CGX Energy : MDA and Financials for quarter end - September 30, 2020

Interim MD&A - Quarterly Highlights

For the three and nine month periods ended September 30, 2020

Dated: November 4, 2020

INTRODUCTION

The following Management Discussion & Analysis - Quarterly Highlights ("Quarterly Highlights") of CGX Energy Inc. (the "Company", "Corporation", or "CGX") has been prepared to provide material updates to the business operations, liquidity and capital resources of the Corporation since its management's discussion & analysis for the fiscal year ended December 31, 2019 (the "Annual MD&A"). These Quarterly Highlights do not provide a general update to the Annual MD&A, or reflect any non-material events since date of the Annual MD&A.

These Quarterly Highlights have been prepared in compliance with the requirements of section 2.2.1 of Form 51-102F1 - Management Discussion and Analysis, in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. These Quarterly Highlights should be read in conjunction with the Annual MD&A, the audited consolidated financial statements of the Company for the years ended December 31, 2019 and 2018 and the unaudited condensed interim consolidated financial statements for the three and nine month periods ended September 30, 2020 and 2019, together with the notes thereto. Results are reported in United States dollars, unless otherwise noted. In the opinion of management, all adjustments (which consist only of normal recurring adjustments) considered necessary for a fair presentation have been included. The results for the three and nine month periods ended September 30, 2020 are not necessarily indicative of the results that may be expected for any future period. Information contained herein is presented as at November 4, 2020 unless otherwise indicated.

The unaudited condensed interim consolidated financial statements for the three and nine month periods ended September 30, 2020 and 2019, have been prepared using accounting policies consistent with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board and interpretations of the IFRS Interpretations Committee. The unaudited condensed interim consolidated financial statements have been prepared in accordance with International Standard 34, Interim Financial Reporting.

For the purposes of preparing these Quarterly Highlights, management, in conjunction with the board of directors of the Company (the "Board of Directors"), considered the materiality of information. Information is considered material if: (i) such information results in, or would reasonably be expected to result in, a significant change in the market price or value of CGX's common shares ("Common Shares"); or (ii) there is a substantial likelihood that a reasonable investor would consider it important in making an investment decision; or (iii) it would significantly alter the total mix of information available to investors. Management, in conjunction with the Board of Directors, evaluated materiality with reference to all relevant circumstances, including potential market sensitivity.

ADDITIONAL INFORMATION

Additional information is accessible at the Company's websitewww.cgxenergy.comor through the Company's public filings available on SEDAR atwww.sedar.com.

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

These Quarterly Highlights contain certain statements or disclosures relating to the Company that are based on the expectations of its management as well as assumptions made by and information currently available to the Company which may constitute forward-looking statements or information ("forward-looking statements") under applicable securities laws. All such statements and disclosures, other thanthose of historical fact, which address activities, events, outcomes, results or developments that the Company anticipates or expects may, or will occur in the future (in whole or in part) should be considered forward-looking statements. In some cases, forward-looking statements can be identified by the use of the words "assume", "believe", "continue", "estimate", "expect", "forward", "future", "lead", "may", "plan", "potential", "prospect", "will", "would" and other similar words suggesting future outcomes or statements regarding an outlook.

In particular, but without limiting the foregoing, these Quarterly Highlights contains forward-looking statements pertaining to the following: the Company's exploration and development activities; expenditures; infrastructure projects, including road refurbishment and the Port and Logistics Yard (each as defined herein); the Company's leads and drilling prospects in respect of its various oil and natural gas interests; governmental and regulatory approvals and agreements; COVID-19 (as defined herein); trends in financial and commodities markets; and the Company's future performance, operations, liquidity and financial condition, including its ability to continue as a going concern.

In addition, statements relating to resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the resources described exist in the quantities predicted or estimated and can be profitably produced in the future.

The forward-looking statements contained in these Quarterly Highlights reflect several material factors and expectations and assumptions of the Company including, without limitation: prevailing and future commodity prices and currency exchange rates; prevailing and future commodity prices and currency exchange rates; applicable royalty rates and tax laws; interest rates; future well production rates and reserve volumes; operating costs, the timing of receipt of regulatory approvals; success obtained in exploration, development and production activities; anticipated timing and results of capital expenditures; the sufficiency of budgeted capital expenditures in carrying out planned activities; the timing, location and extent of future drilling operations; the state of the global, Guyanese, Surinamese and other economies; the state of the oil and natural gas exploration and production industry; the availability and cost of financing, labour and services; and ability to market crude oil and natural gas.

In particular, except where otherwise stated, the Company has assumed a continuation of existing business operations on substantially the same basis as exists at the time of these Quarterly Highlights.

The Company believes the material factors, expectations and assumptions reflected in the forward-looking statements are reasonable at this time but no assurance can be given that these factors, expectations and assumptions will prove to be correct. The forward-looking statements included in these Quarterly Highlights are not guarantees of future performance and should not be unduly relied upon. Such forward-looking 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 including, without limitation: risks associated with the onshore and offshore oil and natural gas industry in general such as operational risks in development, exploration and production; risks associated with international operations; delays or changes in plans with respect to exploration or development projects or capital expenditures; uncertainty of estimates and projections relating to reserves, resources, production, revenues, costs and expenses; risks associated with the construction, development and operations of a deep water port; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; environmental risks; competition; incorrect assessment of the value of acquisitions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; changes in legislation, including but not limited to tax laws, royalties and environmental regulations; and the effects and impacts of the COVID-19 pandemic as further described herein and supply conflicts among the Organization of Petroleum Exporting Countries and other oil producing countries over production restrictions which impact crude oil prices, resulting in increased global supply, the extent and duration of which are uncertain at this time, on the Company's business, general economic and business conditions and markets.

The forward-looking statements contained in these Quarterly Highlights are made as of the date hereof and the Company undertakes no obligations to update publicly or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Readers are cautioned that the foregoing lists of risks, uncertainties and other factors are not exhaustive. Risk and assumptions that could cause actual results to differ materially from those anticipated in these forward-looking statements are described in the Company's Annual Information Form ("AIF") for the year ended December 31, 2019, dated March 5, 2020. Although the Company has attempted to take into account important factors that could cause actual operating results to differ materially, there may be other unforeseen factors and so results may not be as anticipated, estimated or intended. The forward-looking statements are expressly qualified by this cautionary statement.

Boe Conversion

The term "boe" is used in this Quarterly Highlights. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of cubic feet to barrels is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In this MD&A we have expressed boe using the conversion standard of 6.0 Mcf: 1 bbl.

Prospective Resources

Readers should give attention to the estimates of individual classes of resources and appreciate the differing probabilities of recovery associated with each class. Estimates of remaining recoverable resources (unrisked) include Prospective Resources that have not been adjusted for risk based on the chance of discovery or the chance of development and Contingent Resources that have not been adjusted for risk based on the chance of development. It is not an estimate of volumes that may be recovered. Actual recovery is likely to be less and may be substantially less or zero.

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates, assuming their discovery and development, and may be sub-classified based on project maturity. There is no certainty that any portion of the resources will be discovered and they would be technically and economically viable to recover. If discovered, there is no certainty that any discovery will be technically or economically viable to produce any portion of the resources.

Recent Highlights

Highlights of the Company's recent activities to date include the following:

•  CRI had a pore pressure analysis of the Corentyne Kawa prospect completed by Baker Hughes in September 2020. The pore press analysis on the Demerara block was also completed in October 2020.

•  CRI contracted and completed a Quantitative Interpretation (QI)/AVO study to further high grade the prospect inventory during the second and third quarter on the Corentyne block.

•  In October 2020, CRI entered into an agreement with WesternGeco LLC for reprocessing of the 3D seismic over the Demerara Block. The reprocessing is expected to take approximately 7 months to complete and will cost approximately $1,065,000.

•  In October 2020, the Company entered into various contracts to recommence work on its Berbice Deep Water Port project. Currently, the Company is completely renovating a 3.1 km road leading from the Corentyne Highway to the port and is in the process of tendering for the construction of a bridge leading

from the Corentyne Highway to Seawell Village, which connected to the road leading to the Port Site. The Company has also entered into contracts for the relocation of utility services. The contract for the road commenced on October 18, 2020, and is expected to be completed at a cost of approximately $703,000.

•  The Company's annual and special meeting of Shareholders was held on Wednesday September 30, 2020, where each of the five nominees proposed as directors in CGX's management proxy circular dated August 17, 2020 (the "MPC") were elected as directors of the Company. The nominated directors proposed in the MPC achieved an average approval vote of 99.8% from CGX's shareholders. The detailed results of the vote are set out below:

  Nominee	Outcome of Vote	Voted	Voted (%)
  Gabriel De Alba	Approved	For: 213,216,579 Withhold: 471,125	99.8% 0.2%
  Dennis Mills	Approved	For: 213,287,666 Withhold: 400,038	99.8% 0.2%
  Suresh Narine	Approved	For: 213,118,595 Withhold: 569,109	99.7% 0.3%
  Duncan Nightingale	Approved	For: 213,202,261 Withhold: 485,443	99.8% 0.2%
  Hermann Tribukait	Approved	For: 213,205,146 Withhold: 482,558	99.8% 0.2%

•  CRI, the operator of the Corentyne Block, contracted PGS Geophysical AS ("PGS") to provide acquisition and processing of a full broadband marine 3D seismic survey over a northern segment of the

  Corentyne Block located offshore Guyana. The seismic acquisition was completed on November 2, 2019 and produced seismic data covering approximately 582 km2 of the northern portion of the Corentyne Block. PGS completed Time (PreStack Time Migration) and Depth (PreStack Depth

  Migration) processing of these data on June 5, 2020.

  •  CRI has completed a preliminary evaluation of the recently processed 3D seismic data, and has identified two potentially highly prospective large channel sand reservoir complexes. These channel complexes are interpreted to contain multiple high potential leads located in the northern region of the Corentyne Block which is located in close proximity to the Stabroek Block offshore Guyana and Block 58 offshore Suriname. The Pluma and Haimara discoveries in the Stabroek Block are located approximately 2 and 8 miles, respectively from the border of the northern region of the Corentyne Block and the Maka Central, Kwakwasi-1 and Sapakara West discoveries in Block 58 are located approximately 7, 15 and 20 miles, respectively from the border of the northern region of the Corentyne

    Block. The leads mapped in the Northern Corentyne Block are interpreted to be situated at the same geological horizons as the nearby significant discoveries already proven in the Stabroek Block and Block

    58. Also, importantly the Northern Corentyne leads are interpreted to share the same proven hydrocarbon generating basin and intervals in which the current discoveries are located. These leads are primarily stratigraphic traps composed of sandstone accumulations and deemed to be analogous to many the discoveries already proven to be successful in the Guyana basin spanning both Guyana and Suriname. The Northern Corentyne leads are in the process of being high-graded and have been mapped within the Upper Cretaceous, Santonian and Miocene intervals and are currently undergoing further analysis in order to prioritize and rank the best prospect to be drilled. The leads are located in water depths ranging from approximately 500 to 3,600 feet and are estimated to be at a drilling depth of between approximately 11,000 to 21,700 feet.

•  The current high-graded lead identified in the northern region of the Corentyne Block has been named Kawa, after the iconic Kawa Mountain which overlooks the village of Paramakatoi in the Pakaraima Mountains of Guyana. It is a Santonian level, stratigraphic trap and as previously mentioned is interpreted to be analogous to the discoveries immediately to the east on Block 58 in Suriname. Additional leads are being evaluated by the Company.

•  The Company submitted applications to the Department of Energy ("DOE"), Ministry of the Presidency and the Guyana Geology and Mines Commission ("GGMC"), in compliance with Article 4.1 of the Corentyne Petroleum Agreement, Demerara Petroleum Agreement and Berbice Petroleum Agreement and in accordance with the Petroleum Act No. 3 of 1986 and Petroleum Regulations as gazetted on July 12, 1986, to progress into the Second Renewal Period for each of the Petroleum Prospecting Licenses ("PPLs") in respect of the Corentyne, Demerara and Berbice Blocks. The DOE has officially indicated to the Company that they see no material obstacle to a favorable consideration of CGX progressing to the Second Renewal Period in respect of the Corentyne, Demerara and Berbice PPLs, provided that relinquishment details necessary for progression into the Second Renewal Period are agreed upon. The DOE has indicated that the Second Renewal Period instruments in respect of the Corentyne, Demerara and Berbice Blocks can then be finalized immediately thereafter. The Company has submitted its proposed 25% acreage relinquishments which are required on each Block to the DOE and the GGMC and is therefore awaiting the agreement of these agencies on the proposed relinquishment and the final instruments to formally move into the Second Renewal Period of all three Blocks.

•  The Company continued to strengthen its board of directors with the addition of Mr. Gabriel De Alba in January 2020.

•  On September 24, 2019, Frontera Energy Corporation ("Frontera") elected to convert the principal amount outstanding ($8,800,000) under its bridge loan facility due September 30, 2019 ("Bridge Loan III"). The principal amount outstanding under Bridge Loan III was convertible at a price of US$0.22 per share (being the US dollar equivalent of CDN$0.29, which was the closing price of the common shares of CGX prior to the December 4, 2018 announcement of the amendment to the Bridge Loan). As a result of conversion of the Bridge Loan, the Company issued 40,000,000 common shares to Frontera.

•  On September 23, 2019, the Company, through its wholly owned subsidiary CRI as the operator of the Corentyne Block under a Joint Operating Agreement with Frontera Guyana, executed a contract with PGS to provide acquisition and processing of a full broadband marine 3D seismic survey, to produce seismic data covering approximately 582 km2 of the northern portion of the Corentyne Block offshore in Guyana. The seismic acquisition commenced on October 18th, 2019 and was completed on November 2, 2019.

•  In September 2019, CRI also executed a letter of understanding ("LOU") with Rowan Rigs S.a.r.l. (the "Contractor") regarding the drilling rig contract entered into on December 14, 2018, which required the prepayment of certain costs for the use of the Ralph Coffman offshore jack-up rig. Under the terms of the LOU, the Company has agreed with the Contractor that all operational obligations under the drilling rig contract will be deferred until the parties could enter into an amended agreement. The Company and Rowan did not enter into an amended agreement by the specified date, and as such, on August 10, 2020 the amount of $1.17 million was returned to the JOA parties, of which CRI's net share is approximately $0.7 million.

•  In July 2019, CRI received an addendum to the Corentyne PA by the Government of the Cooperative Republic of Guyana, South America ("Government"). Under the addendum, CRI reversed the order of its next two commitments under the Corentyne PA so that the commitments were as follows:

  • o First Renewal Period, Phase Two (27th November 2017 to 27th November 2019)

    During phase two of the first renewal period, CRI shall complete additional seismic acquisition or seismic processing.

• o Second Renewal Period, Phase One (27th November 2019 to 27th November 2020)

  During phase one of the second renewal period, CRI shall drill one (1) exploration well.

•  On May 28, 2019, the transfers of the 33.333% interest in both the Corentyne and Demerara PA and associated PPLs to Frontera Guyana were completed. The transfers were effective May 20, 2019. As a result, on May 28, 2019, the Company received $8,500,851, being the net of the $33,333,000 signing bonus due from Frontera Guyana., less the amount of $24,832,149 of outstanding debts due to Frontera Energy Guyana Corp. from CGX.

•  On May 3, 2019, the Government approved the farm-in joint venture agreements ("JOAs") covering the two offshore PAs and associated PPLs for the Corentyne and Demerara blocks, between CRI and Frontera Guyana.

•  On March 28, 2019, CGX completed the agreement with Japan Drilling Co., Ltd. ("JDC") made on October 30, 2018, and settled all liabilities claimed by JDC from the Company arising from a cancelled drilling contract in 2015. Under the terms of the agreement, the Company paid JDC 45% of the principal amount of the funds claimed and recorded (or $6,637,537), together with interest accrued on such reduced amount in the sum of $1,266,500 (or $7,904,037 in the aggregate) as at October 30, 2018, in order to fully satisfy all liabilities. The company recorded a gain on settlement of debt of approximately $9,998,862 in the year ended December 31, 2019.

•  On March 12, 2019, the Company completed a rights offering ("Offering"). Pursuant to the Offering, the Company issued to holders of its outstanding common shares of record as at the close of business on February 11, 2019 an aggregate of 116,102,318 transferable rights (each, a "Right") to subscribe for, until March 12, 2019 ("Expiry Date"), an aggregate of 116,102,318 common shares. Each Right entitled the holder thereof to subscribe for one common share upon payment of the subscription price of Canadian dollar ("C$") C$0.25 (equivalent of approximately $0.1876) per common share prior to the Expiry Date. On March 12, 2019, the Company issued 116,102,318 common shares, the maximum number of common shares available for issuance under the terms of the Offering, based on shareholders' exercise of the basic subscription privilege and the additional subscription privilege, allocated pro-rata, for aggregate gross proceeds to the Company of C$29,025,579 (equivalent of approximately $21,779,530). Frontera provided a standby commitment in connection with the Offering ("Standby Commitment"), in which Frontera would acquire any common shares available as a result of any unexercised Rights under the Offering, such that CGX was guaranteed to issue 116,102,318 common shares in connection with the Offering. Frontera received 5-year warrants to purchase up to 15,009,026 common shares at an exercise price equal to C$0.415 per common share (a "Warrant"). Since the Offering was oversubscribed, Frontera did not acquire any additional shares under the Standby Commitment.

•  On February 7, 2019, to pay the required drilling rig minimum obligation fee of $5,340,000 (covering CRI's share of the mobilization fee, demobilization fee and 30-days of rig time charged at the stand-by rate), Frontera advanced the Company the full amount. Of this amount the Company signed a promissory note for $3,115,035 (the "Promissory Note"), being CRI's anticipated share pursuant to the terms of the Corentyne block JOA. The Promissory Note carried an interest rate of 7% per annum and matured on the earlier of the closing date of the transactions under the farm-out agreement with Frontera Guyana or May 28, 2019. The amount outstanding under the promissory note was settled on May 28, 2019.

•  On January 30, 2019, the Company amended its Bridge Loan III with Frontera to a non-revolving term facility in an amount of up to $12,939,000, provided that the facility will be automatically reduced by a payment from the Company to a maximum principal amount of $8,800,000 by May 28, 2019. On May 28, 2019 the Company settled principal of $4,139,000, plus accrued interest, of the outstanding debt now owed to Frontera. This revised term facility carried an interest rate of up to 7% per annum and matured on September 30, 2019. The $8,800,000 principal amount was convertible at the option of Frontera any time prior to maturity or repayment at a price of $0.22 per share.

UPDATE ON COVID-19

As the global coronavirus pandemic ("COVID-19") continues, CGX has continued with its plan to protect the health and safety of its employees and all stakeholders. The Company's alternative working arrangements for employees to work from home in Canada, Guyana and the USA are still in place.

The Company's operational activities are still affected due to restrictions on travel for key personnel related to operational planning, especially into and out of Guyana. The Company, which has reiterated its commitment to the resumption of operations as soon as possible, has been engaged in constructive collaborative discussions with the regulatory authorities in Guyana about the timing of its work commitments in that country, in light of these restrictions. The Company looks forward to continuing this discussion with the Government of Guyana.

The Company continues to monitor the COVID-19 related situation and will only fully resume regular activities when there are clear indications that employees are able to return to work in a safe environment and in accordance with the advice provided by regulatory authorities in all the countries with which it operates.

CORPORATE OVERVIEW AND OUTLOOK

CGX is an oil and gas exploration company headquartered in Toronto, Canada. CGX was incorporated in 1998 for the primary purpose of exploring for hydrocarbons in Guyana, South America. As at April 6, 2018, CGX holds an interest in three Petroleum Agreements (known as the Corentyne, Berbice and Demerara Blocks) covering approximately 11,005.2 km2 (approximately 7,183.0 net km2) offshore and onshore Guyana.

CGX has four direct subsidiaries: (i) CGX Resources Inc.("CRI"), a wholly-owned subsidiary, which is incorporated pursuant to the laws of Bahamas; (ii) ON Energy Inc. ("ON Energy"), a corporation subsisting under the laws of Guyana, 62% of the voting shares of which are owned by CGX; (iii) GCIE Holdings Limited ("GCIE"), a wholly-owned subsidiary, which is incorporated pursuant to the laws of Barbados and owns 100% of the shares of Grand Canal Industrial Estates Inc. ("Grand Canal"), a corporation subsisting under the laws of Guyana; and (iv) CGX Energy Management Corp. ("CGMC"), a wholly owned subsidiary, which is incorporated pursuant to the laws of the State of Delaware, USA.

Carrying on Business in Guyana

The exploration activities of CGX are currently conducted in Guyana through its subsidiaries.

Guyana is situated on the northern coast of the South American continent. It is bound on the north by the Atlantic Ocean, on the east by Suriname, on the south-west by Brazil and on the north-west by Venezuela. Guyana's total area is approximately 215,000 km2, slightly smaller than Great Britain. Its coastline is approximately 4.5 feet below sea level at high tide, while its hinterland contains mountains, forests, and savannahs. This topography has endowed Guyana with its extensive network of rivers and creeks as well as a large number of waterfalls. Guyana is endowed with natural resources including fertile agricultural land and rich mineral deposits (including gold, diamonds and semi-precious stones, bauxite and manganese).

Guyana is divided into three counties (Demerara, Essequibo and Berbice) and 10 administrative regions. Georgetown is the capital city of Guyana, the seat of government, the main commercial center, and the principal port. In addition to Georgetown, Guyana has six towns of administrative and commercial importance which are recognized municipal districts; each has its own mayor, council and civic responsibilities.

Guyana is an independent republic headed by the president and National Assembly. Guyana is a member of the British Commonwealth of Nations, with a legal system based for the most part on British Common Law.

The Petroleum Regime in Guyana

Under the Guyana Petroleum Act, PAs and associated PPLs for petroleum exploration in Guyana are executed by, and subject to the approval of, the Minister Responsible for Petroleum. Within Guyana, subsurface rights for minerals and petroleum are vested in the state. PAs may address the following matters: (i) granting of requisite licences; (ii) conditions to be included in the granting or renewal of such licences; (iii) procedure and manner with respect to the exercise of Ministerial discretion; and (iv) any matter incidental to or connected with the foregoing.

The GGMC is the statutory body responsible for administering PAs and PPLs for petroleum exploration in Guyana. The GGMC has been charged with the responsibility for managing the nation's mineral resources In order to obtain a PPL, the licencee must:

•  submit a prospecting licence application to the Minister Responsible for Petroleum, including a detailed annual work program and budget; and

•  agree to comply with licence conditions stipulated by the Minister Responsible for Petroleum, including conditions stipulated in the applicable governing PA.

A PA and an associated PPL enable the holder to conduct prospecting and exploration activities for petroleum on the subject property in accordance with the terms and conditions of such PA and PPL. A PPL is generally issued for an initial period not exceeding four years, and is renewable for up to two additional three-year periods. In the event of a discovery, the holder may apply for a 20 year PPL, renewable for a further 10 years.

CGX's PAs and PPLs

Corentyne PA and PPL

On November 27, 2012, CRI was issued a new PA and PPL for the Corentyne block offshore Guyana. On December 15, 2017, CRI was issued an addendum to the November 27, 2012 PA ("Addendum I"). Under the terms of the Addendum I, CRI's work commitments were modified and CRI relinquished 25% of the original contract area block. Effective May 20, 2019 and as at September 30, 2020 and December 31, 2019, the Corentyne PPL and PA is 66.667% owned by CRI. During the year ended December 31, 2019, CRI received an addendum to the Addendum I on the Corentyne PPL, whereby the principal agreement has now been modified as follows, with all other aspects of the Addendum I remaining unchanged:

First Renewal Period, Phase Two (27th November 2017 to 27th November 2019)

"During phase two of the first renewal period, the Company shall complete additional seismic acquisition or seismic processing."

Second Renewal Period, Phase One (27th November 2019 to 27th November 2020)

"During phase one of the second renewal period, the Company shall drill one (1) Exploration Well."

The table below outlines the commitments under the Addendum I as at September 30, 2020:

Period	Phase	Exploration Obligation	Dates
First Renewal Period - 3 Years	Phase One - 12 Months	Commence planning to drill 1 exploration well (Completed)	Nov 27, 2016 - Nov 27, 2017
- At the end of phase one of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2. (Company has commited to complete work in phase 2)
Phase Two - 24 Months	Complete additional seismic acquisition or reprocessing (Completed)	Nov 27, 2017 - Nov 27, 2019
- At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or relinquish twenty-five (25%) percent of the Contract Area and renew the Petroleum Prospecting Licence for a second period of three (3) years.
Second Renewal Period - 3 Years	Phase One - 12 Months	Drill 1 exploration well	Nov 27, 2019 - Nov 27, 2020
- At the end of phase one of the second renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2.
Phase Two - 24 Months	Drill 1 exploration well	Nov 27, 2020 - Nov 27, 2022
- At the end of the second renewal period of three (3) years, the Company shall relinquish the entire Contract Area except for any Discovery Area, the area contained in any Petroleum Production Licence and any other portion of the Contract Area on which the Minister Responsible for Petroleum agrees to permit the Company to conduct further exploration activities.

The Company has submitted its proposed 25% acreage relinquishment which is required by the Corentyne PA to the DOE and the GGMC and is awaiting the agreement from these agencies on the proposed relinquishment and final instruments to formally move into the Second Renewal Period of the PA.

Demerara PA and PPL

On February 12, 2013, CRI entered into the Demerara PPL and PA covering 3,975 km2, the same area of the former Annex PPL, which was a subset of the Company's original Corentyne PA. On December 15, 2017, CRI was issued an addendum to the February 12, 2013 PA ("Addendum II"). Under the terms of Addendum II, CRI's work commitments were modified and CRI relinquished 25% of the original contract area block, now covering 3,001.2 km2. Effective May 20, 2019 and as at September 30, 2020 and December 31, 2019, CRI held a 66.667% interest in the Demerara PPL and PA.

The table below outlines CRI's commitments under Addendum II as at September 30, 2020:

Period	Phase	Exploration Obligation	Dates
First Renewal Period - 3 Years	Phase One - 12 Months	Conduct additional data processing and planning for 1st exploration well (Conducted)	Feb 12, 2017 - Feb 12, 2018
- At the end of phase one (1) of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2. (Company has commited to complete work in phase 2)
Phase Two - 24 Months	Complete any additional processing and planning, and secure all regulatory approvals for the drilling of 1st exploration well	Feb 12, 2018 - Feb 12, 2020
- At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or relinquish twenty-five (25%) percent of the Contract Area and renew the Petroleum Prospecting Licence for a second period of three (3) years.
Second Renewal Period - 3 Years	Phase One - 12 Months	Drill 1 exploration well	Feb 12, 2020 - Feb 12, 2021
- At the end of phase one of the second renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2.
Phase Two - 24 Months	Drill 1 exploration well	Feb 12, 2021 - Feb 12, 2023
- At the end of the second renewal period of three (3) years, the Company shall relinquish the entire Contract Area except for any Discovery Area, the area contained in any Petroleum Production Licence and any other portion of the Contract Area on which the Minister Responsible for Petroleum agrees to permit the Company to conduct further exploration activities.

The Company has submitted its proposed 25% acreage relinquishment which is required by the Demerara PA to the DOE and the GGMC and is awaiting the agreement from these agencies on the proposed relinquishment and final instruments to formally move into the Second Renewal Period of the PA.

Berbice PA and PPL

On February 12, 2013, ON Energy entered into the Berbice PA and PPL covering 3,295 km2, the same area as the former Berbice PA issued on October 1, 2003, combined with the onshore portion of the

Company's former Corentyne PA. On December 15, 2017, the Company was issued an addendum to the February 12, 2013 PA ("Addendum III"). The Berbice PPL is 100% owned by ON Energy, which is owned 62% by CGX.

The table below outlines ON Energy's commitments under Addendum III as at September 30, 2020:

Period	Phase	Exploration Obligation	Dates
First Renewal Period - 3 Years	Phase One - 18 Months	Compile all relevant data, information and budgetary allocations for a geochemical survey and submit to the GGMC for approval (Completed)	Feb 12, 2017 - Aug 12, 2018
- At the end of phase one (1) of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production License or commit to the work programme in phase two (2).
Phase Two - 18 Months	(a) Complete a geochemical survey of a minimum 120 sq km (Completed) (b) Commence a seismic program defined by the geochemical survey (Completed)	Aug 12, 2018 - Feb 12, 2020
- At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or relinquish twenty-five (25%) percent of the Contract Area and renew the Petroleum Prospecting Licence for a second period of three (3) years.
Second Renewal Period - 3 Years	Phase One - 18 Months	Complete seismic program and all associated processing and interpretation	Feb 12, 2020 - Aug 12, 2021
- At the end of phase one (1) of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production License or commit to the work programme in phase two (2).
Phase Two - 18 Months	Drill 1 exploration well	Aug 12, 2021 - Feb 12, 2023
- At the end of the second renewal period of three (3) years, the Company shall relinquish the entire Contract Area except for any Discovery Area, the area contained in any Petroleum Production Licence and any other portion of the Contract Area on which the Minister Responsible for Petroleum agrees to permit the Company to conduct further exploration activities.

The Company has submitted its proposed 25% acreage relinquishment which is required by the Berbice PA to the DOE and the GGMC and is awaiting the agreement from these agencies on the proposed relinquishment and final instruments to formally move into the Second Renewal Period of the PA.

GUYANA OPERATIONS

The original Corentyne PA covered approximately 11,683 km2 under two separate PPLs. The Annex PPL (4,047 km2) was held 100%, as was the offshore portion of the Corentyne PPL (6,070 km2), while the onshore portion of the Corentyne PPL (1,566 km2) was held net 62% by CGX through ON Energy.

The original Corentyne PA was awarded to CRI in 1998, following which the Company began an active exploration program consisting of a 1,800 km seismic acquisition and preparations to drill the Eagle well. The Eagle drilling location in 2000 was 15 km within the Guyana-Suriname border. However, a border dispute between Guyana and Suriname led to the Company being forced off the Eagle location before drilling could begin. As a result of that incident, all active offshore exploration in Guyana was suspended by CGX and the other operators in the area, including Exxon and Maxus (Repsol, YPF). On September 17, 2007, the International Tribunal on the Law of the Sea ("ITLOS") awarded a maritime boundary between Guyana and Suriname. In the decision, ITLOS determined that it had the jurisdiction to decide on the merits of the dispute and that the line adopted by ITLOS to delimit the parties' continental shelf and exclusive economic zone follows an unadjusted equidistance line. The arbitration was compulsory and binding. CGX financed a significant portion of Guyana's legal expenses at a cost of $9.8 million. The decision was beneficial for CGX, as it concluded that 93% of CRI's Corentyne PPL would be in Guyana territory.

Because CRI was prevented from gaining unhindered access to a portion of the original Corentyne PPL area during the seven year resolution, the term of the contract was extended to June 2013.

In 2008, CRI was the first company to commit to acquire 3D seismic in Guyana when it acquired a 505 square kilometre 3D seismic program to enhance its interpretation of its newly defined Eagle Deepprospect, a large stratigraphic trap in the Cretaceous. The cost of the seismic program was approximately $8 million. Processing and interpretation of the 3D seismic was completed in 2009.

Based on the interpretation of the 3D seismic volume and concurrent activities on both sides of the Atlantic margin, CRI interpreted numerous prospects on the Corentyne PPL. The Eagle-1 well spudded on February 13, 2012 and was initially budgeted for 60 days of drilling, but experienced weather delays and mechanical issues which extended operations to 107 days. In May 2012, the Company completed the analyses of the results of its Eagle-1 well and was declared a dry-hole having encountering hydrocarbon shows in three formations, but the potential reservoir sands proved to be water-bearing. CGX recognized the total cost of Eagle-1 well as a dry hole expense in the financial statements for the years ended December 31, 2013 and 2012.

On November 27, 2012, CRI received a new Corentyne PA, offshore Guyana, renewable after four years for up to six additional years. The New Corentyne PA applies to the former offshore portion of the Corentyne PPL, covering 6,212 km2.

As of March 19, 2013, and effective December 31, 2012, an Independent Resources Evaluation was completed by DeGolyer and MacNaughton of Dallas, Texas, USA (the "D&M Report"). In the D&M Report, the total best estimate (P50) of Prospective Resources for six oil and gas prospects within the Corentyne PA are 779 MMbbl of oil, 743 MMbbl of condensate, 6,943 Bcf of sales gas plus 696 billion cubic feet of solution gas. If the estimate of gas resources were converted to oil on a 6:1 btu equivalence, and if the estimate of solution gas resources associated with the oil prospects were converted to sales gas assuming a 5% shrinkage, the arithmetic sum would be 2,664 MMboe. The D&M Report has been filed on CGX's website atwww.cgxenergy.com. The D&M Report was prepared in accordance with the requirements of

Section 5.9 of National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.

On December 15, 2017, CRI was issued a first addendum to the November 27, 2012 PA. Under the terms of the first addendum to the new Corentyne PA beginning November 27, 2017, the Company's work commitments were modified. At the end of the of the first renewal period on or before November 27, 2019, the Company shall relinquish the entire contract area except for any discovery area and the area contained in any PPL or relinquish twenty-five (25%) percent of the contract area and renew the PPL for a second period of three (3) years. The first addendum to the New Corentyne PA resulted in a reduction of acreage to 4,709 km2. The additional 25% relinquishment required at the end of the First Renewal Period ending on November 27, 2019 has not been adjusted in the 4,709 km2 as this relinquishment is currently subject to approval by the DOE and the GGMC.

On January 30, 2019, CRI and Frontera Guyana executed the JOAs providing for Frontera Guyana to acquire a 33.333% interest in CRI's Corentyne and Demerara PPLs and PAs, in exchange for a $33,333,000 signing bonus. Frontera Guyana agreed to pay one-third of the applicable costs plus an additional 8.333% of CRI's direct drilling costs for the initial exploratory commitment wells in the two blocks. The additional 8.333% carry provided shall be subject to a maximum gross amount (including tax and all costs) of (i) $30,000,000 for drilling the first exploratory well under the Corentyne PA and (ii) $40,000,000 for drilling the first exploratory well under the Demerara PA. On May 28, 2019, the transfers of the 33.333% interest in both the Corentyne and Demerara PPL were completed. The transfers are effective May 20, 2019.

In August 2019, CRI was issued a second addendum to the November 27, 2012 PA. Under the terms of the second addendum to the new Corentyne PA beginning November 27, 2017, the work commitments were modified where by the order of its next two commitments under the new Corentyne PA were reversed. Commencing in October 2019, a 3D seismic survey of 582 km2 was shot on the northern portion of the Corentyne PPL to image an area not previously covered by 3D seismic data adjacent to Exxon's recent Pluma and Haimara discoveries.

Berbice PA, Guyana

In 2003, CGX, through its 62% owned subsidiary ON Energy, applied for and was granted the Berbice PPL consisting of approximately 1,566.2 km2 adjacent to the Corentyne onshore PPL. On the two onshore PPLs, ON Energy completed aeromag re-interpretation, a geochemical sampling program and a 2D seismic program, to fulfill the minimum work obligations, plus drilled three dry-holes.

On February 12, 2013, the Government of Guyana issued a new Berbice PA and PPL to ON Energy, comprising the former Berbice PA and the onshore portion of the former Corentyne PPL, covering 3,295 km2. Under the terms of the new Berbice PA, during the initial period of four years, ON Energy had an obligation to conduct an airborne survey comprising a minimum of 1,000 km2 and either conduct a 2D seismic survey comprising a minimum of 100 km2 or drill one exploration well.

On December 15, 2017, the Company was issued an addendum to the February 12, 2013 PA. Under the terms of the new Berbice PA, during phase two of the first renewal period beginning on August 12, 2018, the Company will (a) complete a geochemical survey of a minimum 120 sq km and (b) commence a seismic program defined by the geochemical survey. At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire contract area except for any discovery area and the area contained in any PPL or relinquish twenty-five (25%) percent of the contract area and renew the PPL for a second period of three (3) years. The additional 25% relinquishment required at the end of the First Renewal Period ending on February 12, 2020 has not been adjusted in the Company's current acreage of 3,295 km2 as this relinquishment is currently subject to approval by the DOE and the GGMC.

The Company contracted Exploration Technologies Inc., a Houston, Texas based geochemical survey company, to conduct a geochemical survey on its Berbice PPL, onshore Guyana. The field survey started on October 27, 2018 and was completed on November 4, 2018. A total of 317 sample points and 49 blanks were taken. The survey covered a total area of approximately 391 km2. This satisfied part (a) of phase 2 of the first renewal period commitment to complete a geochemical survey of a minimum of 120 km2.

Demerara PA, Guyana

On February 12, 2013, the Government of Guyana issued the new Demerara PA and PPL to the Company. The Demerara PA and PPL applies to the former offshore portion of the Annex PPL, covering 3,000 km2, which was a subset of the Company's original Corentyne PA. Under the terms of the new Demerara PA, during the initial period of four years, CGX has an obligation to conduct a 3D seismic survey of a minimum of 1,000 km2 (completed in 2014) and to drill one exploration well.

In September 2014, the Company entered into a seismic contract with Prospector PTE. Ltd. ("Prospector") to conduct a 3,116.74 km2 3D seismic survey on the Company's 100% owned Demerara Block as part of its commitments under the Demerara PA and PPL. The aggregate cost of this seismic survey was approximately $19 million with $7 million paid to Prospector by way of issuance of 15,534,310 common shares valued at $0.49 per share, $2.5 million paid in cash thirty days after receipt of their invoice and the remainder of approximately $9.5 million payable in cash twelve months after the conclusion of the seismic survey, being December 2015. As of the date hereof, this amount remains unpaid.

On December 15, 2017, the Company was issued an addendum to the February 12, 2013 PA. Under the terms of the addendum to the Demerara PA, during phase two of the first renewal period commencing February 12, 2018, the Company will be required to complete any additional processing and planning, and secure all regulatory approvals for the drilling of first exploration well. At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire contract area except for any discovery area and the area contained in any PPL or relinquish twenty-five (25%) percent of the contract area and renew the PPL for a second period of three (3) years. The addendum to the New Demerara PA resulted in a reduction of acreage to 3,001 km2. The additional 25% relinquishment required at the end of the First Renewal Period ending on February 12, 2020 has not been adjusted in the 3,001 km2 as this relinquishment is currently subject to approval by the DOE and the GGMC.

On January 30, 2019, CRI and Frontera Guyana executed the JOAs providing for Frontera Guyana to acquire a 33.333% interest in CRI's Corentyne and Demerara PPLs and PAs, in exchange for a $33,333,000 signing bonus. Frontera Guyana agreed to pay one-third of the applicable costs plus an additional 8.333% of CRI's direct drilling costs for the initial exploratory commitment wells in the two blocks. The additional 8.333% carry provided shall be subject to a maximum gross amount (including tax and all costs) of (i) $30,000,000 for drilling the first exploratory well under the Corentyne PA and (ii) $40,000,000 for drilling the first exploratory well under the Demerara PA. On May 28, 2019, the transfers of the 33.333% interest in both the Corentyne and Demerara PPL were completed. The transfers are effective May 20, 2019.

Contractual Commitments

Further details of the Company's contractual commitments are included in the unaudited condensed interim consolidated financial statements for the three and nine month periods ended September 30, 2020 and 2019.

Deep Water Port Facility and Logistics Yard, Guyana

The Company acquired a 50 year lease in 2010 (the "Lease"), renewable for an additional term of 50 years, of approximately 55 acres of land situated close to the mouth of the Berbice River on its eastern bank (the "Leased Land"). The lease was originally acquired in 2010 by CRI and was transferred in 2012 to GCIE. The Company plans to build a deep water port on the Leased Land (the "Port"). The Company believes that the Leased Land is the most strategic for a deep water port facility servicing the oil and gas and agricultural industries in Guyana. The Company believes that the port will benefit from its proximity to the rapidly developing offshore oil and gas industry in Suriname. The Company has performed various developmental works on the site, including the installation of vertical drains and geotechnical treatment of the land, the building of access roads and the maintenance of bridges. In addition the Company has planned a phased approach to the full development of the facility and has engaged in detailed engineering design and permitting of Phase 1a of the facility. In 2020, the Company will begin the construction of Phase 1a.

CRI owns a 16 acre plot of land which is accessible to the Deep Water Port site detailed above via approximately 4.5 km of roadway, 3.2 km of which was built and will be renovated in 2020 by the Company. The plot of land has been developed by the Company as a functional, fenced logistics yard, with compacted soil, installation of geotextiles and coverage with gravel and other foundational material. The Logistics Yard is functional and will service Phase 1a of the Deep Water Port Facility until its functions are relocated to the 55 acre plot on the bank of the Berbice River at a later date.

For the three and nine month periods ended September 30, 2020, the Company incurred additions of $87,965 and $809,324 respectively (year ended December 31, 2019 - $70,903) with respect to expenditures on the logistics yard and the Deep Water Port Facility. The bulk of the monies spent in the current period were on continued planning for the Deep Water Port Facility and sea defense. A total of 167 feet (51 meters) of boulder protection was installed perpendicular to the north end of the existing Sea Defense structure to prevent high tidal currents from eroding the soil behind the start of the Sea Defense structure.

TRENDS

Financial markets may continue to be volatile in Canada in 2020, reflecting ongoing concerns about the stability of the global economy in light of the COVID-19 global pandemic. In addition, recent oil price wars between Saudi Arabia and Russia have had a significant negative impact on the price of oil. Unprecedented uncertainty in the credit markets has also led to increased difficulties in borrowing and or raising funds. The Company continues to be affected by these trends.

The future performance of the Company will depend on the exploration and development of its properties in Guyana. The Company may have difficulties raising equity for the purpose of carrying out explorationand development activities with respect to its Guyana properties, particularly without excessively diluting present shareholders of the Company. See "Risks and Uncertainties".

OVERALL PERFORMANCE

The Company has no revenues. Accordingly, its ability to ensure continuing operations is reliant on obtaining necessary financing to complete the acquisition and development of potential oil and gas properties.

The net loss and comprehensive loss for the nine month period ended September 30, 2020 was $4,180,525 ($0.02 per Common Share) as compared to net income and comprehensive income of $8,363,935 ($0.04 per Common Share) for the nine month period ended September 30, 2019. Significant changes in the Net loss for the nine-month period:

Under the terms of an agreement with JDC, the Company paid JDC 45% of the principal amount of the funds claimed and recorded (or $6,637,537), together with interest accrued on such reduced amount in the sum of $1,266,500 (or $7,904,037 in the aggregate). The Company made this payment on March 28, 2019. As a result of this agreement and subsequent payment, the company recorded a gain on settlement of debt of $Nil (2019 - $9,998,862) in the nine month period ended September 30, 2020.

As a result of the proceeds received under the JOAs relating to the Demerara PPL, the accounting value for this license would have been in a negative position of $7,600,000 on closing of the transaction. As a result, the Company recorded a reversal of the previously taken impairment in 2014 from the amount of the negative balance, being $Nil (2019 - $7,600,000) during the nine month period ended September 30, 2020.

CGX incurred a gain on revaluation of warrant liability of $841,000 (2019 - $5,529,000 loss) for the nine month period ended September 30, 2020. The warrants are recorded as a derivative liability for accounting purposes due to their exercise price being denominated in a currency other than the Company's US dollar functional currency. Warrant liability is booked based on the valuation of warrants using the Black-Scholes model. The liability varies mainly based on the number of warrants outstanding in the period, the current price of the Common Shares, the volatility used in the calculation, the expected remaining life and the remaining underlying assumptions used in the model. Increases or decreases in the value of the warrant liability result in a gain or loss on revaluation of warrant liability.

General and administrative expense was ($106,201) and $375,137 for the three and nine month periods ended September 30, 2020 respectively compared to $153,606 and $596,972 for the three and nine month periods ended September 30, 2019 respectively. The Company received a payment of $250,000 from M-I Trinidad Limited ("M-I") to cover costs incurred for storage of M-I's property since 2011.

The Company incurred stock-based compensation expenses during the nine months ended September 30, 2020 of $2,528,000, compared to $Nil for the same period in 2019. Stock-based compensation expenses are booked based on the valuation of options using the Black-Scholes model. The expense varies based on the number of options issued and/or vested in the period and the underlying assumptions used in the model.

Interest expense decreased by $1,132,356 to $427,449 for the nine months ended September 30, 2020 from $1,559,805 for the same period in 2019. These costs are lower than the prior year due to interest costs incurred on lower related party loans and trade and other payables as a result of settlement of approximately $18 million in debt owed to JDC and the repayments or conversion of all the loans by Frontera.

Foreign exchange loss for nine month period ended September 30, 2020 was $117,701 (2019 - $73,276). The loss for the period was mainly due to the weakening of the Canadian dollar on the Company's Canadian currency cash as compared to the United States dollar reporting currency.

LIQUIDITY AND FINANCIAL CONDITION

The Company's approach to managing liquidity risk is to ensure that it will have sufficient liquidity to meet liabilities when due. As at September 30, 2020, the Company had a working capital deficiency of $9,502,796 (December 31, 2019 - $5,824,100) consisting of current assets of $10,247,365 (December 31, 2019 - $16,009,455) to settle current liabilities of $19,750,161 (December 31, 2019 - $21,833,555). In order to meet its short-term and longer-term working capital and property exploration expenditure requirements, the Company will require additional financing by way of a joint venture, property sale, issuance of equity or otherewise. There can be no assurance that the Company will be successful in its efforts to arrange additional financing on terms satisfactory to the Company or at all. Please refer to "Going Concern Uncertainty and Management's Plans" for further details.

The unaudited condensed interim consolidated financial statements have been prepared in accordance with accounting principles applicable to a going concern, which assumes that the Company will be able to meet its obligations and continue its operations for its next fiscal year. Realization values may be substantially different from carrying values as shown and the Company's financial statements do not give effect to adjustments that would be necessary to the carrying values and classification of assets and liabilities should the Company be unable to continue as a going concern.

Going Concern Uncertainty and Management's Plans

The financial statements for the three and nine month periods ended September 30, 2020 and 2019 have been prepared assuming that the Company will continue as a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.

The Company has a history of operating losses and as at September 30, 2020, the Company had a working capital deficiency of $9,502,796 (December 31, 2019 - $5,824,100) and an accumulated deficit of $296,540,153 (December 31, 2019 - $292,359,628). The ability of the Company to continue as a going concern is dependent on securing additional required financing through issuing additional equity, debt instruments, sale of Company assets, obtaining payments associated with a joint venture farm-out or otherwise. Given the Company's capital commitment requirements under the Company's PPLs outlined in Note 9 to the interim consolidated financial statements, the Company will not have sufficient cash flow to meet its operating requirements for the 12 month period from the balance sheet date. While the Company has been successful in meeting its working capital requirements in the past, believes in the viability of its strategy and that the actions presently being taken will provide the best opportunity for the Company to continue as a going concern, there can be no assurances to that effect. As a result, there exist material uncertainties which cast significant doubt as to the Company's ability to continue as a going concern.

RELATED-PARTY TRANSACTIONS

The following sets out the details of the Company's related party transactions (See also Note 10 to the Financial Statements). As at September 30, 2020 and December 31, 2019, Frontera owned approximately 72.4% of the common shares of the Company.

Under IFRS, parties are considered to be related if one party has the ability to "control" (financially or by share capital) the other party or have significant influence (management) on the other party in making financial, commercial and operational decisions.

In October 2014, the Company entered into a secured bridge loan agreement (the "C$ Bridge Loan") with Frontera in the aggregate principal amount of C$7,500,000 ($6,700,000). The C$ Bridge Loan was a non-revolving term facility. The C$ Bridge Loan accrued interest at an annual rate of 5% per annum.

The activity on the C$ Bridge Loan from related party for the nine month period ended September 30, 2020 and the year ended December 31, 2019 is as follows:

September 30, 2020

December 31, 2019

Opening balance at beginning of period/year	$	-	$	6,746,322
Loss on foreign exchange	-	80,435
Accrued interest on loan from related party	-	136,745
Settled against signing bonus under JOAs	-	(6,963,502)
Total loan from related party	$	-	$	-

In March 2016, the Company entered into a secured bridge loan agreement (the "Bridge Loan I") with Frontera in the aggregate principal amount of up to $2,000,000. The Bridge Loan I was a non-revolving term facility. The Bridge Loan I accrued interest at an annual rate of 5% per annum.

The activity on the Bridge Loan I from related party for the nine month period ended September 30, 2020 and the year ended December 31, 2019 is as follows:

September 30, 2020
Opening balance at beginning of period/year	$	-	$	2,332,009
Accrued interest on loan from related party	-	41,371
Settled against signing bonus under JOAs	-	(2,373,380)
Total loan from related party	$	-	$	-

December 31, 2019

In October 2016, the Company entered into a secured bridge loan agreement (the "Bridge Loan II") with Frontera in the aggregate principal amount of up to $2,000,000. The Bridge Loan II was a non-revolving term facility. The Bridge Loan II accrued interest at an annual rate of 5% per annum.

The activity on the Bridge Loan II from related party for nine month period ended September 30, 2020 and the year ended December 31, 2019 is as follows:

September 30, 2020
Opening balance at beginning of period/year	$	-	$	2,168,366
Accrued interest on loan from related party	-	39,609
Settled against signing bonus under JOAs	-	(2,207,975)
Total loan from related party	$	-	$	-

December 31, 2019

In April 2017, the Company entered into a secured bridge loan agreement (the "Bridge Loan III") with Frontera. On February 1, 2019, the Company and Frontera amended the Bridge Loan III to a non-revolving term facility in an amount of up to $12,939,000, provided that the facility will be automatically reduced by a payment from the Company to a maximum principal amount of $8,800,000 by May 28, 2019. This revised term facility carries an interest rate of up to 7% per annum and matures on September 30, 2019. The $8,800,000 principal amount is convertible into common shares of the Company at the option of Frontera any time prior to maturity or repayment at a price of $0.22 per share. The Bridge Loan III accrued interest at an annual rate of 7% (5% prior to February 1, 2019) per annum. On September 24, 2019, Frontera elected to exercise the conversion feature and 40,000,000 common shares of the Company were issued to settle $8,800,000.

The activity on the Bridge Loan III from related party for the nine month period ended September 30, 2020 and the year ended December 31, 2019 is as follows:

September 30, 2020

December 31, 2019

Opening balance at beginning period/year

$

-

$

11,302,528

Loan from related party - 961,763 Trade and other payables and accrued interest added to

loan from related party - 712,620

Conversion component of convertible debentures

-

(169,000)Interest accretion - 169,000

Accrued interest on loan from related party - 539,355

Accrued interest added to loan from related party

-

(86,375)Settled against signing bonus under JOAs - (4,425,579)

Exercise of conversion feature - (8,800,000)

Cash payment of interest Total loan from related party

-

(204,312)

$

-

$

-The Bridge Loan III was classified as a liability, with the exception of the portion relating to the conversion feature, resulting in the carrying value of the Bridge Loan III being less than face value. The discount was accreted over the term of the Bridge Loan III utilizing the effective interest rate method at a 10% discount rate.

In November 2015, the Company entered into a convertible debenture (the "Debenture") with Frontera in the aggregate principal amount of $1,500,000. The Debenture accrues interest at an annual rate of 5% per annum and was repayable in full including all accrued interest in November 2016. This Debenture was convertible into shares of the Company at the option of Frontera at any time prior to November 15, 2016 at a price of C$0.335, which lapsed.

The activity on the Debenture from related party for the nine month period ended September 30, 2020 and the year ended December 31, 2019 is as follows:

September 30, 2020
Opening balance at beginning of period/year	$	-	$	1,747,618
Accrued interest on loan from related party	-	32,542
Settled against signing bonus under JOAs	-	(1,780,160)
Total Debenture from related party	$	-	$	-

December 31, 2019

On February 7, 2019, to pay the required drilling rig minimum obligation fee of $5,340,000 (covering the Company's share of the mobilization fee, demobilization fee and 30-days of rig time charged at the stand-by rate) Frontera advanced the Company the full amount. Of this amount the Company signed a Promissory Note for $3,115,035, being the Company's anticipated share pursuant to the terms of the JOAs.

The Promissory Note carried an interest rate of 7% per annum and matured on the earlier of the closing date of the transactions under the farm-out agreement with Frontera or May 28, 2019. On May 28, 2019, the Promissory Note principal plus accrued interest of $63,820 for a total of $3,178,855 was netted against the $33.3 million signing bonus on the JOAs.

The Bridge Loan III was secured by a pledge of the shares in the Company's wholly owned subsidiaries - CGX Resources, GCIE and GGMC. In addition, during the year ended December 31, 2017, GCIE and CGMC signed a guarantee with Frontera for the Bridge Loan III.

Farm in Partner Advances

Under the JOAs, the Company is operator on both the Corentyne and Demerara licences. As operator, the Company makes cash calls on its partner for payment of future licence expenditures. As at September 30, 2020, the Company had cash called and received $1,704,048 (December 31, 2019 - $1,701,409) in advances for future exploration on the Corentyne and Demerara licences.

In addition, as operator of the Corentyne and Demerara licences, the Company receives a fee from its partner to reimburse its indirect costs related to operating the licence. This fee is based on total expenditures under the JOAs. During the nine month period ended September 30, 2020, the Company received fees from its farm in partner of $12,252 (year ended December 31, 2019 - $348,621).

Key Management

Key management includes the Company's directors, officers and any employees with authority and responsibility for planning, directing and controlling the activities of an entity, directly or indirectly. Compensation awarded to key management included:

Nine month period ended September 30,	2020	2019
Short-term employee benefits	934,000	$	1,478,000
Share base payments	1,912,000	-
Total compensation paid to key management	2,846,000	$	1,478,000

$ $

At September 30, 2020, trade and other payables included $187,000 (December 31, 2019 - $112,000) due as a result of deferred payments of directors' fees. These amounts are unsecured, non-interest bearing and are due on demand.

RISKS AND UNCERTAINTIES

An investment in the securities of the Company is highly speculative and involves numerous and significant risks. Such investment should be undertaken only by investors whose financial resources are sufficient to enable them to assume these risks and who have no need for immediate liquidity in their investment. Prospective investors should carefully consider the risk factors that have affected, and which in the future are reasonably expected to affect, the Company and its financial position. Please refer to the section entitled "Going Concern Uncertainty and Management's Plans" herein, "Risk and Uncertainties" in the Annual MD&A, and "Risk Factors" in the AIF, available on SEDAR atwww.sedar.com.

November 4, 2020

Suresh Narine, Executive Chairman and Executive Director (Guyana)Tralisa Maraj, Chief Financial Officer

Unaudited Condensed Interim Consolidated Financial

Statements

For the three and nine month periods ended

September 30, 2020 and 2019

MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL REPORTING

The accompanying unaudited condensed interim consolidated financial statements of CGX Energy Inc. (the "Company") are the responsibility of the management and Board of Directors of the Company.

The unaudited condensed interim consolidated financial statements have been prepared by management, on behalf of the Board of Directors, in accordance with the accounting policies disclosed in the notes to the unaudited condensed interim consolidated financial statements. Where necessary, management has made informed judgments and estimates in accounting for transactions which were not complete at the statement of financial position date. In the opinion of management, the unaudited condensed interim consolidated financial statements have been prepared within acceptable limits of materiality and are in accordance with International Accounting Standard 34 Interim Financial Reporting of International Financial Reporting Standards using accounting policies consistent with International Financial Reporting Standards appropriate in the circumstances.

Management has established systems of internal control over the financial reporting process, which are designed to provide reasonable assurance that relevant and reliable financial information is produced.

The Board of Directors is responsible for reviewing and approving the unaudited condensed interim consolidated financial statements together with other financial information of the Company and for ensuring that management fulfills its financial reporting responsibilities. An Audit Committee assists the Board of Directors in fulfilling this responsibility. The Audit Committee meets with management to review the financial reporting process and the unaudited condensed interim consolidated financial statements together with other financial information of the Company. The Audit Committee reports its findings to the Board of Directors for its consideration in approving the unaudited condensed interim consolidated financial statements together with other financial information of the Company for issuance to the shareholders.

Management recognizes its responsibility for conducting the Company's affairs in compliance with established financial standards, and applicable laws and regulations, and for maintaining proper standards of conduct for its activities.

Toronto, Canada

November 4, 2020

"Suresh Narine"	"Tralisa Maraj"
Suresh Narine	Tralisa Maraj
Executive Chairman and Executive Director	Chief Financial Officer
(Guyana)

Unaudited Condensed Interim Consolidated Statements of Financial Position

(US$'s)

As at,

September 30, 2020

December 31, 2019

$	$
Assets
Current assets
Cash and cash equivalents (note 6)	10,047,354	15,821,285
Trade receivables and other assets (note 7)	200,011	188,170
Total current assets	10,247,365	16,009,455
Property, plant and equipment (note 8)	7,988,804	7,185,972
Exploration and evaluation expenditures (notes 9 and 16)	17,960,742	16,737,403
Total assets	36,196,911	39,932,830
Liabilities
Current liabilities
Trade and other payables (notes 9, 10, 11 and 16)	14,151,113	15,396,146
Farm in partner advances (note 10)	1,704,048	1,701,409
Warrant liability (note 12)	3,895,000	4,736,000
Total liabilities	19,750,161	21,833,555
Shareholders' equity
Share capital (note 13)	287,258,904	287,258,904
Reserve for share based payments (note 14)	25,727,999	23,199,999
Deficit	(296,540,153)	(292,359,628)
Total shareholders' equity	16,446,750	18,099,275
Total liabilities and shareholders' equity	36,196,911	39,932,830
Nature of operations and going concern uncertainty (note 1)
Commitments and contingencies (notes 8, 9, 10 and 16)
Subsequent event (note 16)
Approved on behalf of the Board of Directors on November 4, 2020:

("Signed" Suresh Narine) _________________________, Director Suresh Narine

("Signed" Dennis Mills) _____________________________, Director Dennis Mills

Unaudited Condensed Interim Consolidated Statements of Comprehensive Income (Loss)

(US$'s)

Three months

Nine months

For the periods ended September 30,	2020	2019	2020	2019
$	$	$	$
Operating expenses
General and administrative (recovered) (notes 8 and 10)	(106,201)	153,606	375,137	596,972
Management and consulting (note 10)	376,122	285,229	1,202,267	1,328,797
Interest expense (notes 9 and 10)	144,555	355,355	427,449	1,559,805
Professional fees	109,396	40,727	330,060	110,070
Share based payments (notes 13 and 14)	378,000	-	2,528,000	-
Shareholder information	927	4,919	53,433	37,007
Foreign exchange (gain) loss	(110,865)	156,463	117,701	73,276
(791,934)	(996,299)	(5,034,047)	(3,705,927)
Recovery of previously impaired exploration and
evaluation expenditures (note 9)	-	-	-	7,600,000
Gain on settlement of trade and other payables (note 9)	-	-	-	9,998,862
Indirect revenue from farm in partner (note 10)	(12,006)	-	12,522	-
(Loss) gain on revaluation of warrant liability (note 12)	(654,000)	(3,759,000)	841,000	(5,529,000)
Net income (loss) and comprehensive income (loss)	(1,457,940)	(4,755,299)	(4,180,525)	8,363,935
Basic net income (loss) per share	(0.01)	(0.02)	(0.02)	0.04
Diluted net income (loss) per share	(0.01)	(0.02)	(0.02)	0.04
Weighted average number of shares (000's) - basic	272,579	235,248	272,579	203,035
Weighted average number of shares (000's) - diluted	272,579	235,248	272,579	214,251

CGX Energy Inc.

Unaudited Condensed Interim Consolidated Statements of Changes in Equity (Deficit)

(US$'s)

Share Capital

Number of

Reserves

Share

based	Deficit	Total
Balance at December 31, 2018	116,102,318	$259,034,321	$21,708,131	$(301,592,073)	$ (20,849,621)
Shares issued for rights offering	116,102,318	21,779,530	-	-	21,779,530
Share issue costs	-	(428,823)	-	-	(428,823)
Warrants issued under rights offering	-	(2,259,000)	-	-	(2,259,000)
Shares issued on conversion of convertible debenture	40,000,000	8,800,000	-	-	8,800,000
Equity portion of convertible debenture	-	-	169,000	-	169,000
Transfer of contributed surplus on conversion of convertible
debenture	-	169,000	(169,000)	-	-
Share based payments	-	-	1,565,000	-	1,565,000
Shares issued on exercise of options	375,000	90,744	-	-	90,744
Transfer of contributed surplus on exercise of options	-	73,132	(73,132)	-	-
Net income and comprehensive income for the year	-	-	-	9,232,445	9,232,445
Balance at December 31, 2019	272,579,636	$287,258,904	$ 23,199,999	$ (292,359,628)
Share based payments	-	-	2,528,000	-
Net loss and comprehensive loss for the period	-	-	-	(4,180,525)
Balance at September 30, 2020	272,579,636	$287,258,904	$ 25,727,999	$ (296,540,153)
Balance at December 31, 2018	116,102,318	$259,034,321	$ 21,708,131	$ (301,592,073)
Shares issued for rights offering	116,102,318	21,779,530	-	-
Share issue costs	-	(428,823)	-	-
Warrants issued under rights offering	-	(2,259,000)	-	-
Shares issued on conversion of convertible debenture	40,000,000	8,800,000	-	-
Equity portion of convertible debenture	-	-	169,000	-
Transfer of contributed surplus on conversion of
convertible debenture	-	169,000	(169,000)	-
Net income and comprehensive income for the period	-	-	-	8,363,935
Balance at September 30, 2019	272,204,636	$287,095,028	$ 21,708,131	$ (293,228,138)

Shares Amount

$

18,099,275 2,528,000 (4,180,525)

$

16,446,750

$ (20,849,621)

21,779,530

(428,823)

(2,259,000)

8,800,000

169,000

- 8,363,935 $ 15,575,021

Unaudited Condensed Interim Consolidated Statements of Cash Flow

(US$'s)

Nine month periods ended September 30,	2020	2019
Operations	$	$
Net (loss) / income for the period	(4,180,525)	8,363,935
Adjustments to reconcile net (loss) / income for the period to cash
flow from operating activities:
Unrealized foreign exchange loss	117,701	73,276
Amortization	6,492	25,953
Share based payments	2,528,000	-
Interest accretion on trade and other payables, loans and	427,449	1,146,218
convertible debentures payable to related party
Recovery of previously impaired exploration and evaluation	-	(7,600,000)
expenditures
Gain on settlement of trade and other payables	-	(9,998,862)
(Gain) loss on revaluation of warrant liability	(841,000)	5,529,000
Net change in non-cash working capital items:
Trade receivables and other assets	(11,841)	(1,510,125)
Deferred transaction costs	-	431,500
Trade and other payables	17,408	(8,163,441)
Farm in partner advances	2,639	-
Cash flow (used in) operating activities	(1,933,677)	(11,702,546)
Financing
Proceeds from shares issued for rights offering	-	21,779,530
Share issue costs for rights offering	-	(428,823)
Proceeds from loans from related party	-	961,763
Cash flow from financing activities	-	22,312,470
Investing
Purchases of exploration and evaluation expenditures	(2,977,629)	(6,588,060)
Proceeds from disposition of exploration and evaluation expenditures	-	11,615,887
Purchases of property, plant and equipment	(744,924)	(88,318)
Cash flow (used in) provided from investing activities	(3,722,553)	4,939,509
Net (decrease) increase in cash and cash equivalents	(5,656,230)	15,549,433
Effect of exchange rate changes on cash held in foreign currencies	(117,701)	7,159
Cash and cash equivalents at beginning of period	15,821,285	2,842,455
Cash and cash equivalents at end of period	10,047,354	18,399,047
Supplementary Information
Interest paid	-	204,312
Income tax paid	-	-
Fair value of warrants issued under rights offering	-	2,259,000
Shares issued on conversion of convertible debenture	-	8,800,000
Settlement of related party debt on disposition of exploration and
evaluation expenditures	-	21,717,813
Trade and other payables related to investing activities - ending	10,507,985	11,808,886
Trade and other payables related to investing activities - opening	(12,197,875)	(9,515,645)

The accompanying notes are an integral part of these unaudited condensed interim consolidated financial statements.

General

CGX Energy Inc. ("CGX" or the "Company") is incorporated under the laws of Ontario. The Company's head office is located at 333 Bay Street, Suite 1100, Toronto, Ontario, M5H 2R2. Its principal business activity is petroleum and natural gas exploration offshore the Cooperative Republic of Guyana, South America ("Guyana").

1.

Nature of operations and going concern uncertainty

The Company is in the process of exploring and evaluating petroleum and natural gas properties in the Guyana Suriname basin in South America. The business of petroleum and natural gas exploration involves a high degree of risk and there can be no assurance that the Company's exploration programs will result in profitable operations. The amounts shown as exploration and evaluation expenditures include acquisition costs and are net of any impairment charges to date; these amounts are not necessarily representative of present or future cash flows. The recoverability of the Company's exploration and evaluation expenditures is dependent upon the discovery of economically recoverable petroleum and natural gas reserves; securing and maintaining title and beneficial interest in the properties; the ability to obtain the necessary financing to complete exploration, development and construction of processing facilities; obtaining certain government approvals and attaining profitable production or alternatively, upon the Company's ability to farm-out its interest on an advantageous basis; all of which are uncertain.

The Company has a history of operating losses and as at September 30, 2020 had a working capital deficiency of $9,502,796 (December 31, 2019 - $5,824,100) and an accumulated deficit of $296,540,153

(December 31, 2019 - $292,359,628). The ability of the Company to continue as a going concern is dependent on securing additional required financing through issuing additional equity or debt instruments, the sale of Company assets, or securing an additional joint farm-out for its Petroleum Production Licences

("PPLs"). As a result and given the Company's capital commitment requirements under the Company's PPLs outlined in note 9, the Company does not have sufficient cash flow to meet its operating requirements for the 12 month period from the statement of financial position date. While the Company has been successful in raising financing in the past and believes in the viability of its strategy and that the actions presently being taken provide the best opportunity for the Company to continue as a going concern, there can be no assurances to that effect. As a result there exist material uncertainties which cast significant doubt as to the Company's ability to continue as a going concern.

The Company's PPLs title may be subject to government licensing requirements or regulations, unregistered prior agreements, unregistered claims, and non-compliance with regulatory, environmental and social requirements.

These unaudited condensed interim consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern. Accordingly, they do not give effect to adjustments that would be necessary should the Company be unable to continue as a going concern and therefore be required to realize its assets and liquidate its liabilities and commitments in other than the normal course of business and at amounts different from those in the accompanying unaudited condensed interim consolidated financial statements. Such adjustments could be material. It is not possible to predict whether the Company will be able to raise adequate financing or to ultimately attain profitable levels of operations.

During the nine month period ended September 30, 2020, COVID-19 significantly impacted Canada, Guyana and the global economy, which impact continues after September 30, 2020 as well. If the impacts of COVID-19 continue for a significant extended period, there could be further impacts on the Company. At this time, the full potential impact of COVID-19 on the Company is unknown.

2. Basis of preparation

2.1 Statement of compliance

These unaudited condensed interim consolidated financial statements, including comparatives, have been prepared in accordance with International Accounting Standards ("IAS") 34 'Interim Financial Reporting' ("IAS 34") using accounting policies consistent with the International Financial Reporting Standards ("IFRS") issued by the International Accounting Standards Board ("IASB") and Interpretations of the International Financial Reporting Interpretations Committee ("IFRIC").

2.2 Basis of presentation

These unaudited condensed interim consolidated financial statements were authorized by the Board of Directors of the Company on October 30, 2020.

The notes herein include only significant transactions and events occurring since the Company's last fiscal year end and are not fully inclusive of all matters required to be disclosed in the annual audited consolidated financial statements. Accordingly, these unaudited condensed interim consolidated financial statements should be read in conjunction with our most recent annual financial statements for the year ended December 31, 2019.

New standards, interpretations and amendments adopted by the Company

The accounting policies adopted in the preparation of the interim consolidated financial statements are consistent with those followed in the preparation of the Company's annual consolidated financial statements for the year ended December 31, 2019, except for the adoption of new standards and interpretations effective as of January 1, 2020 outlined in note 2.4.

2.3 Use of management estimates, judgments and measurement uncertainty

The preparation of these unaudited condensed interim consolidated financial statements requires management to make judgments and estimates and form assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting years. Such estimates primarily relate to unsettled transactions and events as at the date of the unaudited condensed interim consolidated financial statements. On an ongoing basis, management evaluates its judgments and estimates in relation to assets, liabilities, revenue and expenses. Management uses historical experience and various other factors it believes to be reasonable under the given circumstances as the basis for its judgments and estimates. Actual outcomes may differ from these estimates under different assumptions and conditions. The most significant estimates relate to the valuation of exploration and evaluation expenditures, property, plant and equipment ("PP&E"), warrant liability, income tax amounts, determination of cash generating units and impairment testing, functional currency, valuation of share-based payments, and contingencies. Significant estimates and judgments made by management in the preparation of these unaudited condensed interim consolidated financial statements are outlined below:

Exploration and evaluation ("E&E") expenditures (Note 9) and PP&E (Note 8)

The application of the Company's accounting policy for exploration and evaluation expenditures requires judgement to determine whether it is probable that future economic benefits are likely, from either future exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is itself an estimation process that requires varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Company defers exploration and evaluation expenditures. The deferral policy requires management to make certain estimates and assumptions as to future events and circumstances; in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available.

2. Basis of preparation (continued)

2.3 Use of management estimates, judgments and measurement uncertainty (continued)

Exploration and evaluation ("E&E") expenditures (Note 9) and PP&E (Note 8) (continued)

If, after an expenditure is capitalised or for PP&E, information becomes available suggesting that the recovery of the expenditure or PP&E is unlikely or if an impairment of the expenditure or PP&E has incurred, the relevant capitalised amount is written off in profit or loss in the period when the new information becomes available.

Valuation of share based payments and warrant liability (Notes 12 and 13)

The Black-Scholes option pricing model is used to determine the fair value for the share based payments and warrant liability and utilizes subjective assumptions such as expected price volatility and expected life of the option or warrant. Discrepancies in these input assumptions can significantly affect the fair value estimate.

Cash generating units and impairment testing

Cash generating units ("CGU's") are identified to be the major producing fields and the wharf project at Berbice, the lowest level at which there are identifiable cash inflows that are largely independent of cash inflows of other groups of assets. The determination of CGUs requires judgment in defining a group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGUs are determined by similar geological structure, shared infrastructure, geographical proximity, commodity type, similar exposure to market risks and materiality.

At the end of each reporting period, the Corporation reviews the carrying amounts of its long-lived assets to be held and used to determine whether there is any indication that those assets have suffered an impairment loss.

If and when facts and circumstances indicate that the carrying value of an exploration and evaluation asset may exceed its recoverable amount, an impairment review is performed. For exploration and evaluation expenditures, when there are such indications, an impairment test is carried out by grouping the exploration and evaluation expenditures with property, plant and equipment CGU's to which they belong for impairment testing. The equivalent combined carrying value of the CGU's is compared against the recoverable amount of the CGU's and any resulting impairment loss is written off to net income (loss). The recoverable amount is the greater of fair value, less costs to sell, or value-in-use. Impairments of exploration and evaluation expenditures are only reversed when there is significant evidence that the impairment has been reversed, but only to the extent of what the carrying amount would have been, had no impairment been recognized.

Functional currency

The determination of the Company's functional currency requires analyzing facts that are considered primary factors, and if the result is not conclusive, the secondary factors. The analysis requires the Company to apply significant judgment since primary and secondary factors may be mixed. In determining its functional currency the Company analyzed both the primary and secondary factors, including the currency of the Company's operating costs in Canada, United States and Guyana, and sources of financing.

2. Basis of preparation (continued)

2.3 Use of management estimates, judgments and measurement uncertainty (continued)

Income taxes

The Company is subject to income, value added, withholding and other taxes. Significant judgment is required in determining the Company's provisions for taxes. There are many transactions and calculations for which the ultimate tax determination is uncertain during the ordinary course of business. The Company recognizes liabilities for anticipated tax audit issues based on estimates of whether additional taxes will be due. The determination of the Company's income, value added, withholding and other tax liabilities requires interpretation of complex laws and regulations. The Company's interpretation of taxation law as applied to transactions and activities may not coincide with the interpretation of the tax authorities. All tax related filings are subject to government audit and potential reassessment subsequent to the financial statement reporting period. Where the final tax outcome of these matters is different from the amounts that were initially recorded, such differences will impact the tax related accruals and deferred income tax provisions in the period in which such determination is made.

Contingencies

Contingent liabilities are possible obligations whose existence will be confirmed only on the occurrence or non-occurrence of uncertain future events outside the Company's control, or present obligations that are not recognized because either it is not probable that an outflow of economic benefits would be required to settle the obligation or the amount cannot be measured reliably. Contingent liabilities are not recognized but are disclosed and described in the notes to the unaudited condensed interim consolidated financial statements, including an estimate of their potential financial effect and uncertainties relating to the amount or timing of any outflow, unless the possibility of settlement is remote. In assessing loss contingencies related to any claims that may result in proceedings, the Company, with assistance from its legal counsel, evaluates the perceived merits of any such claims as well as the perceived merits of the amount of relief sought or expected to be sought.

2.4 New and revised standards and interpretations

New standards and interpretations adopted in current year

During the nine-months period ended September 30, 2020, the Company adopted a number of new IFRS standards, interpretations, amendments and improvements of existing standards. These included the amendments to IAS 1, IAS 8 and IFRS 3. These new standards and changes did not have any material impact on the Company's unaudited condensed interim consolidated financial statements:

IAS 1 - Presentation of Financial Statements ("IAS 1") and IAS 8 - Accounting Policies, Changes in Accounting Estimates and Errors ("IAS 8") were amended in October 2018 to refine the definition of materiality and clarify its characteristics. The revised definition focuses on the idea that information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements.

IFRS 3 - Business Combinations ("IFRS 3") was amended in October 2018 to clarify the definition of a business. This amended definition states that a business must include inputs and a process and clarified that the process must be substantive and the inputs and process must together significantly contribute to operating outputs. In addition it narrows the definitions of a business by focusing the definition of outputs on goods and services provided to customers and other income from ordinary activities, rather than on providing dividends or other economic benefits directly to investors or lowering costs and added a test that makes it easier to conclude that a company has acquired a group of assets, rather than a business, if the value of the assets acquired is substantially all concentrated in a single asset or group of similar assets.

3.

Capital management

The Company manages its capital structure and makes adjustments to it, based on the funds available to the Company, in order to support the acquisition, exploration and development of petroleum and natural gas properties. The Board of Directors does not establish quantitative return on capital criteria for management, but rather relies on the expertise of management to sustain future development of the business. The properties in which the Company currently has an interest are in the exploration stage and the Company's deep water project is under the initial stage of development; as such the Company is dependent on external financing to fund its activities in order to carry out the planned exploration and pay for administrative costs, the Company will spend its existing working capital and will be required to raise additional funding. Management reviews its capital management approach on an ongoing basis and believes that this approach, given the relative size of the Company, is reasonable. To effectively manage the Company's capital requirements, the Company monitors capital expenditures and general and administrative expenses. There were no changes in the Company's approach to capital management during the nine month period ended September 30, 2020 and the year ended December 31, 2019.

The Company is not subject to any capital requirements imposed by a lending institution or regulatory body, other than of the TSX Venture Exchange ("TSXV") which requires adequate working capital or financial resources of the greater of (i) $50,000 and (ii) an amount required in order to maintain operations and cover general and administrative expenses for a period of 6 months. As of September 30, 2020, and the date of these unaudited condensed interim consolidated financial statements, the Company may not be compliant with the policies of the TSXV. The impact of this violation is not known and is ultimately dependent on the discretion of the TSXV.

The Company considers its capital to be equity, which as at September 30, 2020 totaled $16,446,750 and was comprised of share capital, reserve for share based payments and deficit (December 31, 2019 - $18,099,275).

Management plans to secure any necessary future financing through a combination of the issuance of new equity, debt instruments or the sale of Company assets. There is no assurance, however, that these initiatives will be successful.

4. Financial instruments

Fair value

Cash and cash equivalents and trade receivables and other assets are measured at amortized cost which approximates fair value due to their short-term nature. Trade and other payables and farm in partner advances are measured at amortized cost which also approximates fair value due to their short-term nature.

Warrant liability is measured as fair value through profit and loss with Level two classification within the fair value hierarchy.

The fair value hierarchy has the following levels:

•  Level one includes quoted prices (unadjusted) in active markets for identical assets or liabilities.

•  Level two includes inputs that are observable other than quoted prices included in level one.

•  Level three includes inputs that are not based on observable market data.

As at September 30, 2020 and December 31, 2019, the Company does not have any financial assets measured at fair value and that require classification within the fair value hierarchy.

4. Financial instruments (continued)

These estimates are subject to and involve uncertainties and matters of significant judgment, and therefore cannot be determined with precision. Changes in assumptions could significantly affect the estimates.

A summary of the Company's risk exposures as it relates to financial instruments are reflected below:

i) Credit risk

Credit risk is the risk of loss associated with a counterparty's inability to fulfill its payment obligations. The credit risk is attributable to various financial instruments, as noted below. The credit risk is limited to the carrying value amount carried on the statement of financial position:

a) Cash and cash equivalents - Cash and cash equivalents are held mainly with major Canadian and American financial institutions in Canada and the United States and therefore the risk of loss is minimal. The Company keeps only a minimal amount of cash and cash equivalents in major Guyanese banks to pay only its current month activities.

b)Trade receivables and other assets - The Company is exposed to credit risk attributable to customers or credits from vendors. The Company does not believe that this risk is significant. (See Note 7)

The Company's maximum exposure to credit risk as at September 30, 2020 is the carrying value of cash and cash equivalents and trade receivables and other assets.

ii) Liquidity risk

The Company's approach to managing liquidity risk is to ensure that it will have sufficient liquidity to meet liabilities as they become due. As at September 30, 2020, the Company had a working capital deficiency of $9,502,796 (December 31, 2019 - $5,824,100). In order to meet its working capital and property exploration expenditures, the Company must secure further financing to ensure that those obligations are properly discharged (See Note 1). There can be no assurance that the Company will be successful in its efforts to arrange additional financing on terms satisfactory to the Company. If additional financing is raised by the issuance of shares from the treasury of the Company, control of the Company may change and shareholders may suffer additional dilution. If adequate financing is not available, the Company may be required to delay, reduce the scope of, or eliminate one or more exploration activities or relinquish rights to certain of its interests.

iii) Market risk

Market risk is the risk of loss that may arise from changes in market factors such as interest rates, foreign exchange rates, commodity prices and/or stock market movements (price risk).

a) Interest rate risk

The Company is not exposed to significant interest rate price risk due to the short-term nature of its monetary assets and liabilities. Cash not required in the short term is invested in short-term guaranteed investment certificates, as appropriate.

b)

Currency risk

The Company's exploration and evaluation activities are substantially denominated in US dollars. The Company's funds are predominantly kept in Canadian ("C$") and US dollars, with major

Canadian and US financial Institutions. As at September 30, 2020, the Company had approximately C$3,977,000 (December 31, 2019 - C$9,421,000) in Canadian dollar denominated cash deposits.

5. Sensitivity analysis

The Company's funds are mainly kept in Canadian and US dollars with major Canadian and US financial institutions. As at September 30, 2020, the Company's exposure to foreign currency balances approximate as follows:

Account

Foreign Currency

Exposure

As at September 30,

2020

2019

Cash and cash equivalents Trade and other receivables Trade and other payablesC$

$

• C $

• C $

4,000,000 100,000 (200,000)

$

10,000,000 100,000 (200,000)

$

3,900,000

$

9,900,000

Based on management's knowledge and experience of the financial markets, the Company believes it is reasonably possible over a one year period that a change of 10% in foreign exchange rates would increase/decrease net loss for the nine month period ended September 30, 2020 by C$390,000 (2019 - C$990,000).

6. Cash and cash equivalents

The balance of cash and cash equivalents at September 30, 2020, consisted of $10,022,354 (December 31, 2019 - $15,796,285) on deposit with major financial institutions and $25,000 (December 31, 2019 - $25,000) in short-term guaranteed investment certificates and fixed instruments with remaining maturities on the date of purchase of less than 90 days.

7. Trade receivables and other assets

The Company's trade receivables and other assets arise from harmonized sales tax ("HST") receivable, trade receivables and prepaid expenses. These are broken down as follows:

As at,

September 30, 2020

December 31, 2019

Trade receivables HST

$

38,955

$ 25,299

8,760 15,675

Prepaid expenses

152,296 147,196

Total trade receivables and other assets

$

200,011

$

188,170

Below is an aged analysis of the Company's trade receivables:

As at December 31,
Less than 90 days	$	2,410	$	-
Over 90 days	36,545	25,299
Total trade receivables	$	38,955	$	25,299

December 31, 2019

September 30, 2020

At September 30, 2020 and December 31, 2019, the Company anticipates full recovery of these amounts receivable and therefore no additional allowance has been recorded against these receivables. The credit risk on the receivables has been further discussed in Note 4(i). The Company holds no collateral for any receivable amounts outstanding as at September 30, 2020 and December 31, 2019.

8. Property, plant and equipment

Wharf Project (1)Logistics Yard (1)Vehicles, office furniture and fixturesComputer, software and equipment

TotalCost

As at December 31, 2018 Net additions

• $ 6,344,167 70,704

  $

  705,985 199

  $

  • 178,878 $ 44,476

  539,637 -$ 7,768,667 115,379

  As at December 31, 2019 Net additions

• $ 6,414,871 809,324

  $

  706,184 -$

  223,354 -$

  539,637 -$ 7,884,046 809,324

  As at September 30, 2020 Accumulated amortization

• $ 7,224,195

$

706,184

$

223,354

$

539,637

$ 8,693,370

As at December 31, 2018

$

Amortization (2)

• - $ -

• - $ -

• 115,953 $ 42,484

491,616 $ 607,569

48,021 90,505

As at December 31, 2019 Amortization (2)

$

• - $ -

• - $ -

• 158,437 $ 6,492

539,637

$ 698,074

- 6,492

As at September 30, 2020 Net book value

$

-$

-$

164,929

$

539,637

$

704,566

As at December 31, 2019

As at September 30, 2020

$ 6,414,871 $ 7,224,195

$ $

706,184 706,184

$ $

64,917 58,425

$ $

- -$ 7,185,972 $ 7,988,804

Notes: (1) No amortization has been recorded on these assets as they are still under construction.

(2) Amortization has been recorded within general and administrative expense in the statement of comprehensive income (loss).

The lands upon which the wharf project is located are subject to an industrial lease of State land with the Commissioner of Lands and Surveys in Guyana. The term of the lease is for a period of 50 years commencing in 2010 with an option to renew for an additional 50 years. This land is subject to annual rental commitments relating to this lease.

9. Exploration and evaluation expenditures

CorentyneBerbiceDemeraraTotal

Balance, December 31, 2018 Net additions

$ 17,881,521

13,356,008

$ 1,364,482 50,027

$ 8,643,596 799,769

$ 27,889,599

14,205,804

Proceeds on farm-out

(16,666,500)

• - (16,666,500)

  (33,333,000)

  Transaction costs related to farm-out Recovery of previously impaired exploration and evaluation expenditures

  187,500

  -187,500

  375,000

  -

• - 7,600,000

7,600,000

Balance, December 31, 2019 Net additions

Balance, September 30, 2020

$ 14,758,529 562,764 $ 15,321,293

$ 1,414,509 53,100 $ 1,467,609

$

• 564,365 $ 16,737,403

• 607,475 1,223,339

$ 1,171,840

$ 17,960,742

As at September 30, 2020 and December 31, 2019, the expenditures capitalized above include costs for licence acquisitions and maintenance of licences, general exploration, geological and geophysical consulting, surveys, 3D-seismic acquisition, processing and interpretation, drill planning and well exploration costs.

9. Exploration and evaluation expenditures (continued)

The Company's exploration activities are subject to government laws and regulations, including tax laws and laws and regulations governing the protection of the environment. The Company believes that its operations comply in all material respects with all applicable past and present laws and regulations. The Company records provisions for any identified obligations, based on management's estimate at the time. Such estimates are, however, subject to changes in laws and regulations.

Corentyne PA, Guyana

The Company's 100% owned subsidiary, CGX Resources Inc. ("CGX Resources"), was granted the Corentyne Petroleum Agreement ("PA") on June 24, 1998. On November 27, 2012, the Company was issued a new PA and PPL offshore Guyana. On December 15, 2017, the Company was issued an addendum to the November 27, 2012 PA ("Addendum I"). Under the terms of the Addendum I, the Company's work commitments were modified and the Company relinquished 25% of the original contract area block. Effective May 20, 2019 and as at September 30, 2020 and December 31, 2019, the Corentyne PPL and PA is 66.667% owned by the Company. During the year ended December 31, 2019, the Company received an addendum to the Addendum I on the Corentyne PPL, whereby the principal agreement has now been modified as follows, with all other aspects of the Addendum I remaining unchanged:

First Renewal Period, Phase Two (27th November 2017 to 27th November 2019)

"During phase two of the first renewal period, the Company shall complete additional seismic acquisition or seismic processing."

Second Renewal Period, Phase One (27th November 2019 to 27th November 2020)

"During phase one of the second renewal period, the Company shall drill one (1) exploration well."

The table below outlines the commitments under the Addendum I as at September 30, 2020:

Period	Phase	Exploration Obligation	Dates
First Renewal Period - 3 Years	Phase One - 12 Months	Commence planning to drill 1 exploration well (Completed)	Nov 27, 2016 - Nov 27, 2017
- At the end of phase one of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2. (Company has commited to complete work in phase 2)
Phase Two - 24 Months	Complete additional seismic acquisition or reprocessing (Completed)	Nov 27, 2017 - Nov 27, 2019
- At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or relinquish twenty-five (25%) percent of the Contract Area and renew the Petroleum Prospecting Licence for a second period of three (3) years.
Second Renewal Period - 3 Years	Phase One - 12 Months	Drill 1 exploration well	Nov 27, 2019 - Nov 27, 2020
- At the end of phase one of the second renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2.
Phase Two - 24 Months	Drill 1 exploration well	Nov 27, 2020 - Nov 27, 2022
- At the end of the second renewal period of three (3) years, the Company shall relinquish the entire Contract Area except for any Discovery Area, the area contained in any Petroleum Production Licence and any other portion of the Contract Area on which the Minister Responsible for Petroleum agrees to permit the Company to conduct further exploration activities.

9. Exploration and evaluation expenditures (continued)

Corentyne PA, Guyana (continued)

The Company has submitted its proposed 25% acreage relinquishment which are required by the Corentyne PA to the Department of Energy ("DOE") and the Guyana Geology and Mines Commission ("GGMC") and is now awaiting the agreement of these agencies on the acceptance of the proposed relinquishment and final instruments to formally move into the second renewal period of the Corentyne PA.

If a discovery is made, the Company has the right to apply to the Minister for a Petroleum Production Licence with respect to that portion of the contract area having a significant discovery.

After commercial production begins, the Company is allowed to recover contract costs as defined in the PA from "cost oil" produced and sold from the contract area and limited in any month to an amount which equals seventy-five percent (75%) of the total production from the contract area for such month excluding any crude oil and/or natural gas used in petroleum operations or which is lost. The Company's share of the remaining production or "profit oil" is 47%.

To the extent that in any month recoverable contract costs exceed the value of cost oil and/or cost gas, the unrecoverable amount shall be carried forward and shall be recoverable in the immediately succeeding month, and to the extent not then recovered, in the subsequent month or months.

The Company has $155,000,000 of recoverable contract costs brought forward from the original Corentyne licence. This cost can be recovered against any future commercial production.

Annual rental fees of $100,000 and training fees of $100,000 are required to be paid under the PA.

Farm-in agreement

In December 2018, the Company and Frontera Energy Corporation ("Frontera") entered into a letter of intent, whereby a Frontera subsidiary and the Company, were to enter into Joint Operating Agreements (the "JOAs") covering the Company's two shallow water offshore Petroleum Prospecting Licenses in Guyana, the Corentyne and Demerara PPLs and PAs.

On January 30, 2019, the Company and Frontera Energy Guyana Corp. ("Frontera Guyana") executed the JOAs, subject to amendments as agreed upon by both parties. The JOAs provided for a transfer of a 33.333% interest in both Corentyne and Demerara Petroleum Prospecting Licences to Frontera Guyana in exchange for a $33,333,000 signing bonus. Under the JOAs, Frontera Energy Guyana Corp. would pay one-third of the applicable costs plus an additional 8.333% of the Company's direct drilling costs for the initial exploratory commitment wells in the two blocks. The additional 8.333% carry provided shall be subject to a maximum gross amount (including tax and all costs) of (i) $30,000,000 for drilling the first exploratory well under the Corentyne PA and (ii) $40,000,000 for drilling the first exploratory well under the Demerara PA. The Company will be the operator.

On May 28, 2019, the transfers of the 33.333% interest in both the Corentyne and Demerara Prospecting Licences were completed. The transfers are effective May 20, 2019. As a result, on May 28, 2019, the Company received $8,500,851 on closing, being the net of the $33,333,000 signing bonus due from Frontera Energy Guyana Corp., less the amount of $24,832,149 of outstanding debts due to Frontera Energy Guyana Corp. by the Company.

The JOAs do not meet the definition of a joint venture under IFRS 11 Joint Arrangements ("IFRS 11") and have thus been accounted for as joint operations in accordance with IFRS 11. The JOAs do not have any assets or liabilities aside from the exploration and evaluation expenditures asset.

9. Exploration and evaluation expenditures (continued)

Corentyne PA, Guyana (continued)

Settlement agreements

In 2014, the Company entered into a definitive rig agreement with Japan Drilling Co., Ltd. ("JDC") ("Drilling Agreement"), and a rig sharing agreement (the "Rig Sharing Agreement") with JDC and Teikoku Oil (Suriname) Co., Ltd. ("INPEX") for the shared use of JDC's HAKURYU-12 drilling rig (the "Rig"). This Rig was intended to be used for the first commitment well that is required under the Corentyne PPL. During the year ended December 31, 2015, the Company terminated these agreements.

Upon termination of the Drilling Agreement, the total amount payable to JDC was approximately $20.35 million (the "JDC Payable"). Pursuant to the terms of the definitive agreement entered into with JDC with an effective date of November 30, 2015, the JDC Payable was to be paid as follows: (i) $5.5 million payable in common shares; (ii) $500,000 on or before December 1, 2015; (iii) approximately $7.18 million on or before March 25, 2016; and (iv) approximately $7.18 million on or before June 15, 2016. During the year ended December 31, 2016, JDC was issued 16,522,500 common shares at a price of C$0.44 per share as per the terms of the definitive agreement.

Per the definitive agreement, the payments not paid in full, totaling $14.76 million, incur interest at a rate of 8% per annum.

In October 2018, the Company entered into an agreement with JDC to settle all liabilities claimed by JDC under the JDC Payable, by proposing to pay JDC 45% of the principal amount of the funds claimed and recorded (or $6,637,537), together with interest accrued on such reduced amount in the sum of $1,266,500 (or $7,904,037 in the aggregate), in order to fully satisfy all liabilities.

The completion of this transaction was conditional on the Company successfully completing a financing, which condition may be waived by the Company. The agreement between JDC and the Company would have terminated if the closing of the transaction was not completed on or before March 31, 2019. On March 28, 2019, the Company made the agreed settlement payment of $7,904,037 and as a result recorded a gain on settlement of trade and other payables of $9,998,862 during the nine month period ended September 30, 2019.

Under the Rig Sharing Agreement, the Company owed approximately $2.9 million to INPEX for shared costs incurred in the utilization of the Rig. INPEX agreed to allow the Company to defer payment until December 1, 2015.In accordance with the Rig Sharing Agreement, since the amount was not paid in full by December 1, 2015, amounts outstanding shall accrue interest at a rate of Libor plus 7% per annum. During the year ended December 31, 2018, Frontera in a transaction separate from the Company purchased the rights to the amounts owing to INPEX by the Company directly from INPEX. On May 28, 2019, this amount including all accrued interest and other assumed payables for a total of $3,902,698 was settled as partial payment for the signing bonus under the JOAs.

Rig agreement

During the year ended December 31, 2019, the Company on behalf of the JOA executed a letter of understanding ("LOU") with Rowan Rigs S.a.r.l. ("Rowan") regarding the drilling rig contract entered into on December 14, 2018, which required the prepayment of certain costs for the use of the Ralph Coffman offshore jack-up rig. Under the terms of the LOU, the Company and Rowan agreed that all operational obligations under the drilling rig contract were deferred until the parties could enter into an amended agreement. The Company and Rowan did not enter into an amended agreement by the specified date, and as such, on August 10, 2020 the amount of $1.17 million was returned to the JOA parties, of which, the Company's net share was $0.7 million.

9. Exploration and evaluation expenditures (continued)

Berbice PA, Guyana

The Company, through its 62% owned subsidiary ON Energy Inc., acquired the Berbice PA in October 2003. The Berbice PA was renewable for up to two three-year periods.

On February 12, 2013, the Company entered into a new Berbice PA and PPL, which applies to the former Berbice licence and the former onshore portion of the Company's original Corentyne PA. On December 15, 2017, the Company was issued an addendum to the February 12, 2013 PA ("Addendum II"). Under the terms of the Addendum II, the Company's work commitments were modified.

The table below outlines the commitments under the Addendum II as at September 30, 2020:

Period	Phase	Exploration Obligation	Dates
First Renewal Period - 3 Years	Phase One - 18 Months	Compile all relevant data, information and budgetary allocations for a geochemical survey and submit to the GGMC for approval (Completed)	Feb 12, 2017 - Aug 12, 2018
- At the end of phase one (1) of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production License or commit to the work programme in phase two (2).
Phase Two - 18 Months	(a) Complete a geochemical survey of a minimum 120 sq km (Completed) (b) Commence a seismic program defined by the geochemical survey (Completed)	Aug 12, 2018 - Feb 12, 2020
- At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or relinquish twenty-five (25%) percent of the Contract Area and renew the Petroleum Prospecting Licence for a second period of three (3) years.
Second Renewal Period - 3 Years	Phase One - 18 Months	Complete seismic program and all associated processing and interpretation	Feb 12, 2020 - Aug 12, 2021
- At the end of phase one (1) of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production License or commit to the work programme in phase two (2).
Phase Two - 18 Months	Drill 1 exploration well	Aug 12, 2021 - Feb 12, 2023
- At the end of the second renewal period of three (3) years, the Company shall relinquish the entire Contract Area except for any Discovery Area, the area contained in any Petroleum Production Licence and any other portion of the Contract Area on which the Minister Responsible for Petroleum agrees to permit the Company to conduct further exploration activities.

The Company has submitted its proposed 25% acreage relinquishment which are required by the Berbice PA to the DOE and GGMC and is now awaiting the agreement of these agencies on the acceptance of the proposed relinquishment and final instruments to formally move into the second renewal period of the Berbice PA.

After commercial production begins, the Company is allowed to recover contract costs as defined in the PA from "cost oil" produced and sold from the contract area and limited in any month to an amount which equals seventy-five percent (75%) of the total production from the contract area for such month excluding any crude oil and/or natural gas used in petroleum operations or which is lost. The Company's share of the remaining production or "profit oil" is 47%.

9. Exploration and evaluation expenditures (continued)

Berbice PA, Guyana (continued)

To the extent that in any month recoverable contract costs exceed the value of cost oil and/or cost gas, the unrecoverable amount shall be carried forward and shall be recoverable in the immediately succeeding month, and to the extent not then recovered, in the subsequent month or months.

The Company has $500,000 of recoverable costs brought forward from the original Berbice licence. This cost can be recovered against any future commercial production.

Annual rental fees of $25,000 and training fees of $25,000 are required to be paid under the PA.

Demerara PA, Guyana

On February 12, 2013, the Company entered into the Demerara PA and PPL. The new PPL applies to the former offshore portion of the Annex PPL, which was a subset of the Company's original Corentyne PA. On December 15, 2017, the Company was issued an addendum to the February 12, 2013 PA ("Addendum III").

Under the terms of the Addendum III, the Company's work commitments were modified and the Company relinquished 25% of the original contract area block. Effective May 20, 2019 and as at September 30, 2020 and December 31, 2019, the Demerara PPL and PA is 66.667% owned by the Company. The table below outlines the commitments under the Addendum III as at September 30, 2020:

Period	Phase	Exploration Obligation	Dates
First Renewal Period - 3 Years	Phase One - 12 Months	Conduct additional data processing and planning for 1st exploration well (Conducted)	Feb 12, 2017 - Feb 12, 2018
- At the end of phase one (1) of the first renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2. (Company has commited to complete work in phase 2)
Phase Two - 24 Months	Complete any additional processing and planning, and secure all regulatory approvals for the drilling of 1st exploration well (Completed)	Feb 12, 2018 - Feb 12, 2020
- At the end of the first renewal period of three (3) years, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or relinquish twenty-five (25%) percent of the Contract Area and renew the Petroleum Prospecting Licence for a second period of three (3) years.
Second Renewal Period - 3 Years	Phase One - 12 Months	Drill 1 exploration well	Feb 12, 2020 - Feb 12, 2021
- At the end of phase one of the second renewal period, the Company shall elect either to relinquish the entire Contract Area except for any Discovery Area and the area contained in any Petroleum Production Licence or commit to the work programme in phase 2.
Phase Two - 24 Months	Drill 1 exploration well	Feb 12, 2021 - Feb 12, 2023
- At the end of the second renewal period of three (3) years, the Company shall relinquish the entire Contract Area except for any Discovery Area, the area contained in any Petroleum Production Licence and any other portion of the Contract Area on which the Minister Responsible for Petroleum agrees to permit the Company to conduct further exploration activities.

The Company has submitted its proposed 25% acreage relinquishment which are required by the Demerara PA to the DOE and GGMC and is now awaiting the agreement of these agencies on the acceptance of the proposed relinquishment and final instruments to formally move into the second renewal period of the Demerara PA.

9. Exploration and evaluation expenditures (continued)

Demerara PA, Guyana (continued)

If a discovery is made, the Company has the right to apply to the Minister for a PPL with respect to that portion of the contract area having a significant discovery.

After commercial production begins, the Company is allowed to recover contract costs as defined in the PA from "cost oil" produced and sold from the contract area and limited in any month to an amount which equals seventy-five percent (75%) of the total production from the contract area for such month excluding any crude oil and/or natural gas used in petroleum operations or which is lost. The Company's share of the remaining production or "profit oil" is 47%.

To the extent that in any month recoverable contract costs exceed the value of cost oil and/or cost gas, the unrecoverable amount shall be carried forward and shall be recoverable in the immediately succeeding month, and to the extent not then recovered, in the subsequent month or months.

The Company has $1,000,000 of recoverable contract costs brought forward from the original Annex licence. This cost can be recovered against any future commercial production.

Annual rental fees of $100,000 and training fees of $100,000 are required to be paid under the PA.

Farm-in agreement

On May 28, 2019, the transfers of the 33.333% interest in both the Corentyne and Demerara Prospecting Licences to Frontera were completed with an effective date of May 20, 2019. See further discussion under Corentyne PA, Guyana - Note 9.

As a result of the proceeds received under the JOAs relating to the Demerara PPL and PA, the accounting value for this licence would have been in a negative position of $7,600,000 on closing of the transaction. As a result, the Company recorded a reversal of the previously taken impairment in 2014 from the amount of the negative balance, being $7,600,000 during the year ended December 31, 2019.

Demerara Seismic agreement

In September 2014, the Company entered into a contract with Prospector PTE. Ltd. ("Prospector") to conduct a 3D seismic survey on the Company's previously 100% owned Demerara Block as part of its commitments under the Demerara PA. The aggregate cost of this seismic survey was approximately $19 million with $7 million paid to Prospector by way of issuance of 15,534,310 common shares, $2.5 million paid in cash in 2014 and the remainder of approximately $9.5 million payable in cash twelve months after the conclusion of the seismic survey (December 2015), which is included in trade and other payables as at September 30, 2020 and December 31, 2019. In accordance with the contract with Prospector, the amounts outstanding twelve months after the conclusion of the seismic survey shall accrue interest at a rate of 12% per annum. On October 3, 2016, the Company renegotiated the interest rate down from 12% per annum to 6% per annum and agreed to have Prospector complete the seismic processing of the seismic survey. In exchange, CGX has agreed to be responsible under certain circumstances to Prospector for up to a maximum of $500,000. The processing began in late 2016 and was substantially completed in 2017 and as a result, the Company has recorded a provision of $500,000 recorded in trade and other payables as at September 30, 2020 and December 31, 2019.

10. Compensation of key management personnel and related party transactions

Under IFRS, parties are considered to be related if one party has the ability to "control" (financially or by share capital) the other party or have significant influence (management) on the other party in making financial, commercial and operational decisions.

In October 2014, the Company entered into a secured bridge loan agreement (the "C$ Bridge Loan") with Frontera in the aggregate principal amount of C$7,500,000 ($6,700,000). The C$ Bridge Loan was a non-revolving term facility. The C$ Bridge Loan accrued interest at an annual rate of 5% per annum.

The activity on the C$ Bridge Loan from related party for the nine month period ended September 30, 2020 and year ended December 31, 2019 is as follows:

September 30, 2020

December 31, 2019

Opening balance at beginning of period/year	$	-	$	6,746,322
Loss on foreign exchange	-	80,435
Accrued interest on loan from related party	-	136,745
Settled against signing bonus under JOAs	-	(6,963,502)
Total loan from related party	$	-	$	-

In March 2016, the Company entered into a secured bridge loan agreement (the "Bridge Loan I") with Frontera in the aggregate principal amount of up to $2,000,000. The Bridge Loan I was a non-revolving term facility. The Bridge Loan I accrued interest at an annual rate of 5% per annum.

The activity on the Bridge Loan I from related party for the nine month period ended September 30, 2020 and year ended December 31, 2019 is as follows:

September 30, 2020
Opening balance at beginning of period/year	$	-	$	2,332,009
Accrued interest on loan from related party	-	41,371
Settled against signing bonus under JOAs	-	(2,373,380)
Total loan from related party	$	-	$	-

December 31, 2019

In October 2016, the Company entered into a secured bridge loan agreement (the "Bridge Loan II") with Frontera in the aggregate principal amount of up to $2,000,000. The Bridge Loan II was a non-revolving term facility. The Bridge Loan II accrued interest at an annual rate of 5% per annum.

The activity on the Bridge Loan II from related party for the nine month period ended September 30, 2020 and year ended December 31, 2019 is as follows:

September 30, 2020
Opening balance at beginning of period/year	$	-	$	2,168,366
Accrued interest on loan from related party	-	39,609
Settled against signing bonus under JOAs	-	(2,207,975)
Total loan from related party	$	-	$	-

December 31, 2019

In April 2017, the Company entered into a secured bridge loan agreement (the "Bridge Loan III") with Frontera. On February 1, 2019, the Company and Frontera amended the Bridge Loan III to a non-revolving term facility in an amount of up to $12,939,000, provided that the facility will be automatically reduced by a payment from the Company to a maximum principal amount of $8,800,000 by May 28, 2019. This revised term facility carried an interest rate of up to 7% per annum and were to mature on September 30, 2019.

The $8,800,000 principal amount was convertible into common shares of the Company at the option of Frontera anytime prior to maturity or repayment at a price of $0.22 per share.

10. Compensation of key management personnel and related party transactions (continued)

The Bridge Loan III accrued interest at an annual rate of 7% (5% prior to February 1, 2019) per annum. On September 24, 2019, Frontera elected to exercise the conversion feature and 40,000,000 common shares of the Company were issued to settle $8,800,000.

The activity on the Bridge Loan III from related party for the nine month period ended September 30, 2020 and year ended December 31, 2019 is as follows:

September 30, 2020

December 31, 2019

Opening balance at beginning period/year

$

-

$

11,302,528

Loan from related party - 961,763 Trade and other payables and accrued interest added to

loan from related party - 712,620

Conversion component of convertible debentures

-

(169,000)Interest accretion - 169,000

Accrued interest on loan from related party - 539,355

Accrued interest added to loan from related party

-

(86,375)Settled against signing bonus under JOAs - (4,425,579)

Exercise of conversion feature - (8,800,000)

Cash payment of interest Total loan from related party

-

(204,312)

$

-

$

-The Bridge Loan III was classified as a liability, with the exception of the portion relating to the conversion feature, resulting in the carrying value of the Bridge Loan III being less than face value. The discount was accreted over the term of the Bridge Loan III utilizing the effective interest rate method at a 10% discount rate.

In November 2015, the Company entered into a convertible debenture (the "Debenture") with Frontera in the aggregate principal amount of $1,500,000. The Debenture accrues interest at an annual rate of 5% per annum and was repayable in full including all accrued interest in November 2016. This Debenture was convertible into shares of the Company at the option of Frontera at any time prior to November 15, 2016 at a price of C$0.335, which lapsed.

The activity on the Debenture from related party for the nine month period ended September 30, 2020 and year ended December 31, 2019 is as follows:

September 30, 2020
Opening balance at beginning of period/year	$	-	$	1,747,618
Accrued interest on loan from related party	-	32,542
Settled against signing bonus under JOAs	-	(1,780,160)
Total Debenture from related party	$	-	$	-

December 31, 2019

On February 7, 2019, to pay the required drilling rig minimum obligation fee of $5,340,000 (covering the Company's share of the mobilization fee, demobilization fee and 30-days of rig time charged at the stand-by rate) Frontera advanced the Company the full amount. Of this amount the Company signed a promissory note for $3,115,035 (the "Promissory Note"), being the Company's anticipated share pursuant to the terms of the JOAs.

The Promissory Note carried an interest rate of 7% per annum and matured on the earlier of the closing date of the transactions under the farm-out agreement with Frontera or May 28, 2019. On May 28, 2019, the Promissory Note principal plus accrued interest of $63,820 for a total of $3,178,855 was netted against the $33.3 million signing bonus on the JOAs.

10. Compensation of key management personnel and related party transactions (continued)

The Bridge Loan III was secured by a pledge of the shares in the Company's wholly owned subsidiaries - CGX Resources, GCIE Holdings Limited ("GCIE") and CGX Energy Management Corp. ("CGMC"). In addition, during the year ended December 31, 2017, GCIE and CGMC signed a guarantee with Frontera for the Bridge Loan III.

As at September 30, 2020 and December 31, 2019, Frontera owned approximately 72.4% of the common shares of the Company.

Farm in partner advances

Under the JOAs, the Company is operator on both the Corentyne and Demerara licences. As operator, the Company makes cash calls from its partner to pay for future licence expenditures. As at September 30, 2020, the Company had cash called and received $1,704,048 (December 31, 2019 - $1,701,409) in advances for future exploration on the Corentyne and Demerara licences.

In addition, as operator of the Corentyne and Demerara licences, the Company receives a fee from its partner to reimburse its indirect costs related to operating the licence. This fee is based on total expenditures under the JOAs. During the nine month period ended at September 30, 2020, the Company received fees from its farm in partner of $12,522 (year ended December 31, 2019 - $348,621).

Key management

Key management includes the Company's directors, officers and any employees with authority and responsibility for planning, directing and controlling the activities of an entity, directly or indirectly. Compensation awarded to key management included:

Nine month period ended September 30,	2020	2019
Short-term employee benefits	$	934,000	$1,478,000
Share based payments	1,912,000	-
Total compensation paid to key management	$	2,846,000 $	1,478,000

At September 30, 2020, included in trade and other payables is $187,000 (December 31, 2019 - $112,000) due as a result of deferred payment of directors' fees. These amounts are unsecured, non-interest bearing and due on demand. See also Note 16.

11. Trade and other payables

Trade and other payables of the Company are principally comprised of amounts outstanding for trade purchases relating to exploration activities and amounts payable for operating and financing activities. The usual credit period taken for trade purchases is between 30 to 90 days. The following is an aged analysis of the trade and other payables:

As at,

September 30, 2020

December 31, 2019

Less than one month, accruals and accrued interest One month to three months

$

Over three months

4,695,426 - 9,455,687

$

5,930,264 2,426 9,463,456

Total trade and other payables

$

14,151,113

$

15,396,146

12. Warrant liability

As at September 30, 2020 and December 31, 2019, the warrant liability was comprised of the following:As at,

September 30, 2020

December 31, 2019

Warrant liability

$

3,895,000

$

4,736,000

Each warrant entitles the holder to purchase a common share at C$0.415 until March 13, 2024. The Company recorded the warrants issued as a derivative liability due to their exercise price being denominated in a currency other than the Company's US dollar functional currency.

The warrant liability was re-valued at the end of the reporting period with the change in fair value of the warrant liability recorded as a gain or loss in the Company's condensed interim consolidated statements of comprehensive income. The warrant liability was accounted for at its fair value as follows for the nine month period ended September 30, 2020 and year ended December 31, 2019:

September 30, 2020

December 31, 2019

Warrant liability, beginning of period/year	$	4,736,000	$	-
Grant date fair value of warrants issued during the year (note 13)	-	2,259,000
Change in fair value	(841,000)	2,477,000
Warrant liability, end of period/year	$	3,895,000	$	4,736,000

The Company utilized the Black-Scholes valuation model to estimate the fair value of the warrants at September 30, 2020 and December 31, 2019 using the following assumptions:

As at,	September 30, 2020	December 31, 2019
Number of warrants outstanding	15,009,026
Exercise price	C$0.415	C$0.415
Risk-free interest rate	0.25%	1.68%
Expected life (years)	3.45	4.20
Expected volatility	116%	104%
Expected dividends	0%	0%
Market price per share	C$0.47	C$0.54
Fair value of warrants

$

15,009,026

15,009,026

$

3,895,000

4,736,000

Volatility for these warrants has been calculated using the historical volatility of the Company.

13. Capital stock

Share capital

The Company is authorized to issue an unlimited number of common shares without par value. Changes in the issued and outstanding common shares are as follows:

Number of Shares	$
Balance at December 31, 2018	116,102,318	259,034,321
Shares issued for rights offering	116,102,318	21,779,530
Share issue costs	-	(428,823)
Warrants issued under rights offering	-	(2,259,000)
Shares issued on conversion of convertible debt	40,000,000	8,800,000
Value of contributed surplus transferred on conversion of
convertible debt	-	169,000
Shares issued on exercise of options1	375,000	90,744
Value of contributed surplus transferred on exercise of options	-	73,132
Balance at December 31, 2019 and September 30, 2020	272,579,636	287,258,904

1 The weighted average trading price on date of exercise for the stock options exercised during the year ended December 31, 2019 was $0.46.

2019

On March 12, 2019, the Company completed a rights offering (the "Offering"). Pursuant to the Offering, the Company issued to holders of its outstanding common shares of record as at the close of business on February 11, 2019 an aggregate of 116,102,318 transferable rights (each, a "Right") to subscribe for, until March 12, 2019 (the "Expiry Date"), an aggregate of 116,102,318 common shares. Each Right entitled the holder thereof to subscribe for one common share upon payment of the subscription price of C$0.25 (equivalent of approximately $0.1876) per common share prior to the Expiry Date. The Company issued 116,102,318 common shares, the maximum number of common shares available for issuance under the terms of the Offering, based on shareholders' exercise of the basic subscription privilege and the additional subscription privilege, allocated pro-rata, for aggregate gross proceeds to the Company of C$29,025,579 (equivalent of approximately $21,779,530).

Frontera provided a standby commitment in connection with the Offering (the "Standby Commitment"), in which Frontera would acquire any common shares available as a result of any unexercised Rights under the Rights Offering, such that CGX was guaranteed to issue 116,102,318 common shares in connection with the Offering. In consideration for the Standby Commitment, Frontera received 5-year warrants to purchase up to 15,009,026 common shares at an exercise price equal to C$0.415 per common share (each a"Warrant"). Since the Offering was oversubscribed, Frontera did not acquire any additional shares under the Standby Commitment.

Frontera acquired an aggregate of 101,316,916 common shares in connection with the Offering pursuant to the exercise of Rights under the Offering for cash consideration of C$25,329,229 (equivalent of approximately $19,005,950). Officers and directors of the Company acquired an aggregate of 202,859 common shares in connection with the Offering pursuant to the exercise of Rights under the Offering for cash consideration of C$50,715 (equivalent of approximately $38,054).

The grant date fair value of the 15,009,026 Warrants was estimated at $2,259,000 using the Black-Scholes pricing model with the following assumptions: exercise price C$0.415; expected dividend yield 0%; expected forfeiture rate 0%; risk free interest 1.65%; expected volatility 117%, an expected life of 5 years and market price of shares on date of issuance of C$0.26.

13. Capital Stock (continued)

Share Capital (continued)

On September 24, 2019, Frontera exercised the conversion feature on its Bridge Loan III and 40,000,000 common shares of the Company were issued at a conversion price of $0.22 (C$0.29) to settle $8,800,000 in convertible debentures. The fair value share price on the date of exercise was C$0.77.

Common share purchase warrants

The exercise price and expiry date of the warrants outstanding at September 30, 2020 are as follows:

Warrants	Exercise Price	Expiry Date
15,009,026	C$0.415	March 13, 2024

Changes in the number of common share purchase warrants outstanding are as follows:

As at,

Outstanding at beginning of period/year Transactions during the period/year:

September 30, 2020	December 31, 2019
Weighted	Weighted
Average Exercise No. of	Average Exercise No. of
Price ($) Warrants	Price ($) Warrants
-

C$0.415

15,009,026

-

Issued

Outstanding at end of period/year

- C$0.415

- 15,009,026

C$0.415

C$0.415

15,009,026 15,009,026

Options

The Company established a share option plan to provide additional incentive to its directors, officers, employees and consultants for their efforts on behalf of the Company in the conduct of its affairs. The maximum number of common shares reserved for issuance under the share option plan comprising part of the share incentive plan may not exceed 10% of the number of common shares outstanding. Under the terms of the plan, all options vest immediately, unless otherwise specified. All options granted under the plan expire no later than the tenth anniversary of the grant date. As at September 30, 2020, the Company had 12,297,963 (December 31, 2019 - 13,257,963) options available for issuance under the plan.

Changes in the number of stock options outstanding are as follows:

As at,
Outstanding at beginning of period/year	C$0.43	14,000,000	C$0.15	1,375,000
Transactions during the period/year:
Granted	C$0.71	1,510,000	C$0.46	13,000,000
Exercised	-	-	C$0.32	(375,000)
Forfeited	C$0.46	(550,000)	-	-
Outstanding at end of period/year	C$0.46	14,960,000	C$0.43	14,000,000
Exercisable at end of period/year	C$0.44	10,055,000	C$0.39	5,333,333

September 30, 2020	December 31, 2019
Weighted	Weighted
Average Exercise No. of	Average Exercise No. of
Price ($) Options	Price ($) Options

13. Capital stock (continued)

Options (continued)

The following table provides additional outstanding stock option information as at September 30, 2020:

Weighted Average	Weighted Average	Weighted Average
Exercise	No. of Options	Remaining	Exercise	No. of Options	Exercise
Price	Outstanding	Life (Years)	Price	Exercisable	Price
C$ 0.085	1,000,000	1.59	C$0.085	1,000,000	C$0.085
C$ 0.46	12,450,000	4.18	C$0.46	8,300,000	C$0.46
C$ 0.71	1,510,000	4.30	C$0.71	755,000	C$0.71
C$ 0.085 - 0.71	14,960,000	4.01	C$0.46	10,055,000	C$0.44

The following table summarizes the assumptions used with the Black-Scholes valuation model for the determination of the share based compensation for the stock options granted and/or vested during the nine month period ended September 30, 2020:

Vesting of prior

year issued

January 17, 2020
Number of options granted	1,510,000
Exercise price	C$0.71
Risk-free interest rate	1.58%
Expected life (years)	5.0
Expected volatility	120.57%
Market price per share	C$0.71
Expected dividends and forfeiture rate	-
Vesting	1/3 immediately, 1/3
in 6 months and 1/3
in 12 months
Fair value of grant
Share based compensation

options

$ 1,915,000

Totals
$	681,000 $	681,000
$	613,000 $	2,528,000

The following table summarizes the assumptions used with the Black-Scholes valuation model for the determination of the share based compensation for the stock options granted and/or vested during the year ended December 31, 2019:

December 2, 2019

Totals

Number of options granted

13,000,000

Exercise price Risk-free interest rate Expected life (years) Expected volatility Market price per share

C$0.46

1.54%

5.0

124.66%

Expected dividends and forfeiture rate Vesting

C$0.46 - 1/3 immediately, 1/3 in 6 months and 1/3 in 12 months

Fair value of grant

Share based compensation

$ $

3,790,000 $ 3,790,000

1,565,000 $ 1,565,000

Volatility for all option grants has been calculated using the Company's historical information.

13. Capital stock (continued)

Options (continued)

The weighted average grant-date fair value of options granted during the nine month period ended September 30, 2020 was $0.45 (year ended December 31, 2019 - $0.29) per option issued.

14. Reserve for share based payments

A summary of the changes in the Company's reserve for share based payments for the nine month period ended September 30, 2020 and year ended December 31, 2019 is set out below:

As at,

September 30, 2020

December 31, 2019

Balance at beginning of period/year Share based payments (note 13)

$

23,199,999 $ 21,708,131 2,528,000 1,565,000

Equity portion of convertible debenture (note 10) Value transferred on exercise of convertible debenture

-

169,000

(note 13)

- (169,000)

Value transferred on exercise of stock options

- (73,132)

Balance at end of period/year

$

25,727,999

$

23,199,999

15. Segmented information

Operating and geographic segments

At September 30, 2020 and December 31, 2019, the Company's current operations are comprised of a single reporting operating segment engaged in petroleum and natural gas exploration in Guyana. The Company expects that once the wharf project is constructed that it will have two operating segments. The Company's corporate division only earns revenues that are considered incidental to the activities of the Company and therefore does not meet the definition of an operating segment as defined in IFRS 8

'Operating Segments'.

As the operations comprise a single reporting segment, amounts disclosed in the unaudited condensed interim consolidated financial statements also represent operating segment amounts.

The following is a detailed breakdown of the Company's assets by geographical location:

As at,

September 30, 2020

December 31, 2019

Total current assets

Canada

Guyana

Total non-current assets

Canada

Guyana

Total Identifiable assets

Canada

Guyana $ 36,196,911

$ 10,247,365

$	15,813,054
196,401
$	16,009,455
$	-
23,923,375
$	23,923,375
$ 9,868,113	$	15,813,054
26,328,798	24,119,776
$	39,932,830
Page 28

$ 9,868,113

379,252

$

- 25,949,546

$ 25,949,546

16. Commitments and contingencies

Contractual obligations

The Company has entered into agreements for service contracts. The future minimum consultancy commitments and contract commitments over the next five years are as follows:

Contractual

Fiscal Year Ended December 31,	Obligations
2020	$	105,000

The Company has entered into several contracts with various suppliers for services including the following:

The Company has entered into contracts for a Pore Study and Resource Studies over the Corentyne and Demerara Block to complete its requirement under the Corentyne and Demerara PPLs and an agreement for a rip rap sea wall protection for the wharf project. Aggregate minimum future obligation still outstanding under these agreements is $105,000, all expected to be paid in 2020.

Subsequent to September 30, 2020 the Company entered into a contract for the upgrading of a 3.1 km access roadway from Seawell Bridge to the deep water port site for the wharf project. The total contract value is approximately $703,000 and construction is expected to take place from October 2020 to April 2021.In addition, the Company entered into an agreement with WesternGeco LLC for reprocessing of the 3D seismic over the Demerara Block. The reprocessing is expected to take approximately seven months to complete and will cost approximately $1,065,000.

Contingencies

As at September 30, 2020, the Company is party to three (December 31, 2019 - three) separate written management agreements with certain senior officers of the Company. The three contracts currently require a total payment of up to $2,005,000 (December 31, 2019 - $2,030,000) be made upon the occurrence of certain events such as termination and change in control. As the likelihood of these events taking place was not determinable as at September 30, 2020, the contingent payments have not been reflected in these unaudited condensed interim consolidated financial statements.