |||||
Interest expense | | | ||||||
Interest and other income | ( | ( | ||||||
Loss before taxes | ( | ( | ||||||
Deferred tax recovery | 10 | ( | ( | |||||
Net loss | ( | ( | ||||||
Other Comprehensive Loss, Net of Tax | ||||||||
Items that may be reclassified subsequently to profit or loss: | ||||||||
Foreign currency translation adjustment | ( | ( | ||||||
Loss on foreign exchange on investments | 7 | ( | ( | |||||
( | ( | |||||||
Total Comprehensive Loss | $ | ( | $ | ( | ||||
Net Loss per Share | ||||||||
Basic and diluted | 14 | $ | ( | $ | ( | |||
The notes are an integral part of these consolidated financial statements.
36 | Questerre Energy Corporation |
Consolidated Statements of Changes in Equity
For the year ended December 31, | ||||||
($ thousands) | 2021 |
| 2020 | |||
Share Capital | ||||||
Balance, beginning of year | $ | | $ | | ||
Options exercised | | – | ||||
Balance, end of year | | | ||||
Contributed Surplus | ||||||
Balance, beginning of year | | | ||||
Share based compensation | | | ||||
Balance, end of year | | | ||||
Accumulated Other Comprehensive Loss | ||||||
Balance, beginning of year | ( | ( | ||||
Other comprehensive loss | ( | ( | ||||
Balance, end of year | ( | ( | ||||
Deficit | ||||||
Balance, beginning of year | ( | ( | ||||
Net loss | ( | ( | ||||
Balance, end of year | ( | ( | ||||
Total Shareholders' Equity | $ | | $ | | ||
The notes are an integral part of these consolidated financial statements.
2021 Annual Report | 37 |
Consolidated Statements of Cash Flows
For the years ended December 31, | ||||||||
($ thousands) |
| Note |
| 2021 |
| 2020 | ||
Operating Activities | ||||||||
Net loss | $ | ( | $ | ( | ||||
Adjustments for: | ||||||||
Depletion, depreciation and accretion | 8,12 | | | |||||
Impairment | 8,9 | | | |||||
Lease expiries | 9 | | | |||||
Share based compensation | 11 | | | |||||
Deferred tax recovery | 10 | ( | ( | |||||
Interest expense | | | ||||||
Interest and other income | ( | ( | ||||||
Abandonment expenditures | 12 | ( | ( | |||||
Adjusted funds flow from operations | | | ||||||
Interest expense | ( | ( | ||||||
Interest income | | | ||||||
Change in non-cash working capital | 18 | ( | | |||||
Net cash from operating activities | | | ||||||
Investing Activities | ||||||||
Property, plant and equipment expenditures | 8 | ( | ( | |||||
Exploration and evaluation expenditures | 9 | ( | ( | |||||
Change in non-cash working capital | 18 | | ( | |||||
Net cash used in investing activities | ( | ( | ||||||
Financing Activities | ||||||||
Proceeds from issue of share capital | | – | ||||||
Principal portion of lease payments | ( | ( | ||||||
Increase in credit facilities | | | ||||||
Repayment of credit facilities | ( | ( | ||||||
Net cash used in financing activities | ( | ( | ||||||
Change in cash, cash equivalents and restricted cash | ( | ( | ||||||
Cash, cash equivalents and restricted cash, beginning of year | | | ||||||
Cash, cash equivalents and restricted cash, end of year | $ | | $ | | ||||
The notes are an integral part of these consolidated financial statements.
38 | Questerre Energy Corporation |
Notes to the Consolidated Financial Statements
For the years ended December 31, 2021 and 2020
1. Reporting Entity
Questerre is
a) Segmented Disclosure
Management has determined the operating segments based on information regularly reviewed for the purposes of decision making, allocating resources, and assessing operational performance by Questerre’s chief operating decision makers comprising of the Chief Executive Officer and other members of executive management. The operating segments have been aggregated based on several factors including geographic location and stage of development as well as the assignment of reserves and resources.
The accounting policies applied by the segments are the same as those applied by the Company.
The Company’s operating segments at year end are as follows:
• | Western |
• | Quebec – Development of a significant natural gas discovery in the province with a focus on securing social acceptability and regulatory approvals for a clean technology energy project. |
• | Corporate & other – General and administrative resources to manage the respective operating segments. Includes exploration activities in the Kingdom of Jordan and an investment in Red Leaf Resources Inc. (“Red Leaf”). |
Segmented assets are those assets associated with each operating segment as recorded on the consolidated balance sheets.
The table below details the breakdown of assets by operating segment to the consolidated balance sheets and the reconciliation of income by operating segment to the consolidated statements of net income and comprehensive income.
2021 Annual Report | 39 |
| Western |
| Corporate | |||||||||
($ thousands) |
| Canada | Quebec |
| & other | Consolidated | ||||||
Assets by operating segment | ||||||||||||
Exploration and Evaluation | $ | 8,855 | $ | – | $ | 5,855 | $ | 14,710 | ||||
Property, Plant & Equipment | 140,120 | – | – | 140,120 | ||||||||
Other | 5,084 | 7,658 | 16,691 | 29,433 | ||||||||
Total Assets, December 31, 2021 | $ | 154,059 | $ | 7,658 | $ | 22,546 | $ | 184,263 | ||||
Exploration and Evaluation | $ | 6,381 | $ | 101,946 | $ | 5,876 | $ | 114,203 | ||||
Property, Plant & Equipment | 52,484 | – | – | 52,484 | ||||||||
Other | 3,502 | 7,356 | 18,632 | 29,490 | ||||||||
Total Assets, December 31, 2020 | $ | 62,367 | $ | 109,302 | $ | 24,508 | $ | 196,177 | ||||
Results by operating segment | ||||||||||||
Revenues | $ | 28,535 | $ | – | $ | – | $ | 28,535 | ||||
Expenses | (29,699) | (506) | (2,638) | (32,843) | ||||||||
Segmented Loss, December 31, 2021 | $ | (1,164) | $ | (506) | $ | (2,638) | $ | (4,308) | ||||
Deferred tax recovery | 7 | |||||||||||
Total Loss, December 31, 2021 | $ | (4,301) | ||||||||||
Revenues | $ | 20,609 | $ | – | $ | – | $ | 20,609 | ||||
Expenses | (134,116) | (987) | (3,139) | (138,242) | ||||||||
Segmented Loss, December 31, 2020 | $ | (113,507) | $ | (987) | $ | (3,139) | $ | (117,633) | ||||
Deferred tax recovery | 10 | |||||||||||
Total Loss, December 31, 2020 | $ | (117,623) | ||||||||||
2. Basis of Preparation
a) Statement of compliance
The Company prepares its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Boards (“IASB”). The policies applied in these consolidated financial statements are based on IFRS issued and outstanding as at March 24, 2022, the date the Board of Directors approved the statements.
b) Basis of measurement
The consolidated financial statements have been prepared on the historical cost basis except for financial assets classified as fair value through profit and loss which are measured at fair value with changes in fair value recorded in profit or loss and changes due to foreign exchange recorded through other comprehensive income or loss as disclosed in Note 3.
c) Functional and presentation currency
These consolidated financial statements are presented in Canadian dollars, which is the Company’s functional currency. The Company has a wholly-owned subsidiary with a functional currency of the Jordanian Dinar.
40 | Questerre Energy Corporation |
d) Jointly controlled assets
The Company conducts many of its oil and gas production activities through jointly controlled operations. Interests in joint arrangements are classified as either joint operations or joint ventures, depending on the rights and obligations of the parties to the arrangement. Joint operations arise when the Company has rights to the assets and obligations for the liabilities of the arrangement. The Company recognizes its share of assets, liabilities, revenues and expenses of a joint operation. Joint ventures arise when the Company has rights to the net assets of the arrangement. Joint ventures are accounted for under the equity method.
e) Use of estimates and judgments
The preparation of consolidated financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates. These estimates and judgments have risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year.
Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the year in which the estimates are revised and in any future years affected.
Petroleum and natural gas reserves
All of Questerre’s petroleum and natural gas reserves are evaluated and reported on by independent reserve engineers in accordance with the COGE Handbook and Canadian Securities Administrators’ National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The estimation of reserves is a subjective process. Forecasts are based on engineering data, anticipated future commodity prices, expected production volumes, future operating and development costs, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change to reflect updated information. Reserve estimates can be revised upward or downward based on the results of future drilling, testing, production levels and changes in costs and commodity prices. These estimates are evaluated by independent reserve engineers at least annually.
Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the estimated proved plus probable reserves and there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves.
Reserve estimates impact a number of areas, in particular, the valuation of property, plant and equipment, and the calculation of depletion.
Refer to Note 8 & 9 for carrying amounts of property, plant and equipment, exploration and evaluation assets.
Exploration and evaluation assets
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The application of the Company's accounting policy for exploration and evaluation assets requires judgement in determining whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined. In addition, Management uses judgement to determine when exploration and evaluation (“E&E”) assets are reclassified to property, plant and equipment (“PP&E”) assets.
Exploration and evaluation assets are subject to ongoing management review to confirm the continued intent to establish the technical feasibility and commercial viability of the assets. In making this determination, various factors are considered such as drilling results, future capital and operating expenditures, including judgement over the amount of economically recoverable resources, and whether the appropriate government, regulatory, or internal approvals are likely to be received.
Cash generating units (“CGU”)
A CGU is defined as the lowest grouping of assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations. Factors considered in the classification include geography and the way management monitors and makes decisions about its operations.
Refer to Note 8 for carrying amounts of property, plant and equipment.
Impairment of property, plant and equipment, exploration and evaluation and goodwill
The Company assesses its oil and gas properties, including exploration and evaluation assets, for possible impairment or reversal of previously recognized impairments if there are events or changes in circumstances that indicate that carrying values of the assets may not be recoverable or indications that previously recognized losses should be reversed. Determining if there are facts and circumstances present that indicate that carrying values of the assets may not be recoverable requires management’s judgment and analysis of the facts and circumstances.
The recoverable amounts of CGUs have been determined based on the higher of value in use (“VIU”) and the fair value less costs of disposal (“FVLCD”). Significant assumptions the Company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, quantities of reserves, 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 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 at an operating segment level based on the recoverable amount for each CGU of the Company. Therefore, impairment of goodwill uses the same significant assumptions noted above for impairment of assets.
Asset retirement obligation
Determination of the Company’s asset retirement obligation is based on Government regulations, operator estimates and internal estimates using current costs and technology in accordance with existing legislation and
42 | Questerre Energy Corporation |
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.
Refer to Note 12 for the carrying amounts related to the asset retirement obligation.
Share based compensation
The Company has a stock option plan enabling employees, officers and directors to receive Class “A” Common voting shares (“Common Shares”) or cash at exercise prices equal to the market price or above on the date the option is granted. Notwithstanding, the Company has the right to only equity settle options. While the Company has equity settled options for the past nine years, it may change this in the future at its discretion. Under the equity settled method, compensation costs attributable to stock options granted to employees, officers or directors are measured at fair value using the Black-Scholes option pricing model. The assumptions used in the calculation are: the volatility of the stock price, risk-free rates of return and the expected lives of the options. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Changes to assumptions may have a material impact on the amounts presented.
For further detail refer to Note 11.
Income tax accounting
Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing tax laws in each jurisdiction differ significantly from the Company’s estimate, the ability of the Company to realize the deferred tax assets could be impacted.
The determination of the Company’s income and other tax assets or liabilities requires interpretation of complex laws and regulations. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax asset or liability may differ significantly from that estimated and recorded by management.
Refer to Note 10 for the carrying amounts related to deferred taxes.
Investment in Red Leaf
Questerre holds investments in certain private companies including its investment in Red Leaf.
The Company uses the equity method of accounting to reflect its ownership in Red Leaf. Under the equity method, the Company’s initial and subsequent investments are recognized at cost and subsequently adjusted for the Company’s share of Red Leaf’s income or loss, less distributions received. The Company is deemed to have significant influence in Red Leaf on the basis that it holds more than 20% of the voting power and the ability to participate in the decision making process of Red Leaf through its current Board representation.
Refer to Note 7 for the carrying amounts related to the Company’s investment in Red Leaf.
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3. Significant Accounting Policies
The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements.
a) Basis of consolidation
Subsidiaries
Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are considered.
The acquisition method of accounting is used to account for business combinations that meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. Contingent consideration is included in the cost of acquisitions at fair value. Directly attributable transaction costs are expensed in the current period and reported within general and administrative expenses. The excess of the cost of acquisition over the fair value of the identifiable assets, liabilities and contingent liabilities acquired is recorded as goodwill. If the cost of the acquisition is less than the fair value of the net assets acquired, the difference is recognized immediately in profit or loss.
Transactions eliminated on consolidation
Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.
b) Financial instruments
Financial assets and liabilities are recognized when the Company becomes a party to the contractual provisions of the instrument. Financial assets are derecognized when the rights to receive cash flows from the assets have expired or have been transferred and the Company has transferred substantially all risks and rewards of ownership. Financial liabilities are derecognized when the obligation specified in the contract is discharged, cancelled or expires.
Financial assets and liabilities are offset and the net amount is reported in the balance sheet when there is a legally enforceable right to offset the recognized amounts and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.
The Company classifies its financial instruments in the following categories, at initial recognition, depending on the purpose for which the instruments were acquired.
Financial assets and liabilities at fair value through profit or loss
A financial asset or liability is classified in this category if it is held for trading. Derivatives are also included in this category unless they are designated as hedges. The Company has designated its risk management contracts in this category.
44 | Questerre Energy Corporation |
Financial assets at amortized cost
Financial assets at amortized cost are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They include accounts receivable and deposits. These assets are included in current assets due to their short-term nature. They are recognized initially at the amount expected to be received, less, when material, a discount to reduce to fair value. Subsequently, they are measured at amortized cost using the effective interest method less a provision for impairment.
Cash and cash equivalents include deposits held with banks, less outstanding cheques, and short-term deposits with original maturities of one year or less.
Financial liabilities at amortized cost
Financial liabilities at amortized cost comprise credit facilities and accounts payable and accrued liabilities. Financial liabilities are initially recognized at the amount required to be paid, less, when material, a discount to reduce the payables to fair value. Subsequently, financial liabilities are measured at amortized cost using the effective interest method.
Financial liabilities are classified as current liabilities if payment is due within twelve months.
c) Investments
For the purposes of testing for impairment, the Company measures the fair market value of Red Leaf by valuation techniques such as net asset value analysis. Judgment is required in measuring the fair value of the Company’s investment in Red Leaf, which may result in material adjustments to its related carrying value.
d) Share capital
Common Shares are classified as equity. Incremental costs directly attributable to the issue of Common Shares are recognized as a deduction from equity, net of any tax effects.
e) Property, plant and equipment and exploration and evaluation assets
Recognition and measurement
Exploration and evaluation expenditures
Costs incurred prior to acquiring the legal rights to explore an area are recognized as exploration and evaluation expense in profit or loss.
Exploration and evaluation costs, including the costs of acquiring licenses, exploratory well expenditures, costs to evaluate the commercial potential of underlying resources and directly attributable general and administrative costs, are capitalized as exploration and evaluation assets. The costs are accumulated in cost centres by exploration area pending determination of technical feasibility and commercial viability. Gains and losses on exploration and evaluation assets are recognized on disposal through the income statement.
At each reporting period, exploration and evaluation assets are assessed for impairment to determine if (i) sufficient data exists to determine technical feasibility and commercial viability, or (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount.
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The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable based on several factors including the assignment of reserves. A review of each exploration license or field is carried out, at each reporting date, to ascertain whether technical feasibility and commercial viability has been achieved. Upon determination of technical feasibility and commercial viability, intangible exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to property, plant and equipment.
Every reporting period, the Company evaluates individually significant exploration and evaluation wells for impairment, if there are specific impairment indicators evident at the well level. If technical feasibility and commercial viability of the well is not established, the well costs are written off. For insignificant wells, overall exploration and evaluation well indicators are evaluated. If there are indicators of impairment, the wells are tested for impairment at the CGU level.
Development and production costs
Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Cost includes all costs required to acquire developed or producing oil and gas properties and to develop oil and gas properties. Development and production assets are grouped into CGUs for impairment testing.
Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of the property, plant and equipment and are recognized net within gain (loss) on divestures in profit or loss.
Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. When the exchange is at fair value, a gain or loss is recognized in profit or loss.
Business Combinations
Business combinations are accounted for using the acquisition method of accounting. The determination of fair value often requires management to make assumptions and estimates about future events. The assumptions and estimates with respect to determining the fair value of exploration and evaluation assets and property, plant and equipment acquired generally require the most judgment and include estimates of reserves acquired, forecast benchmark commodity prices and discount rates. Assumptions are also required to determine the fair value of decommissioning obligations associated with the properties. Changes in any of these assumptions or estimates used in determining the fair value of acquired assets and liabilities could impact the amounts assigned to assets, liabilities and goodwill (or gain from a bargain purchase) in the acquisition equation. Future profit (loss) can be affected as a result of changes in future depletion and depreciation or impairment.
Other property, plant and equipment
Expenditures related to workovers or betterments that improve the productive capacity or extend the life of an asset are capitalized. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.
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Depletion and depreciation
The net carrying value of development and production assets is depleted using the unit of production method based on estimated proved and probable reserves, considering estimated future development costs necessary to bring those reserves into production. These estimates are evaluated by independent reserve engineers at least annually.
For other assets, depreciation is recognized in profit or loss on a straight-line basis over the respective useful lives.
Depreciation methods and useful lives are reviewed at each reporting date.
f) Goodwill
Goodwill arises on the acquisition of businesses, subsidiaries, associates and joint ventures. Goodwill is measured at cost less accumulated impairment losses. Goodwill is not amortized.
g) Impairment
Non-financial assets
The carrying amounts of the Company’s non-financial assets, other than deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated and compared to the carrying amount. For goodwill an impairment test is completed each year, or when any indication of impairment exists.
For the purpose of impairment testing, assets are grouped together into CGUs. Goodwill, for the purpose of impairment testing, is assessed for impairment on an operating segment basis. The Company has three operating segments. Exploration and evaluation assets are allocated to related CGUs when they are assessed for impairment, both at the time of any triggering facts and circumstances as well as upon their reclassification to producing assets.
The recoverable amount of an asset or a CGU is the greater of its VIU and FVLCD. FVLCD is determined using discounted future cash flows of proved and probable reserves using an after tax discount rate for FVLCD. In determining FVLCD, recent market transactions are considered, if available. In the absence of such transactions, the discounted cash flow model is used. In assessing VIU, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset.
An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit (group of units) on a pro rata basis.
An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount
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does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized. Impairment reversals are recognized in profit or loss.
Impairment of financial assets
Questerre applies the simplified approach to providing for expected credit losses prescribed by IFRS 9 Financial Instruments (“IFRS 9”) which permits the use of the lifetime expected loss provision for all trade receivables carried at amortized costs.
At each reporting date, the Company measures the lifetime expected loss provision taking into consideration Questerre’s historical credit loss experience as well as forward-looking information in order to establish loss rates. The impairment loss (or reversal) is the amount of expected credit losses that is required to adjust the loss allowance at the reporting date to the amount that is required to be recognized. Also refer to Note 6.
Share based compensation
The Company has issued options to directors, officers and employees.
The Company accounts for its stock-based compensation awards on the basis that they will be equity settled. Under the equity settled method, compensation costs attributable to stock options granted to employees, officers or directors are measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. The exercise of stock options is recorded as an increase in Common Shares with a corresponding reduction in contributed surplus. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest.
h) Provisions
A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability.
Asset retirement obligation
The Company’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category.
Asset retirement obligations are measured at the present value of management’s best estimate of expenditure required to settle the present obligation at the balance sheet date. The best estimate of the provision is recorded on a discounted basis using a risk-free interest rate. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as accretion of the asset retirement obligation whereas increases or decreases due to changes in the estimated future cash flows and risk-free rates are adjusted through property, plant and equipment or exploration and evaluation assets. Actual costs incurred upon settlement of the asset retirement obligations are charged against the provision.
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i) Revenue from commodity sales and royalties
Questerre principally generates revenue from the sale of commodities, which include crude oil, natural gas, condensate and natural gas liquids (“NGLs”). Questerre also generates revenue from royalties on production from leases where it owns a working interest. Revenue associated with the sale of commodities is recognized when control is transferred from Questerre to its customers. Questerre’s commodity sale contracts represent a series of distinct transactions. Questerre considers its performance obligations to be satisfied and control to be transferred when all of the following conditions are satisfied:
| ● | Questerre has transferred title and physical possession of the commodity to the buyer; |
| ● | Questerre has transferred the significant risks and rewards of ownership of the commodity to the buyer; and |
| ● | Questerre has the present right to payment. |
Revenue represents the Company’s share of commodity sales net of royalty obligations to governments and other mineral interest owners. Questerre sells its production pursuant to variable priced contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under these contracts, the Company is required to deliver a variable volume of crude oil, natural gas, condensate or NGLs to the contract counterparty.
Revenue is recognized when a unit of production is delivered to the contract counterparty. The amount of revenue recognized is based on the agreed upon transaction price, whereby any variability in revenue is related specifically to the Company’s efforts to deliver production. Therefore, the resulting revenue is allocated to the production delivered in the period during which the variability occurs. Payment terms for Questerre’s commodity sales contracts are on the 25th of the month following delivery. Questerre does not have any contracts where the period between the transfer of the promised goods or services to the customer and payment by the customer exceeds one year and therefore Questerre does not adjust its revenue transactions for the time value of money. The Company enters into contracts with customers that can have performance obligations that are unsatisfied, or partially unsatisfied, at the reporting date.
Royalty revenue is recognized as it accrues in accordance with the terms of the governing agreement, which is generally in the month when the product is produced with production volumes primarily marketed with the payor’s production. Royalty revenue is measured at fair value of the consideration received when Management can reliably estimate the amount pursuant to the terms of the royalty agreement. An accrual is included in revenue and accounts receivable for amounts not received at the reporting date based on historical trends, new wells on stream and current market prices. Differences between the estimates and actual amounts received are adjusted and recorded in the period when the actual amounts are received.
j) Income tax
Deferred tax is recognized using the balance sheet method, providing for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes.
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Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.
A deferred tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax asset will be realized.
The effect of a change in enacted or substantively enacted income tax rates on future income tax assets and liabilities is recognized in profit or loss in the period that the change occurs unless the original entry was recorded to equity.
k) Net profit or loss per share
Basic per share amounts are calculated using the weighted average number of shares outstanding during the year. Diluted per share amounts are calculated using the weighted average number of shares outstanding, adjusted for the potential number of shares which may have a dilutive impact on net profit. Potentially dilutive shares include stock options. The weighted average number of diluted shares is calculated in accordance with the treasury stock method. The treasury stock method assumes that the proceeds received from the exercise of all potentially dilutive instruments are used to repurchase Common Shares at the average market price.
Since the options may be settled in cash or shares at the Company’s discretion and therefore there is no obligation to settle in cash, the share units are accounted for as equity-settled share based payment transactions and included in diluted profit per share if the effect is dilutive.
l) Leases
Under IFRS 16, the Company recognizes right-of-use assets and lease liabilities for most leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements and may continue to be treated as operating leases. The right-of-use assets recognized are subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the right-of-use assets or the end of the lease term. The estimated useful lives of right-of-use assets are determined on the same basis as those of property and equipment. In addition, the right-of-use assets are periodically reduced by impairment losses, if any, and adjusted for certain re-measurements of the lease liabilities.
The lease liabilities are initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate. The Company uses its incremental borrowing rate as the discount rate.
The lease liabilities are subsequently measured at amortized cost using the effective interest method. It is re-measured when there is a change in future lease payments arising from a change in an index or rate, if there is
50 | Questerre Energy Corporation |
a change in the Company's estimate of the amount expected to be payable under a residual value guarantee, or if the Company changes its assessment of whether it will exercise a purchase, extension or termination option.
When the lease liabilities are re-measured in this way, a corresponding adjustment is made to the carrying amount of the right-of-use assets or is recorded in profit or loss if the carrying amount of the right-of-use assets has been reduced to $0. The Company presents right-of-use assets and lease liabilities separately in the balance sheet.
The application of IFRS 16 requires significant judgments and estimations to be made. Areas that require judgment include identifying whether a contract (or part of a contract) includes a lease, determining whether it is reasonably certain that an extension or termination option will be exercised, determining whether variable payments are in substance fixed, establishing whether there are multiple leases in an arrangement and determining the stand-alone amounts for lease and non-lease components. Other sources of estimation uncertainty in the application of IFRS 16 include estimating the lease term, determining the appropriate discount rate to apply to lease payments and assessing whether a right-of-use assets are impaired.
4. Changes in Accounting Policies and Disclosures
a) Future Accounting Pronouncements
In January 2021, the IASB issued amendments to IAS 1 Presentation of Financial Statements, to clarify its requirements for the presentation of liabilities as current or non-current in the consolidated balance sheet. The amendment is effective for periods beginning on or after January 1, 2023.
In May 2020, the IASB issued Onerous Contracts - Cost of Fulfilling a Contract, which made amendments to IAS 37 Provisions Contingent Liabilities and Contingent Assets. Effective January 1, 2022, the amendments specify which costs an entity includes in determining the cost of fulfilling a contract for the purpose of assessing whether the contract is onerous.
5. Cash and Cash Equivalents
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Bank balances | $ | 37 | $ | 177 | ||
Short-term bank deposits | 8,494 | 10,227 | ||||
$ | 8,531 | $ | 10,404 | |||
6. Financial Risk Management and Determination of Fair Values
a) Overview
The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities such as credit risk, liquidity risk and market risk. The Company manages its exposure to these risks by operating in a manner that minimizes this exposure.
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b) Fair value of financial instruments
The Company’s financial instruments as at December 31, 2021 included cash and cash equivalents, accounts receivable, deposits, investments, credit facilities and accounts payable and accrued liabilities. As at December 31, 2021, the fair values of the Company’s financial assets and liabilities equaled their carrying values due to the short-term maturity.
Disclosures about the inputs to fair value measurements are required, including their classification within a hierarchy that prioritizes the inputs to fair value measurement.
Level 1 Fair Value Measurements
Level 1 fair value measurements are based on unadjusted quoted market prices.
Level 2 Fair Value Measurements
Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices.
Level 3 Fair Value Measurements
The net book value of PP&E recognized is based on historical cost until tested for impairment using market values. The market value of PP&E is the estimated amount for which PP&E could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of oil and natural gas interests (included in PP&E) are generally estimated with reference to the discounted cash flows expected to be derived from oil and natural gas production based on internally and externally prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market conditions. The market value of E&E assets is estimated with reference to the market values of current arm’s length transactions in comparable locations. Refer to Notes 8 and 9.
c) Credit risk
Credit risk represents the potential financial loss to the Company if a customer or counterparty to a financial instrument fails to meet or discharge their obligation to the Company. Credit risk arises principally from the Company’s receivables from joint venture partners and oil and gas marketers. The carrying amounts of accounts receivable and cash and cash equivalents represent the maximum credit exposure.
Substantially all of the accounts receivable are with oil and natural gas marketers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. The Company generally extends unsecured credit to these customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions. Management believes the risk is mitigated by entering into transactions with long-standing, reputable counterparties and partners.
Accounts receivable related to the sale of the Company’s petroleum and natural gas production is paid in the following month from major oil and natural gas marketing companies and the Company has not experienced any credit loss relating to these sales.
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Receivables from joint venture partners are typically collected within one to three months of the joint venture bill being issued. The Company mitigates this risk by obtaining pre-approval of significant capital expenditures.
The Company’s accounts receivables are aged as follows:
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Current | $ | 3,154 | $ | 2,759 | ||
31 - 60 days | 1 | 31 | ||||
61 - 90 days | 11 | 4 | ||||
>90 days | 1,012 | 177 | ||||
Expected credit loss provision | (162) | (288) | ||||
$ | 4,016 | $ | 2,683 | |||
The Company does not anticipate any material default as it transacts with creditworthy customers and management does not expect any losses from non-performance by these customers. There are no material financial assets that the Company considers past due that are considered impaired.
Cash and cash equivalents include cash bank balances and short-term deposits. The Company manages the credit risk exposure by investing in Canadian banks and credit unions. Management does not expect any counterparty to fail to meet its obligations.
d) Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s processes for managing liquidity risk include ensuring, to the extent possible, that it will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual capital expenditure budgets which are monitored and are updated as required. In addition, the Company requires authorizations for expenditures on projects to assist with the management of capital.
Since the Company operates in the upstream oil and natural gas industry, it requires sufficient cash to fund capital programs necessary to maintain or increase production, develop reserves and to potentially acquire strategic assets. The Company’s capital programs are funded principally by cash obtained through its credit facilities, equity issuances and from operating activities. During times of low oil and natural gas prices or when cash resources may be limited, a portion of capital programs can generally be deferred, however, due to the long cycle times and the importance to future cash flow in maintaining the Company’s production, it may be necessary to utilize alternative sources of capital to continue the Company’s strategic investment plan during periods of low commodity prices. As a result, the Company frequently evaluates the options available with respect to sources of long and short-term capital resources. Occasionally, to the extent possible, the Company will use derivative instruments to manage cash flow in the event of commodity price declines.
The Company’s financial obligations relates to amounts due under the credit facilities, including trade and other payables, which consist of invoices payable to trade suppliers relating to the office and field operating activities and its capital spending program. The Company processes invoices within a normal payment period and all amounts are due within the next 12 months.
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The timing of cash outflows relating to financial liabilities as at December 31, 2021 and 2020 are as follows:
Less than | One to three | Subsequent | ||||||||||
($ thousands) |
| one year |
| years |
| years |
| Total | ||||
Credit Facilities | $ | 3,420 | $ | – | $ | – | $ | 3,420 | ||||
Trade and other liabilities | 8,361 | – | – | 8,361 | ||||||||
Lease Liabilities | 52 | 150 | 5 | 207 | ||||||||
Contingent Liabilities | – | 1,820 | – | 1,820 | ||||||||
December 31, 2021 | $ | 11,833 | $ | 1,970 | $ | 5 | $ | 13,808 | ||||
Less than | One to Three | Subsequent | ||||||||||
($ thousands) |
| one year |
| Years |
| years |
| Total | ||||
Credit Facilities | $ | 15,427 | $ | – | $ | – | $ | 15,427 | ||||
Trade and other liabilities | 6,186 | – | – | 6,186 | ||||||||
Lease Liabilities | 50 | 166 | 39 | 255 | ||||||||
Contingent Liabilities | – | 1,820 | – | 1,820 | ||||||||
December 31, 2020 | $ | 21,663 | $ | 1,986 | $ | 39 | $ | 23,688 | ||||
e) Market risk
Market risk is the risk that changes in market prices, such as commodity prices, foreign exchange rates and interest rates will affect the Company’s profit or loss or the value of the financial instruments. The objective of the Company is to mitigate exposure to these risks while maximizing returns to the Company.
Commodity price risk
Commodity price risk is the risk that the fair value or future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted not only by the relationship between the Canadian and United States dollar, but also world economic events that dictate the levels of supply and demand. The Company may enter into oil and natural gas contracts to protect, to the extent possible, its cash flow on future sales. The contracts reduce the volatility in sales revenue by locking in prices with respect to future deliveries of oil and natural gas.
As at December 31, 2021, the Company had no outstanding commodity risk management contracts.
Currency risk
All of Questerre’s petroleum and natural gas sales are denominated in Canadian dollars; however, the underlying market prices for these commodities are impacted by the exchange rate between Canada and the United States. The Company also incurs expenditures in its Jordanian subsidiary that are denominated in Jordanian Dinar and United States dollars. As at December 31, 2021, the Company had no forward foreign exchange contracts in place.
54 | Questerre Energy Corporation |
Interest rate risk
Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. At December 31, 2021, the Company had credit facilities outstanding of $3.4 million (December 31, 2020: $15.4 million).
f) Capital management
The Company believes with its expected positive adjusted funds flow from operations and existing credit facilities in the near future it will be able to meet its foreseeable obligations in the normal course of operations. On an ongoing basis, the Company reviews its capital expenditures to ensure that funds flow from operations or access to credit facilities are available to fund these capital expenditures. To execute its current business plan including incurring capital expenditures related to the full participation in the current and future drilling programs it anticipates it will be require access to additional financial liquidity.
The volatility of commodity prices has a material impact on Questerre’s adjusted funds flow from operations. Questerre attempts to mitigate the effect of lower prices by entering into risk management contracts, shutting in production in unusually low pricing environments, reallocating capital to more profitable areas and reducing capital spending based on results and other market considerations.
The Company considers its capital structure to include shareholders’ equity and any outstanding amounts under its credit facilities. The Company will adjust its capital structure to minimize risk and its cost of capital through the issuance of shares, securing additional credit facilities and adjusting its capital spending as required. Questerre monitors its capital structure based on the current and projected funds flow from operations.
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Credit facilities | $ | 3,420 | $ | 15,427 | ||
Shareholders' equity | 148,961 | 152,120 | ||||
7. Investment in Red Leaf
Red Leaf is a private Utah based oil shale and technology company whose principal assets are its proprietary EcoShale
technology to recover oil from shale and its oil shale leases in the state of Utah.
As at December 31, 2021, Questerre holds 132,292 common shares, representing approximately 41% of the common share capital of Red Leaf and 288 Series A Preferred Shares of Red Leaf representing approximately 16% of the issued and outstanding preferred shares capital of Red Leaf on a non-diluted basis.
Questerre has determined its investment in Red Leaf will be accounted for using the equity method. This is based on several criteria including its current equity interest in Red Leaf and ability to participate in the decision making process of Red Leaf through its current Board representation. The Company measures the fair market value of its investment using a net asset value approach. The net asset value is calculated as the current assets of Red Leaf less abandonment liabilities, the accrued and unpaid dividends associated with the preferred shares
2021 Annual Report | 55 |
and an estimate of research and development and general and administrative expenses for the upcoming fiscal year.
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Balance, beginning of year | $ | 7,979 | $ | 8,439 | ||
Dividends received on preferred shares | – | (228) | ||||
Loss on foreign exchange | (14) | (232) | ||||
Balance, end of the year | $ | 7,965 | $ | 7,979 | ||
The assets, liabilities and net loss of Red Leaf as of December 31, 2021 were comprised as follows:
($ thousands)(1) |
|
| 2021 |
| 2020 | |
Cash and Cash Equivalents | $ | 26,770 | $ | 24,756 | ||
Other Current Assets | 268 | 282 | ||||
Current Liabilities | 617 | 646 | ||||
Non-current liabilities | 2,150 | 1,554 | ||||
Net Loss(2) | $ | (3,977) | $ | (12,884) | ||
(1) Converted at an exchange rate of US$1=C$1.2678 | ||||||
(2) Converted at an average exchange rate of US$1=C$1.2535 | ||||||
The issued and outstanding share capital of Red Leaf as of December 31, 2021 is comprised of the following:
Issued and | Questerre | |||||
| Outstanding |
| Ownership | |||
Common Shares | 319,728 | 132,292 | ||||
Preferred Shares | 1,795 | 288 |
The Series A Preferred Shares carry voting rights and dividends accrue on a cumulative basis, whether or not declared, at a rate of 8% per annum compounding annually. On the occurrence of a defined liquidation event, including certain reorganizations, takeovers, the sale of all or substantially all the assets of the company, and shareholder distributions, the Series A Preferred shareholders are entitled to an amount representing the original issue price plus any accrued dividends. As of December 31, 2021, this priority amount is approximately US$1.2 million.
56 | Questerre Energy Corporation |
8. Property, Plant and Equipment
A reconciliation of the property, plant and equipment assets is detailed below.
($ thousands) |
| Total | |
Cost or deemed cost: | |||
Balance, December 31, 2019 | $ | 285,740 | |
Additions | 2,496 | ||
Transfer from exploration and evaluation assets | 2,687 | ||
Balance, December 31, 2020 | 290,923 | ||
Change to asset retirement | 1,694 | ||
Balance, December 31, 2021 | $ | 292,617 | |
Accumulated depletion, depreciation and impairment losses: | |||
Balance, December 31, 2019 | $ | 132,946 | |
Depletion and depreciation | 9,236 | ||
Impairment | 96,257 | ||
Balance, December 31, 2020 | 238,439 | ||
Depletion and depreciation | 5,794 | ||
Reversal of previous impairment | (91,736) | ||
Balance, December 31, 2021 | $ | 152,497 | |
($ thousands) |
| Total | |
Net book value: | |||
At December 31, 2020 | $ | 52,484 | |
At December 31, 2021 | $ | 140,120 | |
During the years ended December 31, 2021 and 2020, the Company did not capitalize any administrative overhead or share based compensation expense directly related to development activities. Included in the December 31, 2021, depletion calculation are future development costs of $271.3 million (December 31, 2020: $267.8 million).
The Company assessed the carrying value of its PP&E as at December 31, 2021, for indicators of impairment or indicators to reverse previously recorded impairment. Based on this review, the Company’s Montney and Antler CGUs were tested in accordance with the Company’s accounting policy. The recoverable amount of the CGUs was estimated based on the FVLCD using a discounted cash flow model. Due to the higher future commodity prices, the Company recorded a reversal of $91.7 million in impairment expense incurred in 2020. Of this amount, $76 million was attributable to the Kakwa, Alberta CGU and $15.7 million to the Antler, Saskatchewan CGU. No impairment reversals were recorded for the Company’s other CGUs.
The estimates of FVLCD were determined using discount rates ranging from 11% to 13% (2020: 11% to 13%) and forecasted after tax cash flows based on proved plus probable reserves, with escalating prices and future development costs. As at December 31, 2021, the future prices used to determine cash flows from crude oil and natural gas reserves were as follows:
2021 Annual Report | 57 |
Average | ||||||||||||
Annual % | ||||||||||||
Change | ||||||||||||
| 2022 |
| 2023 |
| 2024 |
| 2025 |
| 2026 |
| Thereafter | |
WTI (US$/barrel) | 72.83 | 68.78 | 66.76 | 68.09 | 69.45 | 2.00 | ||||||
AECO ($/MMbtu) | 3.56 | 3.21 | 3.05 | 3.11 | 3.17 | 2.00 |
Effective March 31, 2020, the Company reviewed the carrying amounts of its oil and natural gas assets based on the material decline in commodity prices and the resulting decrease in forward benchmark commodity prices as of March 31, 2020, compared to December 31, 2019. Based on this review, the Company tested its CGUs for impairment in accordance with its accounting policy. The recoverable amount of the CGUs was estimated based on the FVLCD using a discounted cash flow model. The impairment testing concluded that the carrying amounts of Montney, Antler and Other Alberta CGUs exceeded their FVLCD. As a result, the Company recorded an impairment expense of $96.3 million in aggregate. The amount attributable to the Montney, Antler and Other Alberta CGUs is respectively $78.2 million, $17.9 million, and $0.2 million.
The estimates of FVLCD were determined using discount rates ranging from 11% to 13% and forecasted after tax cash flows based on proved plus probable reserves, with escalating prices and future development costs. As at March 31, 2020, the future prices used to determine cash flows from crude oil and natural gas reserves were as follows:
Average | ||||||||||||
Annual % | ||||||||||||
Change | ||||||||||||
| 2021 |
| 2022 |
| 2023 |
| 2024 |
| 2025 |
| Thereafter | |
WTI (US$/barrel) | 40.45 | 49.17 | 53.28 | 55.66 | 56.87 | 2.00 | ||||||
AECO ($/MMbtu) | 2.20 | 2.38 | 2.45 | 2.53 | 2.60 | 2.00 |
9. Exploration and Evaluation Assets
Exploration and evaluation assets consist of the Company’s exploration projects which are pending the determination of technical feasibility and commercial viability. Additions represent the Company’s share of costs incurred on exploration and evaluation assets during the period.
58 | Questerre Energy Corporation |
A reconciliation of the movements in exploration and evaluation assets is detailed below.
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Balance, beginning of year | $ | 114,203 | $ | 127,081 | ||
Acquisition | – | 263 | ||||
Additions | 4,719 | 4,811 | ||||
Transfers to property, plant and equipment | – | (2,687) | ||||
Undeveloped lease impairments | 0 | (14,416) | ||||
Undeveloped lease expiries and farmouts | (220) | (717) | ||||
Foreign currency translation adjustment - Jordan | (145) | (132) | ||||
Balance, end of period | $ | 118,557 | $ | 114,203 | ||
During the year ended December 31, 2021, the Company capitalized administrative overhead charges of $1.1 million (2020: $1.9 million) and $0.67 million (2020: $0.9 million) for capitalized share based compensation expense directly related to exploration and evaluation activities.
As a result of the introduction of Bill 21 - An Act mainly to end petroleum exploration and production and the public financing of those activities, the Company impaired the full carrying value of its Quebec exploration and evaluation assets of $104 million.
The Company estimates qualifying exploration and development expenditures of $164.6 million were incurred on its exploration licenses from 2006 to 2021. Of this amount $156.7 million was incurred on permits where the Company is currently the operator, $4 million was incurred on permits where it is non-operator and $3.9 million incurred on permits that have been surrendered. In addition, the Company incurred mineral rentals and surface rentals totalling $3.9 million and has placed deposits with the Government for abandonment and reclamation liabilities of $7.2 million.
The Company will seek just compensation for the value of its licenses in the event the legislation is enacted and will object to the revocation of its licenses until just compensation is received.
Effective March 31, 2020, as a result of the decline in commodity prices and no future plans to pursue development of its wholly owned and operated exploration and evaluation assets in Kakwa, the Company impaired exploration and evaluation assets in Kakwa totaling $14.4 million.
10. Deferred Income Taxes
The tax on the Company’s net loss before taxes differs from the amount that would arise using the weighted average tax rate applicable to profits or losses of the consolidated entities as follows:
2021 Annual Report | 59 |
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Net loss before taxes | $ | (4,308) | $ | (117,633) | ||
Combined federal and provincial tax rate | 23.58% | 24.47% | ||||
Computed "expected" deferred tax recovery | (1,016) | (28,785) | ||||
Increase in deferred taxes resulting from: | ||||||
Non-deductible differences and permanent items | 241 | 831 | ||||
Non-taxable portion of capital items | – | 54 | ||||
Change in deferred tax asset not recognized | 775 | 26,077 | ||||
Rate adjustments and other | – | 1,823 | ||||
Deferred tax expense | $ | – | $ | – | ||
The Company evaluated the recoverability of its deferred tax assets using forecasted before-tax cash flows based on proved reserves, with escalating prices and future development costs obtained from an independent reserve evaluation report and a deduction for estimated general and administrative costs associated with these proved reserves. As a result, no deferred tax asset was recorded. The combined statutory tax rate was 23.58% in 2021 and 24.47% in 2020.
The movement in deferred tax assets and liabilities during the year, without taking into consideration the valuation allowances, are as follows:
Petroleum and | Asset | |||||||||||||||||
natural gas | retirement | Share | Non-capital | Capital | ||||||||||||||
($ thousands) |
| properties |
| Investments |
| obligation |
| issue costs |
| losses |
| losses | ||||||
December 31, 2020 | $ | 21,578 | $ | 3,650 | $ | 4,795 | $ | 274 | $ | 15,092 | $ | 4,295 | ||||||
Change | 3,670 | (1) | 276 | (205) | (2,810) | 7 | ||||||||||||
December 31, 2021 | $ | 25,248 | $ | 3,649 | $ | 5,071 | $ | 69 | $ | 12,282 | $ | 4,302 | ||||||
The amount and timing of reversals of temporary differences will be dependent upon, among other things, the Company’s future operating results, and acquisitions and dispositions of assets and liabilities.
Non-capital loss carry-forwards at December 31, 2021 expire from 2036 to 2040.
60 | Questerre Energy Corporation |
The following temporary differences have not been recognized:
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Petroleum and natural gas properties | $ | 107,061 | $ | 91,655 | ||
Investments | 30,944 | 31,006 | ||||
Asset retirement obligation and leases | 21,504 | 20,368 | ||||
Share issue costs | 294 | 1,016 | ||||
Non-capital losses | 52,084 | 64,107 | ||||
Capital losses | 36,488 | 36,488 | ||||
Total | $ | 248,375 | $ | 244,640 | ||
11. Share Based Compensation
The Company has a stock option program that provides for the issuance of options to purchase Common Shares to its directors, officers and employees at or above grant date market prices. The options granted under the plan generally vest evenly over a three-year period starting at the grant date or one year from the grant date. The grants generally expire five years from the grant date or five years from the commencement of vesting.
Under the Company’s option plan, a put right is included that allows the optionee to settle options with cash or equity. Under the put right, the optionee will receive the net cash proceeds that is the excess of the closing price of the Common Shares at the day of the put notice over the exercise price of the option. The Company has the option to decline a put right exercise at any time. The Company does not intend to cash settle options in future periods.
For the year ended December 31, 2021, the Company cash settled 2.34 million expiring options for a payment of $0.1 million (2020: Nil) representing the difference between the exercise and market price on the date of the settlement.
The number and weighted average exercise prices of stock options are as follows:
Options Outstanding | Options Exercisable | |||||||||||||
Weighted | Weighted | Weighted | Weighted | |||||||||||
Number of | Average | Average | Number of | Average | Average | |||||||||
Options | Years to | Exercise | Options | Years to | Exercise | |||||||||
| (thousands) |
| Expiry |
| Price |
| (thousands) |
| Expiry |
| Price | |||
$0.15 - $0.30 | 20,650 | 3.21 | $ | 0.22 | 11,208 | 2.80 | $ | 0.24 | ||||||
$0.31 - $0.50 | 3,157 | 1.58 | 0.48 | 3,158 | 1.58 | 0.48 | ||||||||
$0.51 - $0.70 | 6,450 | 0.30 | 0.69 | 6,450 | 0.30 | 0.69 | ||||||||
$0.71 - $0.90 | 50 | 0.89 | 0.71 | 50 | 0.89 | 0.71 | ||||||||
30,307 | 2.41 | $ | 0.35 | 20,866 | 1.84 | $ | 0.42 | |||||||
2021 Annual Report | 61 |
The following table summarizes information about stock options outstanding and exercisable at December 31, 2021:
December 31, 2021 | December 31, 2020 | |||||||||
Number of | Weighted | Number of | Weighted | |||||||
Options | Average | Options | Average | |||||||
| (thousands) |
| Exercise Price |
| (thousands) |
| Exercise Price | |||
Outstanding, beginning of period | 25,351 | $ | 0.38 | 27,087 | $ | 0.40 | ||||
Granted | 8,350 | 0.18 | 6,475 | 0.20 | ||||||
Forfeited | (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 | 20,866 | $ | 0.42 | 16,191 | $ | 0.42 | ||||
The fair value of the liability was calculated using the Black-Scholes valuation model. The following weighted average assumptions were used in the model for options granted in 2021 and 2020:
December 31, | December 31, | |||
| 2021 | 2020 | ||
Weighted average fair value per award ($) | 0.14 | 0.14 | ||
Volatility (%) | 104.47 | 90.43 | ||
Forfeiture rate (%) | 11.02 | 11.57 | ||
Expected life (years) | 5.00 | 5.00 | ||
Risk free interest rate (%) | 0.42 | 1.31 |
This forfeiture rate estimate is adjusted to the actual forfeiture rate. Expected volatility and expected life is based on historical information.
12. Asset Retirement Obligation
The Company’s asset retirement and abandonment obligations result from its ownership interest in oil and natural gas assets. The total asset retirement obligation is estimated based on the Company’s net ownership interest in all wells and facilities, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future periods. The Company has estimated the net present value of the asset retirement obligation to be $21.5 million as at December 31, 2021 (December 31, 2020: $20.4 million) based on an undiscounted total future liability of $24.9 million (December 31, 2020: $22.1 million). These payments are expected to be made over the next 30 years. The average discount factor, being the risk-free rate related to the liabilities, is 1.31% (December 31, 2020: 0.65%). An inflation rate of 2% (December 31, 2020: 2%) over the varying lives of the assets is used to calculate the present value of the asset retirement obligation.
62 | Questerre Energy Corporation |
The following table provides a reconciliation of the Company’s total asset retirement obligation:
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Balance, beginning of year | $ | 20,369 | $ | 19,571 | ||
Liabilities settled | (190) | (59) | ||||
Revisions due to change in discount rates & estimates | 1,069 | 756 | ||||
Accretion | 247 | 101 | ||||
Balance, end of year | $ | 21,495 | $ | 20,369 | ||
13. Credit Facility
Following a review conducted in the third quarter, the Company’s facilities with a Canadian chartered bank were renewed at $16 million. The credit facilities include a revolving operating demand facility of $16 million (“Facility A”). Facility A can be used for general corporate purposes, ongoing operations, and capital expenditures within Canada. Any borrowing under the credit facilities, with the exception of letters of credit, bears interest at the bank’s prime interest rate and an applicable basis point margin based on the ratio of debt to cash flow measured quarterly. The facilities are secured by a debenture with a first floating charge over all assets of the Company and a general assignment of books debts.
Under the terms of the credit facility, the Company has provided a covenant that it will maintain an Adjusted Working Capital Ratio greater than 1.0. The ratio is defined as current assets (excluding unrealized hedging gains and including undrawn Credit Facility A availability) to current liabilities (excluding bank debt outstanding and unrealized hedging losses). The Adjusted Working Capital Ratio at December 31, 2021 was 3.05 (2020: 2.95) and the covenant was met. At December 31, 2021, $3.4 million (December 31, 2020: $15.4 million) was drawn on Facility A with an effective average interest rate of 3.45% for 2021 (2020: 3.45%). As at December 31, 2021, the Company has outstanding letters of credit for $7.7 million (2020: $7.4 million) with the Quebec Government for abandonment costs. The letters of credit are secured by term deposits.
The following table reconciles the movement in the credit facilities during the year.
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Credit Facilities beginning of year | $ | 15,427 | $ | 16,377 | ||
Drawdown from Credit Facilities | 17,993 | 24,550 | ||||
Repayment of Credit Facilities | (30,000) | (25,500) | ||||
Credit Facilities end of year | $ | 3,420 | $ | 15,427 | ||
The credit facilities are a demand facility and can be reduced, amended or eliminated by the lender for reasons beyond the Company’s control. Should the credit facilities, in fact, be reduced or eliminated, the Company would need to seek alternative credit facilities or consider the issuance of equity to enhance its liquidity. The next scheduled review will be in the second quarter of 2022.
2021 Annual Report | 63 |
14. Share Capital
The Company is authorized to issue an unlimited number of Common Shares. The Company is also authorized to issue an unlimited number of Class “B” Common voting shares and an unlimited number of preferred shares, issuable in one or more series. At December 31, 2021, there were no Class “B” common voting shares or preferred shares outstanding.
a) Issued and outstanding – Common Shares
Number | Amount | ||||
| (thousands) |
| ($ thousands) | ||
Balance, December 31, 2019 | 427,907 | $ | 429,703 | ||
Shares returned to treasury | (391) | – | |||
Balance, December 31, 2020 | 427,516 | 429,703 | |||
Options exercised | 1,000 | 175 | |||
Balance, December 31, 2021 | 428,516 | $ | 429,878 | ||
In the first quarter of 2020, the Company returned 0.4 million unclaimed Common Shares, related to prior corporate acquisitions, to treasury for no associated monetary consideration.
b) Per share amounts
Basic and diluted net loss per share is calculated as follows:
December 31, | December 31, | |||||
(thousands, except as noted) |
| 2021 |
| 2020 | ||
Net loss | $ | (4,301) | $ | (117,623) | ||
Issued Common Shares at beginning of year | 427,516 | 427,907 | ||||
Shares returned to treasury | – | (294) | ||||
Issued on exercised of options | 518 | – | ||||
Weighted average number of Common Shares outstanding (basic) | 428,034 | 427,613 | ||||
Basic and diluted net loss per share | $ | (0.01) | $ | (0.28) | ||
Under the current stock option plan, options can be exchanged for Common Shares of the Company, or for cash at the Company’s discretion. They are considered potentially dilutive and are included in the calculation of diluted net loss per share for the period. The average market value of the Common Shares for purposes of calculating the dilutive effect of options was based on quoted market prices for the period that the options were outstanding. At December 31, 2021, 30.3 million options (December 31, 2020: 25.4 million) were excluded from the diluted weighted average number of Common Shares outstanding calculation as their effect would have been anti-dilutive.
64 | Questerre Energy Corporation |
15. Petroleum and Natural Gas Revenue
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Oil and liquids | $ | 24,058 | $ | 17,164 | ||
Natural gas | 4,413 | 3,131 | ||||
Royalty revenue | 1,933 | 1,629 | ||||
$ | 30,404 | $ | 21,924 | |||
16. Employee Salaries and Benefits
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Salaries, bonuses and other short-term benefits | $ | 1,572 | $ | 1,381 | ||
Share based compensation | 1,004 | 1,234 | ||||
$ | 2,576 | $ | 2,615 | |||
Note: Salaries are net of Canada Emergency Wage Subsidy Federal Government assistance program. | ||||||
17. Key Management Compensation
Key management includes directors and officers. The compensation paid or payable to key management is as follows:
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Salaries, bonuses, director fees and other short-term benefits | $ | 1,418 | $ | 1,397 | ||
Share based compensation | 1,098 | 1,276 | ||||
$ | 2,516 | $ | 2,673 | |||
The Company has entered into written executive employment agreements with each of the officers of the Company. Each of these written agreements provides that in the event of a change of control of the Company, each of the officers is entitled to: (i) 18 months of then applicable base salary with 24 months for the CEO; and (ii) the vesting of all options to purchase Common Shares. In the event of a change in control, all options will vest and the severance payable to key management would have been $2.1 million at December 31, 2021. This amount does not include accelerated share based compensation expense.
2021 Annual Report | 65 |
18. Supplemental Cash Flow Information
Changes in non-cash working capital are detailed below:
December 31, | December 31, | |||||
($ thousands) |
| 2021 |
| 2020 | ||
Accounts receivable | $ | (1,333) | $ | 1,185 | ||
Deposits and prepaid expenses | (114) | 62 | ||||
Accounts payable and accrued liabilities | 2,175 | (5,215) | ||||
Change in non-cash working capital | $ | 728 | $ | (3,968) | ||
Related to: | ||||||
Operating activities | $ | (176) | $ | 560 | ||
Investing activities | 904 | (4,528) | ||||
$ | 728 | $ | (3,968) | |||
Note: Change in accounts payable and accrued liabilities excludes forgiveness of debt related to Quebec Acquisition | ||||||
19. Right-of-use Assets and Lease Liabilities
a) Right-of-use assets
($ thousands) |
| Real Estate | Other |
| Total | ||||
Cost | |||||||||
Balance, January 1, 2019 | $ | 198 | $ | 25 | $ | 223 | |||
Additions | 218 | – | 218 | ||||||
Balance, December 31, 2020 | $ | 416 | $ | 25 | $ | 441 | |||
Additions (net of prior lease termination) | – | – | – | ||||||
Balance, December 31, 2021 | $ | 416 | $ | 25 | $ | 441 | |||
Accumulated Depreciation | |||||||||
Balance, January 1, 2019 | $ | 104 | $ | 4 | $ | 108 | |||
Depreciation | 80 | 5 | 85 | ||||||
Balance, December 31, 2020 | $ | 184 | $ | 9 | $ | 193 | |||
Depreciation | 48 | 5 | 53 | ||||||
Balance, December 31, 2021 | $ | 232 | $ | 14 | $ | 246 | |||
Carrying value | |||||||||
Balance, January 1, 2019 | $ | 95 | $ | 21 | $ | 116 | |||
Additions, net of depreciation | 138 | (5) | 133 | ||||||
Balance, December 31, 2020 | $ | 233 | $ | 16 | $ | 249 | |||
Additions, net of depreciation | (48) | (5) | (53) | ||||||
Balance, December 31, 2021 | $ | 185 | $ | 11 | $ | 196 | |||
66 | Questerre Energy Corporation |
b) Lease liabilities
($ thousands) | |||
Balance, January 1, 2020 | $ | 148 | |
Additional leases acquired during period | 218 | ||
Interest expense | 7 | ||
Lease payments | (118) | ||
Balance, December 31, 2020 | $ | 255 | |
Additional leases acquired during period | – | ||
Interest expense | 9 | ||
Lease payments | (57) | ||
Balance, December 31, 2021 | $ | 207 | |
Current portion | 52 | ||
Long term portion | 155 | ||
Balance, December 31, 2021 | $ | 207 | |
Amounts related to lease liabilities recognized in profit or loss are as follows: | |||
Interest expense on lease liabilities | $ | 9 | |
20. Commitments
A summary of the Company’s net commitments at December 31, 2021 follows:
($ thousands) |
| 2022 |
| 2023 |
| 2024 |
| 2025 |
| Thereafter |
| Total | ||||||
Transportation and Processing | $ | 2,977 | $ | 3,162 | $ | 2,884 | $ | 2,015 | $ | 1,240 | $ | 12,278 | ||||||
21.Related Party Transactions
The Company paid fees of $0.2 million (2020: $0.1) to a law firm where a Director of the Company is currently a partner.
2021 Annual Report | 67 |