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Altai Resources Inc. — Management Reports 2021
Apr 6, 2021
42722_rns_2021-04-06_8669267a-cb33-4ea2-91ef-e12a641ae4f7.pdf
Management Reports
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ALTAI RESOURCES INC.
MANAGEMENT'S DISCUSSION AND ANALYSIS (FORM 51-102F1) FOR THE YEAR ENDED DECEMBER 31, 2020
Dated April 6, 2021
The following management’s discussion and analysis of the financial position and results of operations (the “MD&A”) dated April 6, 2021 has been prepared by management and are based on and derived from the audited consolidated financial statements of Altai Resources Inc. (the "Company" or "Altai") for the year ended December 31, 2020 in comparison with those for the year ended December 31, 2019.
This discussion should be read in conjunction with the audited consolidated financial statements and the related notes for the year ended December 31, 2020, as well as the Company’s audited consolidated financial statements for the year ended December 31, 2019 and the related MD&A.
The audited consolidated financial statements for the year ended December 31, 2020 were audited and prepared by management in accordance with the International Financial Reporting Standards (IFRS). The audited consolidated financial statements were presented in Canadian dollars, which is both the functional and presentation currency of the Company. Figures referred to in this discussion are in Canadian dollars, unless otherwise stated.
Additional information relating to the Company is available on SEDAR at www.sedar.com and on Altai’s website at www.altairesources.com.
FORWARD LOOKING STATEMENTS
This MD&A contains forward-looking statements and assumptions respecting the Company’s strategies, future operations, commodity prices and presents certain issues, risks and uncertainties that can be expected to impact on any of such matters.
Forward-looking statements and assumptions are generally identifiable by the terminology used, such as "plan", "intend", "expect", "believe", "estimate", "should", "anticipate" and "potential" or other similar wording. By its very nature, the forward-looking statements contained in this discussion require Altai and its management to make assumptions that may not materialize or that may not be accurate. In addition, the forward-looking statements and assumptions contained in this discussion are subject to known and unknown risks and uncertainties and other factors, some of which are beyond the control of Altai, which could cause actual results, expectations, achievements or performance to differ materially.
The Company disclaims any intention or obligation to update publicly or revise any forward-looking statements if circumstances or management’s estimates or opinions should change except as required by applicable securities laws. The reader is cautioned not to place undue reliance on forward-looking statements.
COMPANY OVERVIEW
Altai Resources Inc. is a natural resource exploration and development company incorporated under the laws of the province of Ontario, and is listed on the TSX Venture Exchange under the symbol ATI.
OVERVIEW OF PROPERTIES
The Company has three natural resource properties, all in Canada. Two of the properties, both in Quebec, are still in exploration stage. Altai has 45% net working interest in an oil producing property in southern Alberta. All properties were in good standing as at December 31, 2020 and to date.
Altai’s properties are as following:-
a) the 50%-owned Malartic gold property (named “Blackcliff gold property” by the property joint-venture partner and operator) in the Val d’Or area of Quebec,
b) the 100%-owned Sorel-Trois Rivieres natural gas property, St. Lawrence Lowlands, Quebec, and c) the 45%-owned Cessford oil property in the Cessford area of southern Alberta. Canadian Natural Resources Limited is the 50% partner and operator of the property.
1) Malartic gold property, Quebec
Ownership and Location
The 50%-owned Malartic gold property (named “Blackcliff gold property” by joint-venture partner and operator, Globex Mining Enterprises Inc.) consists of six map designated claims (CDC) totalling 127.6 hectares (315 acres) in the Malartic Township, Val d’Or area, Quebec, approximately 5 km north-east of the town of Malartic and the Canadian Malartic mine which is Canada’s largest gold mine.
Access
The property is easily accessible from 0.6 km west of Malartic on Highway 117. A gravel all-season road which services the Camflo mill is followed north-west for 3.5 km and then a secondary gravel road is followed for a further 3.5 km to the shaft area.
Topography
The area is relatively flat and has been previously forested. No important streams or wetlands are found on the property.
Services
Water and power resources are available in close proximity to the property.
Regional Geology
The area is situated in the south central part of the Abitibi Greenstone Belt of the Superior Province. All the rocks are of Archean age. Alteration is of the green schist grade.
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The property is in the southern part of the Malartic group approximately 1 km north of the contact with Kewagama group sediments. Abitibi rock units strike roughly east-west but at least two phases of deformation affect the rocks of the region.
Local Geology
The rock types which underlie the property are the following; mafic lavas, tuffs, agglomerates, diorite, thin bands of peridotite, granodiorite, albitite and siliceous syenite dykes.
The property is underlain by a major fold the axis of which is oriented east-west. The northern flank dips north-east while the southern flank dips south-east. The shaft (Vinray Shaft) is situated at the nose of the fold.
The gold mineralization is hosted in a concordant folded quartzo-felspathic granophyre sill or "grey diorite" approximately 91 m (300 feet) thick which defines the nose of the fold.
The grey diorite dips 65 to 71 degrees to the north-east and is flanked on the north-east by dacites and tuffs to the south-west. The diorite can be followed for several km and the Camflo gold deposit occurs in proximity to the unit. The gold zone in the area of the shaft is traversed by east-west faults 1.22 m (4 feet) to 3.05 m (10 feet) thick.
Economic Geology
Within the limits of the property, 14 gold zones have been discovered, several of which are discontinuous lenses in the same horizon. Ten zones are considered important. These veins are zones of silification and pyritization accompanied by carbonatization and chloritization associated with faulting and brecciation with grey or green diorite or tuff.
The principal alteration minerals are epidote, biotite and magnetite. The zones are injected by veins of quartz less than 30 cm (1 foot) thick which are well mineralized by pyrite and pyrrhotite. Intensity of faulting varies from moderate to intense, and are oriented east-west at a small angle to the diorite. All the gold zones are located on the south flank of the synform second phase fold.
At the shaft area the gold zones are subvertical at surface but dip 70 degrees north at the 61 m (200 feet) level. To the east, the dip is a constant 70 degrees north to a depth of 174 m (570 feet).
Resources
The property has a drill indicated resource inventory (non NI 43-101 compliant) of 466,342 tonnes averaging 7.11 gr/tonne (513,909 tons, 0.21 oz/t) to a depth of 200 meters (600 feet).
An aeromagnetic survey on the property was carried out by Novatem on behalf of the two joint-venture partners in late June 2020. To date Altai has received maps and data of the survey. To date Altai is waiting for a work program from the Operator.
2) Sorel-Trois Rivieres natural gas property, St. Lawrence Lowlands, Quebec
a) Licences
The Company holds a 100% interest in 5 oil and gas exploration licences issued by the Quebec Government and a 15% gross production royalty in an exploration licence optioned by Altai to Talisman Energy Canada (now Repsol Canada Energy Partnership which has assigned that licence to Questerre Energy Corporation on February 1, 2020). The licences and the gross production royalty are situated in the St. Lawrence Lowlands and are referred to as the Sorel-Trois Rivieres property. Altai’s current land position for its 5 licences in the Quebec Lowlands totals 68,483 hectares (169,225 acres).
Prior to June 13, 2011 the Company held 7 oil and gas and reservoir licences totalling 114,344 hectares (282,544 acres) of land in the St. Lawrence Lowlands. The Quebec government enacted Bill 18 (2011, chapter 13) on June 13, 2011, limiting oil and gas activity within Quebec. Bill 18 is composed of two parts. The first part revoked without compensation, all exploration licences situated between the two shores of the St. Lawrence River from the westernmost tip of Anticosti Island and the Ontario border. The second part of Bill 18 exempted holders of oil and gas and reservoir exploration licences from performing the required work (a “stop the clock” provision) until the date determined by the Minister, which date was not to be later than 13 June 2014". The duration of the licences was also extended by the same period of time as the exemption. Because of Bill 18, 45,861 hectares (113,323 acres) equal to 40.11% of the Company’s 100% owned and operated exploration licences were expropriated without compensation. As a result of the expropriation, the Company took an impairment write down of $9,845,601 on the carrying value of the property ($24,547,724) by 40.11%, for the year ended December 31, 2011.
Summary of the situation concerning Quebec government policies for licences and exploration activities in the St. Lawrence Lowlands from 2010 to date
2010: Exploration work in the Quebec Lowlands halted pending the BAPE Report to be presented approximately in 2013.
2011: Bill 18 (2011, chapter 13) was enacted by the Quebec provincial legislature on June 13, 2011. Please refer to Paragraph 2 above for details.
2014: a) Bill 5 of the Quebec provincial legislature (an Act to amend the Act to limit oil and gas activities and other legislative provisions) was enacted on June 13, 2014. It allowed the Quebec Government to extend, beyond June 13, 2014, the exemption for holders of exploration licences from performing the exploration programs required by law. It also extended the suspension of the term of those licences and deferred the increase of the annual licence fees payable until the exemption was lifted.
b) The BAPE released its 4 year study concerning shale gas exploration and development for the Quebec Lowlands. The report concluded, among other things, that shale gas development did not have social acceptability and that further work should not continue in the Lowlands. As a result, any and all development programs were suspended in the Quebec Lowlands “for the time being” according to the Premier of Quebec.
2015: The Environmental Assessment Study prepared by and for the government presented its conclusions in late October 2015 and suggested various modifications to existing procedures. It suggested that some exploration work might continue, particularly regarding areas other than the Lowlands
mainly because of social acceptability.
2016: a) The document titled “Energy Policy to 2030” presented and adopted by the Quebec Government in April 2016 provides the general framework for guidance and objectives for the government on the overall policy regarding all energy sources, including oil and gas. As for hydrocarbon exploration and development, the Energy Policy states that it supports responsible development of oil and gas resources in Quebec, that a legal framework will be established and that an office will be created to oversee the Quebec energy sector including various energy projects.
b) Bill 106, “An Act to implement the Energy Policy to 2030 and amend various legislative provisions”, was passed in the Quebec National Assembly in December 2016. The Bill contains a series of modifications to existing legislation to cover the Energy Policy, including changes to the Mining Act and other Acts then in force and the creation of a new Petroleum Resources Act (the “Act”) that governs the development of petroleum resources in Quebec. The Act outlines the various general conditions and norms (including social acceptability) regarding licensing, exploration, drilling and production.
2017: On September 20, 2017, the Quebec Ministry of Energy and Natural Resources (the “Ministry”) published the draft regulations to govern oil and gas activities in the province and required for the implementation of the Act.
2018: a) On June 6, 2018, the Quebec Minister of Energy and Natural Resources announced in a press release a series of new measures regarding regulations for hydrocarbon exploration and production in Quebec including a ban on fracking in shales and various other restrictions including distances for wells and fracking. On June 20, 2018, the Ministry published the revised draft regulations incorporating all the measures announced in its June 6, 2018 press release.
b) On September 5, 2018 the Quebec Government published the Final Regulations (the “Regulations”) which include all the significant restrictions and measures published in the June 20, 2018 revised draft regulations. Both the Act and the Regulations automatically came into effect on September 20, 2018.
To date, various legal proceedings have been initiated against the Ministry regarding the Act and they are in various stages of hearings.
Altai has been in full compliance with all the requirements of the Act and the Regulations to date.
Information on the four Monitoring Committees for the Altai licences is available on our website www.altairesourcesquebec.com.
In view of the prolonged delay regarding approval of shale exploration in Quebec thereby creating uncertainty as to the future of shale gas development, the Company in December 2014 adopted a prudent approach and wrote down the project to $1 as required by accounting standards. The impairment of exploration and evaluation assets can be reversed in the future (in whole or in part) if there is evidence that the impairment no longer exists.
Based on previous exploration work, Altai considers that the property has good potential for conventional gas, gas reservoirs and storage facilities, and shale gas. Exploration for gas reservoirs is an important exploration objective for the Company.
There has been no shale gas exploration or fracture stimulation for natural gas in the Quebec Lowlands since 2010.
Total cumulative capital and exploration expenditures incurred on the natural gas interests to December 31, 2020 amounted to $24,922,441 (2019 - $24,833,707), with total cumulative write downs of $24,922,440 (2019 - $24,833,706).
b) Property Summary
The sedimentary geology of the St. Lawrence Lowlands comprises unconsolidated Quaternary sediments overlying Cambrian and Ordovician age sedimentary rocks that were deposited on the Precambrian basement or Canadian Shield. Within this sedimentary sequence several potential conventional and unconventional hydrocarbon play types have been targeted since exploration began in the late 1800s. The most recent and widely known of these is the shale gas play in the organic rich Ordovician Utica Shale. Although the Utica has been recognised as the major hydrocarbon source rock in the St. Lawrence Lowlands for some time, exploration work before 2005 (with two notable exceptions) had focused on conventional structural targets both in the hard rock and shallow unconsolidated sedimentary sequences with hydrocarbons having migrated out of the Utica over geological time. Prior to Forest Oil’s 2008 announcement of a natural gas “discovery” in the Utica, there have been two conventional producing gas fields in the province, both of which have been converted to gas storage facilities.
Given the relative success reported in shale wells drilled by the various operators of exploration licences in the immediate vicinity of the Company’s assets (Talisman, Canadian Forest Oil & Junex) since 2005, Altai recognises the need to fully evaluate its own extensive 100% owned and operated land position but has been unable to do so to date given the current situation in Quebec.
The Utica play is essentially divided into the deep (Tier 2) sector, where the base of the Utica is at 1,100 meters to 2,500 meters and the shallow (Tier 1) sector where the shale is less than 1,000 meters deep. Tiers 1 and 2 are separated by the Yamaska fault system which runs approximately north-east south-west, sub parallel to the St. Lawrence River. Before March 2011, approximately 30 wells had been successfully drilled and fracked in both Tier 1 and Tier 2 on the lands adjacent to Altai’s with several operators having produced gas to surface at quasi commercial rates from horizontal wells. The estimated Original Gas In Place (“OGIP”) of the Utica in Quebec has been variously reported as being between 90 and 153 billion cubic feet (BCF) per section (640 acres) over an area of approximately 1.5 million acres. Altai estimates that 17,400 hectares (43,000 acres) of the Company’s gross land is situated in Tier 2, and 51,083 hectares (126,225 acres) situated onshore in Tier 1. Based on both proprietary and public domain seismic and well data, Altai estimates that the Tier 2 Utica thickness is 195 - 220 meters and the Tier 1 Utica thickness is 80 - 140 meters.
In addition to the Utica shale, potential for conventional hydrocarbon resources exists in several other geological formations underlying the St. Lawrence Lowlands and in Altai’s licences.
In 2006, Talisman Energy drilled an earn-in well on an Altai Licence near St-Francois-du-Lac south of Lac Saint-Pierre. That well targeted a conventional collapsed graben structure in the Trenton / Black River (TBR) carbonates that is present on Altai’s licences for some 34 km, sub parallel to the St. Lawrence River. This type of reservoir has produced large quantities of gas and oil in Ohio, Michigan, New York State and West Virginia with a significant number of producing Hydrothermal Dolomite (HTD) gas wells having been drilled by Talisman Energy’s US subsidiary in upstate New York. Since HTD and collapsed grabens are localised structures, it is likely that the current widely spaced regional seismic coverage has ‘missed’ a few potential targets. In the development of every gas play across the continent, the use of extensive 3-D seismic in identifying optimum well locations, sweet spots and horizontal well paths has so far proven invaluable. In the case of Quebec, such data would not only improve our knowledge of the shale morphology, it would have the knock on effect of imaging previously un-imaged sections of the TBR immediately below and increase the possibility of identifying hydrocarbon reservoir structures within the TBR group.
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According to an independent consultant, the main target in Altai’s existing lands is a NE trending collapse zone 34 kilometers long averaging one kilometer in width. The zone appears as a depression at the top of Trenton formation of Ordovician age at a depth of about 750 meters. The depression may have been caused by hydrothermal dolomitization of fractured limestones (hydrothermal dolomite reservoir facies). Targets in similar geological setting along former shoreline of Cambro-Ordovician craton have produced large quantities of gas and oil in Ohio, Michigan, New York State, West Virginia and elsewhere in the Appalachians. In addition to Trenton formation, the stratigraphically lower Chazy, Beekmantown and Potsdam formations have gas showings elsewhere in the Appalachians.
Dr. Robert Theriault, formerly with the Hydrocarbons Branch, Quebec Ministry of Natural Resources, compared Altai’s deep collapse structure (referred to by him as a “sag” at the top of the Trenton Formation to the Albion-Scipio oil and gas field (“Albion-Scipio”) in the State of Michigan, USA. Albion-Scipio, also in the Trenton Formation, has produced over 130 million barrels of oil (290 million barrels of original oil in place) and 200 BCF (billion cubic feet) of natural gas since the start of its production in the late 1950s. The sag zone, 34 kilometers long and outlined in Altai’s licences, may extend for approximately another 20 kilometers towards the SW, all in Altai’s existing licences, making its physical size similar to that of Albion-Scipio. Dr. Theriault pointed out the similarity of the seismic cross section of Altai’s target with that of Albion-Scipio.
3) Cessford oil property, central Alberta
In 2012, the Company acquired a gross 50% (net 45%) working interest in 240 acres of Alberta Crown leases in the Cessford area of southern Alberta and production of approximately 12.5 barrels of light oil per day (11bopd net to Altai) in four long-life oil producing wells for a cash consideration of $800,000. 692012 Alberta Ltd. and another Calgary party (together the “Parties”) provided technical support to Altai during the acquisition process and were paid a fee in kind by Altai, that is, each of the two parties held a 2.5% working interest in the property on the transaction closing. ConocoPhillips Canada Energy Partnership of ConocoPhillips Canada Resources Corp., a fully owned subsidiary of ConocoPhillips, US, was the 50% partner and operator of the property until November 2015 when it assigned both its working interest and operatorship of the property to Canadian Natural Resources Limited (“CNRL”).
The four wells are subject to certain royalty payments.
The four wells are producing from the Glauconitic “C” pool. Reserve life of the wells is estimated at 13-15 years. However, there have been no reserve studies performed to accurately estimate the reserves of this property.
In January 2020 the Company was served with a Civil Claim by the Parties for a payment of $10,480.96 for their share of the property revenue to a certain date. The Company is defending against the Civil Claim and has counterclaimed against the Parties for certain damages. Please refer to “Subsequent Event” for further details.
OVERALL PERFORMANCE AND RESULTS OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 2020
1) For the year ended December 31, 2020, the Company earned revenue of $208,612 (2019 - $255,919), comprising of oil revenue, net of royalties, of $81,337 (2019 - $127,584) and $127,275 interest and dividend income (2019 - $128,335). Total expenses, including Cessford property production expenses of $60,158 (2019 - $58,364) and exploration expenditure of $88,734 (2019- $113,667) amounted to $322,722 (2019 - $368,645). The net loss for the year ended December 31, 2020 was $114,110 (2019 - $112,726).
2) Revenue
(1) Revenue, net of royalty expense, from the Cessford oil property for the year ended December 31, 2020 ($81,337) was lower by 36.24% to that of 2019 ($127,584).
(2) Dividend and interest income from marketable securities and bank deposit accounts were marginally lower by $1,060 (0.82%) than those for 2019 as increase in dividends from marketable securities was offset by the drop in interest income from the bank deposit and short term papers due to interest rates being brought much further down by the COVID-19 pandemic.
3) Expenses
Expenses for the years ended December 31, 2020 and 2019 are as following:
| 2020 | 2019 | |
|---|---|---|
| $ | $ | |
| Production | 60,158 | 58,364 |
| Professional fees | 54,000 | 54,000 |
| Exploration expenditures – oil and gas | 88,734 | 113,508 |
| General and administrative expenses | 59,151 | 84,536 |
| Amortization | 60,679 | 58,237 |
| 322,722 | 368,645 |
(1) Production expenses – Production costs of $60,158 for the Cessford oil property for the year ended December 31, 2020 included $10,925 legal fees on the case of civil claim served in January 2020 by the two parties holding 5% net working interests on the property (refer to Section 3 of Overview of Properties). The actual production cost for the year was $49,233 which was 15.64% lower than that of 2019 ($58,364).
(2) Professional fees – Niyazi Kacira, Chairman and President of the Company, continued to voluntarily offer to provide his professional services to the Company without any cash compensation to help the Company to reduce its expenses.
(3) Exploration expenditures-oil and gas – Expenditures were for the Sorel-Trois Rivieres gas property and included $80,601 annual rent and insurance premium expense for the five licences and $30,000 paid to a director at $2,500 per month to provide consulting service for the project since 2017. to provide consulting service for the project since 2017. The expenses were offset by $22,517 refund (without interest) by the Quebec Government for the Company’s payment of an increase in property rent for 2017-2019 charged by the Ministry in December 2018 after the Petroleum Resources Act came into effect on September 20, 2018.
(4) General and administrative expenses – included $5,200 TSX Venture exchange annual sustaining fees, $4,264 filing fees for the regulatory filing of
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the audited consolidated financial statements for the year ended December 31, 2019, $8,858 transfer agency fees, $11,771 expenses for the annual general meeting of shareholders held in August 2020, and $15,000 accrued fees for the audit of the 2020 year end consolidated financial statements.
(5) Amortization - Amortization expense of $60,679 (2019 - $58,237) was entirely for the Cessford oil property as the computer equipment became fully depreciated by 2017 year end.
SUMMARY OF QUARTERLY RESULTS
The following table presents the quarterly results for each of the last eight quarters:
| December 31, | September 30, | June 30, | March 31, | December 31, | September 30, | June 30, | March 31, | |
|---|---|---|---|---|---|---|---|---|
| 2020 | 2020 | 2020 | 2020 | 2019 | 2019 | 2019 | 2019 | |
| $ | $ | $ | $ | $ | $ | $ | $ | |
| Revenue | 55,356 | 54,884 | 39,782 | 58,590 | 69,293 | 64,392 | 70,157 | 52,077 |
| Expenses | 82,663 | 84,468 | 92,475 | 63,116 | 81,244 | 106,808 | 109,673 | 70,920 |
| Net loss | (27,307) | (29,584) | (52,693) | (4,526) | (11,951) | (42,416) | (39,516) | (18,843) |
| Net loss per share (Basic and Diluted)* |
(0.00) | (0.00) | (0.00) | (0.00) | (0.00) | (0.00) | (0.00) | (0.00) |
- For each of the quarters with net loss, the diluted weighted average number of shares used to calculate the diluted net loss per share in the period is the same as the basic weighted average number of shares as the inclusion of dilutive shares would be anti-dilutive.
1) Q1 of 2019 a) Revenue from oil production, net of royalty expense, of $20,984 was similar to that of Q4 of 2018 ($20,331), with mandatory reduction of oil production in Alberta since January 2019 in force.
b) Expenses included $8,250 expenses for the Sorel-Trois Rivieres gas property of which $7,500 was consulting fees paid to a director at $2,500 per month.
2) Q2 of 2019
a) Revenue from oil production net of royalty expense, of $37,866 was higher than that of Q1 of 2019 ($20,984) as the mandatory reduction in oil production in Alberta continued to ease in Q2 of 2019.
b) Expenses included $44,379 exploration expenses for the Sorel-Trois Rivieres gas property of which $7,500 was project consulting fees to a director and $35,258 annual rent for the 5 licences for the period of 2019-2020.
3) Q3 of 2019
- a) Revenue from oil production, net of royalty expense, of $32,015 was lower than that of Q2 of 2019 ($37,866).
b) Expenses included $52,629 exploration expenses for the Sorel-Trois Rivieres gas property of which $45,000 was premium expense for insurance policies taken out for the five licences for the period of 2019-2020 as required by the Petroleum Resources Act and $7,500 was project consulting fees to a director. General administrative expenses were lower with the Company’s continual effort to reduce administrative costs.
- 4) Q4 of 2019
a) Revenue from oil production, net of royalty expense, of $36,720 was higher than that of Q3 of 2019 ($32,015) by $4,705.
b) Expenses included $8,192 exploration expenses for the Sorel-Trois Rivieres gas property of which $7,500 was project consulting fees to a director and $15,000 fees accrued for the audit of the 2019 year-end consolidated financial statements. General administrative expenses were lower with the continual effort to reduce administrative costs of the Company.
- 5) Q1 of 2020
a) Revenue from oil production, net of royalty expense, of $26,472 was lower than that of Q4 of 2019 ($36,720) by $10,248, representing a decrease of 27.90% due to the various external economic factors adversely impacting the oil prices.
b) Expenses on production, excluding the $9,425 legal fees on the civil claim referred to in Section 3(1) of Overall Performance and Results of Operations, were $9,886. General administrative expenses continued to be maintained at a low level.
6) Q2 of 2020
a) Revenue from oil production, net of royalty expense, of $7,992 was lower than that of Q1 of 2020 ($26,472) by $18,480, being a decrease of 69.80%, due to the sharp drop in Canadian oil prices with the low oil demand because of COVID-19 and other external economic factors affecting oil prices. b) i) Expenses on oil production, $9,322 (excluding $188 legal fees on the civil claim referred to in Section 3(1) of Overall Performance and Results of Operations) were higher than the oil revenue of $8,176 by $1,147 due to the drop in the oil revenue as explained in a) above.
ii) Exploration expenses on oil and gas of $43,367 included $35,601 annual rent paid for the 5 licences, apart from $7,500 project consulting fees to a director.
iii) General and administrative expenses of $11,539 included $3,972 fees to the securities commissions for the filing of the 2019 year end financial statements and the SEDAR system fees.
- 7) Q3 of 2020
a) Revenue from oil production, net of royalty expense, of $23,244 was higher than that of Q2 of 2020 ($7,992) by $15,252, being an increase of 190.84%, as the Canadian oil prices bounced back with the COVID-19 easing off somewhat in Q3 before the second wave started and due to other external factors affecting oil prices.
b) i) Expenses for oil production of $11,258 included $2,728 mineral lease rents for 2020-2021.
ii) Exploration expenses for the Sorel-Trois Rivieres gas property of $43,367 included $45,000 insurance premium expense for the five licences for the period of 2020-2021 and $7,500 project consulting fees to a director, offset by a $22,517 refund by the Quebec Government for the increase in property rent for 2017-2019 charged by the Ministry in December 2018 after the Petroleum Resources Act came into effect on September 20, 2018..
iii) General and administrative expenses of $15,155 included $7,143 expenses for the annual shareholders meeting.
8) Q4 of 2020 a) Revenue from oil production, net of royalty expenses, of $23,629 was marginally higher than that of Q3 ($23,244) by $385 reflecting Canadian oil prices stabilizing in the second half of 2020.
b) i) Expenses for oil production of $20,078 included $2,325 property taxes for 2020-2021 for the four wells and $6,400 insurance policy premium for the project.
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ii) Exploration expenses for the Sorel-Trois Rivieres gas property of $7,726 comprised mainly of $7,500 consulting fees to the director providing consulting service for the project.
iii) General and administration expenses of $25,628 included $4,358 expenses for the annual shareholders meeting and $15,000 accrued fees for the audit of the 2020 year end consolidated financial statements.
EXPENDITURES FOR MINING PROPERTY AND OIL AND GAS INTERESTS
1) Expenditures for the resource properties for the years ended December 31, 2020 and 2019 are:
| 2020 | 2019 | |
|---|---|---|
| $ | $ | |
| Malartic gold property, Quebec | 1,618 | 1,680 |
| Sorel-Trois Rivieres gas property, Quebec | 88,734 (1) | 113,508 |
| Expenditures | 90,352 | 115,188 |
(1) Please refer to Section 3.3 of Overall Performance and Results of Operations for the year ended December 31, 2020.
2) Expenditures for revenue producing oil property
There was no capital cost or expenditure for the Cessford oil property, Alberta for the years ended December 31, 2020 and 2019.
OUTLOOK
1) As mentioned in Section 2a of Overview of Properties, no exploration work has taken place in the St. Lawrence Lowlands since 2010 when the moratorium began. The Company plans to maintain its licences in good standing until such time as exploration work can resume.
The final regulations (the “Regulations”) for the implementation of the Petroleum Resources Act (the “Act”), published on September 5, 2018, incorporated a ban on fracking in shales and various other restrictions including increased distances for wells and fracking. Both the Act and the Regulations became effective September 20, 2018. Since then, Altai has been in full compliance with all the requirements of the Act and the Regulations to date. Information on the Monitoring Committees for all Altai licences is available on our website www.altairesourcesquebec.com
Various legal proceedings have been initiated against the Ministry regarding the Act and they are in various stages of hearings.
The Company believes that its licences still present solid economic potential. Apart from Utica shales, the property also has good potential for conventional gas and gas reservoirs and storage facilities. Exploration and development of gas reservoirs is an important objective of these licences for Altai.
2) The 45% net working interest in the 240 acres Cessford property and production of light oil in four long-life wells (13-15 years) is operated by Canadian Natural Resources Limited.
Effective December 2020 the mandatory oil production reduction in Alberta, started in January 2019, was put on hold until further notice. The oil prices have stabilized since the second half of 2020 despite the ongoing COVID-19 pandemic. It remains to be seen how the net revenue from the Cessford property will be affected.
LIQUIDITY AND CAPITAL RESOURCES
- 1) The Company’s treasury funds comprise of cash and cash equivalents and marketable securities.
At the beginning of 2020, the Company’s working capital was $3.77 million comprising of $1.45 million cash and cash equivalents and $2.32 million marketable securities classified and measured at fair value through other comprehensive income. As at December 31, 2020, the Company’s working capital was $3.46 million comprising of $1.37 million cash and cash equivalents and $2.09 million marketable securities.
During 2020, the Company maintained its usual thrifty mode for the administrative and general expenses and continued to seek appropriate ways to reduce such costs.
With the bank interest rates being drastically lowered due to the impact of COVID-19, yield on the Company’s low risk bank deposit became very low. However Altai’s short-term papers for 2020 have not been adversely affected as much.
The Company’s marketable securities consists of shares of Canadian major banks and relatively stable companies which are denominated in Canadian currency and are liquid and regularly pay dividends or interests. As such, Altai’s marketable securities investment remains liquid and reasonably safe. Impacted by the coronavirus pandemic, share prices in 2020 faced gigantic fluctuations and had become much lower than in 2019. The fair market value of the portfolio has decreased during the year 2020 by $234,559 despite the slight improvement from Q2 to Q4 of the year. The dividend income stream from our marketable securities portfolio has slightly increased, but is offset by lower interest income from bank deposit. The total fair value of the marketable securities at December 31, 2020 was $2,088,865 (2019 - $2,323,424) with total cost of $1,262,798 (2019 - $1,214,017).
2) Since Altai does not have any debt nor committed capital expenditures and has liquid investment, the Company does not anticipate any liquidity issues in the next twelve months.
- 3) The Company includes the following in its capital as at December 31, 2020 and 2019:
| 2020 | 2019 | |
|---|---|---|
| Shareholders’ equity comprised of | ||
| Share capital | $ 34,003,020 | $ 34,003,020 |
| Contributed surplus | 3,238,391 | 3,238,391 |
| Deficit | (33,485,445) | (33,392,000) |
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Accumulated other comprehensive income
696,385 942,182
$ 4,452,351 $ 4,791,593
The Company’s objectives when managing capital are to:
-
(a) ensure that the Company maintains the level of capital necessary to meet the requirements of its exploration programs and current operating expenditures;
-
(b) allow the Company to respond to changes in economic and/or marketplace conditions;
(c) give shareholders sustained growth in shareholder value by increasing shareholders’ equity; and
- (d) maintain a flexible capital structure which optimizes the cost of capital at acceptable levels of risk.
The Company manages its capital structure and makes adjustments in light of variations in economic conditions and the risk characteristics of its underlying assets. The Company maintains or adjusts its capital level to enable it to meet its objectives by:
-
(a) realizing proceeds from the disposition of its investments; and
-
(b) raising capital through equity financings.
The Company is not subject to any capital requirements imposed by a regulator.
The payment of cash dividends does not form part of Altai’s current capital management program and, to date, the Company has not declared any cash dividends on its shares. The Company’s management is responsible for the management of capital. The Company expects that its current capital resources will be sufficient to discharge its liabilities for the ensuing twelve months.
SIGNIFICANT ACCOUNTING POLICIES
The preparation of the Company’s consolidated financial statements requires management to use accounting policies relevant for its industry and operations. The significant accounting policies used are presented in Note 3 to the audited consolidated financial statements for the year ended December 31, 2020.
In the process of applying the Company’s accounting policies, management has to make:
1) estimates and assumptions that affect the amounts reported in the financial statements and the accompanying notes. The estimates are based on management’s best knowledge of current events and actions that the Company may undertake in the future. Actual results could differ from those estimates; and 2) critical judgments related to the economic recoverability of the Company’s resources properties and the assumption that the Company will continue as a going concern.
SHARE CAPITAL
1) Share capital
Authorized
An unlimited number of common shares of no par value.
| Issued and outstanding common shares | No. of shares | Amount |
|---|---|---|
| Balance at December 31, 2018, December 31, 2019 and December 31, 2020 | 56,033,552 | $34,003,020 |
2) Share purchase warrants
There is no share purchase warrants outstanding at December 31, 2018 through to December 31, 2020 and to date.
3) Stock options
The 2010 Stock Option Plan permits the grant of up to 4,950,000 option shares to directors, officers and employees of the Company or of its subsidiaries. Options granted are generally exercisable for up to five years from the date of grant.
The prices of all stock options granted are greater than or equal to the closing fair market value of each common share on the days prior to the options being granted.
At December 31, 2020, there were 2,750,000 option shares available for future grants.
In 2020, the Company did not grant any stock options.
A summary of the status of the Company’s stock options as at December 31, 2020 and 2019 is presented below:
| 2020 | 2019 | |||
|---|---|---|---|---|
| Weighted | Weighted | |||
| average | average | |||
| No. of | exercise | No. of | exercise | |
| Stock options | Options | price | Options | price |
| Outstanding and exercisable at beginning of the year and at the end of theyear |
1,280,000 | $0.100 |
1,280,000 | $0.100 |
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The following table summarizes information on outstanding and exercisable stock options as at December 31, 2020:
| Number of | Remaining | ||
|---|---|---|---|
| options | Exercise | contractual | |
| outstanding and | price | life (years) | Expiry date |
| exercisable | |||
| 80,000 | $0.100 | 1.52 |
July 6, 2022 |
| 1,200,000 | $0.100 | 2.66 |
August 29, 2023 |
| 1,280,000 | $0.100 | 2.59 |
4) The Company’s share capital at December 31, 2019, December 31, 2020 and February 28, 2021 are as following:
| Issued and outstanding common shares Stock options Common shares fully diluted |
December 31, 2019 Basic Weighted average 56,033,552 56,033,552 1,280,000 - 57,313,552 56,033,552 |
December 31, 2020 Basic Weighted Average 56,033,552 56,033,552 1,280,000 - 57,313,552 56,033,552 |
February 28, 2021 Basic Weighted average 56,033,552 56,033,552 1,280,000 - 57,313,552 56,033,552 |
|---|---|---|---|
COMMITMENTS
1) In October 2010 the Company signed an agreement to pay $50,000 as termination fee to Maria Au, an officer of the Company, when her service to the Company terminates in the future.
2) The Company is committed to certain royalty payments on its oil production assets, the cost of which cannot be reasonably estimated.
RELATED PARTY TRANSACTIONS
Consulting services were provided by management personnel who are officers of the Company and companies owned by officers of the Company. The directors of the Company did not receive any cash compensation in their capacity as directors during the years ended December 31, 2020 and 2019. The remuneration of directors and officers of the Company for the years ended December 31, 2020 and 2019 are as follows:
| 2020 2019 |
|
|---|---|
| Cash compensation Fair value of stock-based compensation Total compensation Cash compensation Fair value of stock-based compensation Total compensation |
|
| Directors | $ 30,000 (1) $ - $ 30,000 $ 30,000 $ - $ 30,000 |
| Officers Niyazi Kacira – Chairman and President Maria Au – Secretary-Treasurer |
- (2) - - - - - 54,000 - 54,000 54,000 - 54,000 |
| $ 54,000 (3) $ - $ 54,000 $ 54,000 $ - $ 54,000 |
|
| Total – Directors and Officers | $ 84,000 $ - $ 84,000 $ 84,000 $ - $ 84,000 |
(1) Since October 2017, a director has been paid a monthly fee of $2,500 to provide consulting service for the Sorel-Trois Rivieres natural gas property.
(2) Niyazi Kacira, Chairman and President of the Company, voluntarily offered to provide his professional services to the Company without any cash compensation effective January 1, 2015, to help the Company to reduce its expenses.
(3) These fees have been allocated all to administrative expenses (2019 - $54,000).
The Company did not pay any other benefits, apart from the compensation reported above, to the directors and officers during the years ended December 31, 2020 and 2019.
OFF-BALANCE SHEET TRANSACTIONS
At December 31, 2020 and to date, the Company does not have any off-balance sheet arrangements.
FINANCIAL INSTRUMENTS
The Company has designated its cash and cash equivalents as fair value through profit or loss and marketable securities as available-for-sale, both of which are measured at fair value. Accounts receivable are classified as loans and receivable, which are measured at amortized cost. Accounts payable and accrued liabilities are classified as financial liabilities measured at amortized cost.
The Company is exposed in varying degrees to a number of risks arising from financial instruments. The Board of Directors has overall responsibility for the
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establishment and oversight of the Company’s risk management framework. Management’s close involvment in the operations allows for the identification of risks and variances from expectations. The Board approves and monitors the risk management process.
The types of risk exposure and the way in which such exposures are managed as follows:
(a) Credit risk
Credit risk is the risk of financial loss to the Company if counterparty to a financial instrument fails to meet its payment obligations. The Company’s exposure to credit risk includes cash and cash equivalents. The risk exposure is limited to their carrying amounts at the date of the financial position statement.
Cash and cash equivalents are maintained with financial institutions. The risk is mitigated because the financial institutions are major institutions with high credit ratings.
(b) 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 manages its liquidity risk by actively forecasting, planning, reviewing and monitoring expenditures and commitments and anticipated financial requirements.
Cash and cash equivalents on hand at December 31, 2020 and to date are expected to be sufficient to fund the Company’s ongoing operational needs for the next 12 months.
(c) Market risk
Market risk is the risk that changes in market prices, such as natural gas and mineral prices, foreign exchange rates and interest rates will affect the Company’s income. The object of market risk management is to manage and control market risk exposures within acceptable parameters, while optimizing the return on risk.
1) Commodity risk
The ability of the Company to develop its properties and the future profitability of the Company is directly related to the market price of certain minerals and oil and gas prices. The Company does not use derivative financial instruments to reduce its exposure to commodity price risk.
2) Currency risk
The Company is not exposed to the financial risk related to the fluctuation of foreign exchange rates. The Company operates mainly in Canada and all of its expenses are incurred in Canadian dollars.
3) Interest rate risk The Company is not exposed to significant interest rate risks since all of its financial instruments can be quickly turned into cash, thus avoiding additional risks.
SUBSEQUENT EVENT
To the end of February 2021, the Civil Claim referred to in Section 3 of the Overview of Properties had not yet been resolved. The Company continues to defend against the Civil Claim.
DISCLOSURE CONTROL AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
Management has established processes to provide them with sufficient knowledge to support representations that they have exercised reasonable diligence to ensure that (i) the annual financial statements and annual MD&A (the “annual filings”) for the financial year ended December 31, 2020 do not contain any untrue statement of material fact or omit to state a material fact required to be stated or that is necessary to make a statement not misleading in light of the circumstances under which it is made, for the periods covered by the annual filings, and (ii) the annual financial statements together with other financial information included in the annual filings fairly present in all material respects the financial condition, financial performance and cash flows of the Company, as of the date of and for the periods presented in the annual filings.
In contrast to the certificates required for non-venture issuers under National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings (NI 52-109), the Venture Issuer Basic Certificates filed by the Company’s President (in his capacity as an officer also performing the functions of a chief executive officer) and the Secretary-Treasurer (in her capacity as an officer also performing the functions of a chief financial officer) (together the “certifying officers”) do not include representations relating to the establishment and maintenance of disclosure controls and procedures (DC&P) and internal control over financial reporting (ICFR), as defined in NI 52-109. In particular, the certifying officers filing the certificates are not making any representations relating to the establishment and maintenance of
i) controls and other procedures designed to provide reasonable assurance that information required to be disclosed in the annual and interim filings or other reports filed or submitted under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation; and
ii) a process to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the Company’s generally accepted accounting standards (IFRS).
The Company’s certifying officers are responsible for ensuring that processes are in place to provide them with sufficient knowledge to support the representations they are making in the certificates. Investors should be aware that inherent limitations on the ability of certifying officers of a venture issuer to design and implement on a cost effective basis DC&P and ICFR as defined in NI 52-109 may result in additional risks to the quality, reliability, transparency and timeliness of the annual and interim filings and other reports provided under securities legislation.
AT20MD&A
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