PetroTal
Annual Report 2020

Plain-text annual report

2020 YEAR END REPORTING PACKAGE April 22, 2021 TSXV: TAL / AIM: PTAL / OTC: PTALF PetroTal Announces 2020 Year-End Financial and Operating Results PetroTal emerges stronger after a collapse in world oil prices and the COVID-19 pandemic Calgary, AB and Houston, TX – April 22, 2021—PetroTal Corp. ("PetroTal" or the "Company") (TSXV: TAL and AIM: PTAL) is pleased to announce its financial and operating results for the year and the three months ("Q4") ended December 31, 2020. Selected financial, reserves and operational information is outlined below and should be read in conjunction with the Company's audited consolidated financial statements ("Financial Statements"), management's discussion and analysis ("MD&A") and annual information form ("AIF") for the year ended December 31, 2020, which are available on SEDAR at www.sedar.com and on the Company's website at www.PetroTal‐Corp.com. Reserves numbers presented herein were derived from an independent reserves report (the "NSAI Report") prepared by Netherland, Sewell & Associates, Inc. ("NSAI") effective December 31, 2020. All amounts herein are in United States dollars ("USD") unless otherwise stated. 2020 Highlights - - - - - - - - - Drilled and completed the 6H well on schedule and within budget achieving a 10-day flush production average of approximately 4,500 bopd; Successfully and seamlessly reopened the Bretana field in late September 2020 after COVID 19, social, and Northern Oil Pipeline (“ONP”) maintenance related issues. There was no additional downtime or related safety issues once startup commenced, with field production rising back to approximately 11,000 bopd (pre shut down levels) ten days later; Completed commissioning of the enhanced central production facilities ("CPF-1"), bringing overall oil production capacity to between 16,000 and 18,000 bopd; Optimized the 2020 capital program to maximize liquidity and operational performance due to the COVID 19 pandemic, ongoing government social related issues, and shut down of the ONP; Signed an extended oil sales contract with Petroperu outlining improved terms, including reduced pipelined tariffs and fees during periods of low oil prices; Raised approximately $18 million in equity to provide 2020 liquidity support; Delivered a material lift in 2020 year ended 3P oil reserves with a lower 2P operating cost profile based on positive technical revisions, historical well performance, and field cost reduction initiatives; Concluded historic collaboration between the local Bretana residents and communities, aligning their goals and objectives with the Company's; and, Executed a route to market diversification strategy through Brazil with comparable margins to the ONP route. Events Subsequent to December 31, 2020 - On January 19, 2021, the Company executed a final agreement with Petroperu, restructuring the contingent derivative liability over three years. The amount of the contingent liability represented $16.6 million (based on the November 30, 2020 valuation) and was subsequently paid out (along 2 with the $3 million Peruvian-government COVID emergency response loan), from the $100 million bond offering referred to below. Since that time, the Company through Petroperu, has recently placed hedges, solidifying approximately $30 million of true-up revenue on the 1.8 million barrels in the ONP that originally caused the contingent liability; On February 2, 2021, the Company announced completion of a 3-year $100 million senior secured bond with an annual 12% coupon, issued at a 5% discount. The bonds issued by PetroTal are the Company’s only interest bearing debt and the proceeds are for payout of the Petroperu derivative liability with Petroperu and Reactiva loan, totaling $20 million, to support the Company’s crude oil price hedging strategy ($15 million), to finance potential acquisitions ($20 million), with the remainder for continued development of the Bretana oil field; On February 18, 2021, the Company announced its 2021 capital development program of $100 million, to be funded from the bond proceeds and internally generated funds from operations, along with existing cash resources; The Company has hedged approximately 32% of expected April to December 2021 oil production. Additionally, Petroperu has now hedged 100% of oil sales through the ONP. This robust hedging program will ensure funding stability to support the 2021 capital development program, in the event that Brent oil price drops materially; and, Pursuant to the Company’s oil market diversification strategy, in Q1 2021 the Company completed a second shipment of 225,000 barrels of oil through Brazil for export into the Atlantic region. The oil sale was FOB Bretana and generated revenue of $8.8 million. - - - - Three months ended December 31, 2020 (“Q4”) Highlights - - - - - - - - PetroTal produced 6,410 bopd and sales volumes averaged 5,471 bopd, compared to sales of 2,327 bopd in Q3 2020; Indigenous communities and government bodies reached agreements that will see increased funding for the local communities, thereby allowing for the ONP to resume full operations; The Company's stringent COVID-19 protocols continue to ensure that the camp remains safe; The Company sold 397,000 barrels of oil to the Iquitos refinery and the ONP (at pump station #1 at Saramuro), thereby generating revenues of $12.4 million, net of transportation and fees; PetroTal reached agreement with an international oil trader for an initial shipment to export 106,000 barrels through Brazil into the Atlantic region, via the Amazon river. The December 2020 shipment was sold FOB Bretana, priced at the forward month Brent ICE price, and paid within two weeks of loading at Bretana. Importantly, there are no subsequent oil price adjustments; Operating income of $5.9 million ($11.90/bbl) compared to $2.3 million ($10.86/bbl) in Q3 2020; Funds flow provided by operations of $1.3 million compared to a deficiency of $0.5 million in Q3 2020; and, Capital expenditures were $6.3 million compared to $3.4 million in Q3 2020. 2020 Operational Highlights - - Six producing wells and one water disposal well were operating during Q4 2020, inclusive of the initial water disposal well that was converted to an oil producer; Approximately $42 million incurred in capital expenditures to drill one oil well, build production facilities and standby-related charges, compared to $89 million in 2019; 3 - - - - PetroTal produced a total of 2.1 million barrels of oil in 2020, representing average oil production of 5,675 bopd, an increase of 37% from the average production of 4,131 bopd realized in 2019; Annual independent reserve assessment, as prepared by NSAI shows increases in all reserve categories: o Proved ("1P") reserves of 22.3 million barrels ("mmbbl"), an increase of 4% from the 21.5 mmbbl recorded at the end of 2019; o Proved plus Probable ("2P") reserves of 51.0 mmbbl, an increase of 7% from the 47.7 mmbbl recorded at the end of 2019; and, o Proved plus Probable and Possible ("3P") reserves of 106.1 mmbbl, an increase of 25% from the 84.8 mmbbl recorded at the end of 2019; Original oil in place ("OOIP") estimates for 1P, 2P and 3P reserve categories were unchanged from 2019 at 235, 364 and 579 mmbbls, respectively; and, Net Present Value (after tax, discounted at 10%) ("NPV-10") represents $271 million ($12.15/bbl) for 1P reserves, $621 million ($12.17/bbl) for 2P reserves and $1.2 billion ($11.03/bbl) for 3P reserves based on the NSAI year end 2020 price deck. 2020 Financial Highlights - - - - - - - Generated revenue in 2020 of $76.6 million ($36.71/bbl) compared to $82.8 million ($56.24/bbl) in 2019; Royalties to the Peruvian government were $2.9 million compared to $3.4 million for 2019; Generated funds from operations of $16.6 million compared to $30.3 million in 2019, as a result of the significant decrease in oil prices; Operating and transportation costs, were $44.8 million ($21.49/bbl) compared to $37.7 million ($25.59/bbl) for 2019, an improvement of 21%, on a per barrel basis; Net operating income (netback) was $28.9 million ($13.84/bbl) compared to $41.7 million ($28.34/bbl) in 2019; Cash flow generated was $13.4 million compared to $51.1 million in 2019. Cash flow represents netback inclusive of G&A costs, realized gain (losses) on commodity contracts and all other cash transactions; and, At December 31, 2020, the Company held cash of $9.6 million, compared to $21.1 million at the end of 2019. 4 Selected Financial and Operating Highlights (in thousands USD) Financial Crude oil revenues Royalties Net operating income Commodity price derivatives loss (1) Net income (loss) Basic and diluted net income (loss) (US$/share) Capital expenditures Operating Average production (bopd) (2)(3) Average sales (bopd) Average Brent oil price (US$/barrel) Average realized price (US$/barrel) Netback (US$/barrel) (4) Funds flow provided by (used in) operations (4) Balance sheet Cash Working Capital Total assets Current liabilities Equity Note: Year-Ended Quarter-Ended December 31, 2020 December 31, 2019 December 31, 2020 September 30, 2020 June 30, 2020 March 31, 2020 $76,593 (2,877) 28,881 4,788 (1,524) (0.00) 42,297 $82,790 (3,396) 41,719 367 $20,152 0.03 88,763 5,675 5,700 41.74 36.71 13.84 16,668 4,131 4,033 64.31 56.24 28.34 29,413 $17,374 (700) 5,992 (12,969) 10,675 0.01 6,315 $7,611 (248) 2,324 (4,399) 3,224 0.01 3,354 $9,839 (123) 2,756 (18,264) 16,029 0.02 8,756 $41,768 (1,806) 17,809 40,420 (31,452) (0.05) 23,872 6,410 5,471 44.24 34.52 11.90 1,293 2,444 2,327 43.34 35.56 10.86 (548) 4,185 4,729 29.19 22.87 6.40 862 9,686 10,313 50.14 44.51 18.98 15,061 9,628 (22,157) 215,138 58,608 137,163 21,101 (11,762) 194,181 59,286 121,057 9,628 (22,157) 215,138 58,608 137,163 9,788 (30,407) 205,531 62,355 126,253 20,379 (31,845) 216,899 76,932 122,789 7,373 (61,025) 194,274 89,914 90,029 (1) Contingent liability will be paid over a three-year period. (2) (3) The field was shut in on May 7, 2020; for the 37 producing days in Q2 2020, production averaged 11,500 bopd. The field was shut in from July 1 to July 14 and from August 9 to September 27; for the 28 producing days in Q3 2020 constrained production averaged 8,000 bopd. Funds flow provided by (used in) operations and netback do not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities. See “Non-GAAP Measures”. (4) Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented "2020 was an extremely challenging year for the global economy and PetroTal emerged from the downturn in a position of strength, a testament to our team's dedication and resolve. Although our 2020 results were impacted by many one-time events, the Company's announcements over the last six months have been overwhelmingly positive and will underpin our growth through 2021 and beyond. I am excited to continue to deliver on our 2021 capital program, which we anticipate will generate value for our equity, debt, and ESG stakeholders. I would like to thank PetroTal's shareholders, directors, employees, and contractors for their continued support and I look forward to keeping all our stakeholders updated on the Company's progress throughout the remainder of 2021." 5 ABOUT PETROTAL PetroTal is a publicly traded, dual‐quoted (TSXV: TAL and AIM: PTAL) oil and gas development and production company domiciled in Calgary, Alberta, focused on the development of oil assets in Peru. PetroTal's flagship asset is its 100% working interest in Bretana oil field in Peru's Block 95 where oil production was initiated in June 2018, and in early 2020 became the second largest crude oil producer in Peru. Additionally, the Company has large exploration prospects and is engaged in finding a partner to drill the Osheki prospect in Block 107. The Company's management team has significant experience in developing and exploring for oil in Peru and is led by a Board of Directors that is focused on safely and cost effectively developing the Bretana oil field. For further information, please see the Company's website at www.petrotal-corp.com, the Company's filed documents at www.sedar.com, or below: Douglas Urch Executive Vice President and Chief Financial Officer Durch@PetroTal-Corp.com T: (713) 609-9101 Manolo Zuniga President and Chief Executive Officer Mzuniga@PetroTal-Corp.com T: (713) 609-9101 PetroTal Investor Relations InvestorRelations@PetroTal-Corp.com Celicourt Communications Mark Antelme / Jimmy Lea petrotal@celicourt.uk T : 44 (0) 208 434 2643 Strand Hanson Limited (Nominated & Financial Adviser) James Spinney / Ritchie Balmer T: 44 (0) 207 409 3494 Stifel Nicolaus Europe Limited (Joint Broker) Callum Stewart / Simon Mensley / Ashton Clanfield Tel: +44 (0) 20 7710 7600 Auctus Advisors LLP (Joint Broker) Jonathan Wright / Rupert Holdsworth Hunt / Harry Baker T: +44 (0) 7711 627449 6 READER ADVISORIES FORWARD-LOOKING STATEMENTS: This press release contains certain statements that may be deemed to be forward-looking statements. Such statements relate to possible future events, including, but not limited to: PetroTal's business strategy, objectives, strength and focus; drilling, completions, workovers and other activities and the anticipated costs and results of such activities; the ability of the Company to achieve drilling success consistent with management's expectations; anticipated future production and revenue; drilling plans including the timing of drilling; oil production levels, including average production and exit production in 2021; the 2021 capital program and budget, including drilling plans; COVID-19 surveillance and control process; hedging program and the terms thereof; and future development and growth prospects. All statements other than statements of historical fact may be forward-looking statements. In addition, statements relating to expected production, reserves, recovery, costs and valuation are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Forward-looking statements are often, but not always, identified by the use of words such as "anticipate", "believe", "expect", "plan", "estimate", "potential", "will", "should", "continue", "may", "objective" and similar expressions. The forward-looking statements are based on certain key expectations and assumptions made by the Company, including, but not limited to, expectations and assumptions concerning the ability of existing infrastructure to deliver production and the anticipated capital expenditures associated therewith, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices and the actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labour, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the accuracy of PetroTal's geological interpretation of its drilling and land opportunities, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance of new wells, the Company's growth strategy, general economic conditions and availability of required equipment and services. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating to production, costs and expenses; and health, safety and environmental risks), commodity price volatility, price differentials and the actual prices received for products, exchange rate fluctuations, legal, political and economic instability in Peru, access to transportation routes and markets for the Company's production, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. In addition, the Company cautions that current global uncertainty with respect to the spread of the COVID-19 virus and its effect on the broader global economy may have a significant negative effect on the Company. While the precise impact of the COVID-19 virus on the Company remains unknown, rapid spread of the COVID-19 virus may continue to have a material adverse effect on global economic activity, and may continue to result in volatility and disruption to global supply chains, operations, mobility of people and the financial markets, which could affect interest rates, credit ratings, credit risk, inflation, business, financial conditions, results of operations and other factors relevant to the Company. Please refer to the risk factors identified in the AIF and the MD&A which are available on SEDAR at www.sedar.com. The forward-looking statements contained in this press release are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. PRESENTATION OF OIL AND GAS INFORMATION: The reserves information herein sets forth PetroTal's reserves as at December 31, 2020, as presented in the independent reserves report prepared by NSAI, a qualified reserves evaluator, in accordance with the standards contained in the most recent publication of the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") and the reserve definitions contained in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51- 101"). In addition to the summary information disclosed in this announcement and the press release dated February 24, 2021, more detailed information is included in the AIF. All oil and gas disclosure contained in this press release complies with the 7 requirements of NI 51-101. The term original oil in place (OOIP) is equivalent to total petroleum initially in place ("TPIIP"). TPIIP, as defined in the COGE Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered. OIL AND GAS INFORMATION: References in this press release 10-day flush production and other short‐term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production for PetroTal. The Company cautions that the such results should be considered to be preliminary. OIL REFERENCES: All references to "oil" or "crude oil" production, revenue or sales in this press release mean "heavy crude oil" as defined in NI 51-101. All references to Brent indicate Intercontinental Exchange ("ICE") Brent. NON-GAAP MEASURES: This press release contains financial terms that are not considered measures under generally accepted accounting principles ("GAAP") such as operating netback and funds flow provided by operations, that do not have any standardized meaning under GAAP and may not be comparable to similar measures presented by other companies. Management uses these non-GAAP measures for its own performance measurement and to provide shareholders and investors with additional measurements of the Company's efficiency and its ability to fund a portion of its future capital expenditures. The Company considers operating netbacks to be a key measure as they demonstrate Company’s profitability relative to current commodity prices. Netback is calculated by dividing net operating income by barrels sold in the corresponding period. Funds flow provided by operations, is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. A reconciliation from cash provided by operating activities to funds flow provided by operations is included in the MD&A. FOFI DISCLOSURE: This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about PetroTal's prospective results of operations, production and production capacity, NPV-10, 2021 capital program and budget, cash flow profile, liquidity and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this press release was approved by management as of the date of this press release and was included for the purpose of providing further information about PetroTal's anticipated future business operations. PetroTal disclaims any intention or obligation to update or revise any FOFI contained in this press release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein. All FOFI contained in this press release complies with the requirements of Canadian securities legislation, including NI 51-101. Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this press release. 8 MANAGEMENT’S DISCUSSION AND ANALYSIS For the years ended December 31, 2020 and 2019 TSXV: TAL / AIM: PTAL / OTC: PTALF TABLE OF CONTENTS 1. Corporate overview ……………………………………………………………………………………………………….……… 2. Overview and selected information...……………………………………………………………...……………………. 3. 2020 Highlights………………………………………………………………………………………………………………………. 4. Outlook and growth strategy ..…………………...………………..………………………………………………………. 5. Selected financial information……………………………………………………………………………………………….. 6. 2020 Reserve Report………………………. ……………………………………………………………………..…….………. 7. Significant judgements and estimates ……………………………………………………………………..…….……… 8. Related party transactions and taxes ……………………………………….……..…………………………………….. 9. Contractual obligations and commitments……………………………………………………………………………… 10. Forward-looking statements and business risks ……………………………………………………………………… 3 4 4 6 7 14 16 16 16 17 10 MANAGEMENT’S DISCUSSION AND ANALYSIS This Management’s Discussion and Analysis (“MD&A”) of the operating results and financial condition of PetroTal Corp. (“PetroTal” or the “Company”) for the years ended December 31, 2020 and 2019, is dated April 21, 2021, and should be read in conjunction with the Company’s audited Consolidated Financial Statements (the “Financial Statements”) for the twelve months ended December 31, 2020 and 2019 and the Company’s annual information form (the “AIF”) for the year ended December 31, 2020. The audited Financial Statements were prepared by management in accordance with International Financial Reporting Standards (“IFRS”) issued by the International Accounting Standards Board, which are also generally accepted accounting principles (“GAAP”) for publicly accountable enterprises in Canada. Financial figures throughout this MD&A are stated in thousands of United States dollars (“$” or “USD”) unless otherwise indicated. This MD&A contains forward-looking statements that should be read in conjunction with the Company's disclosure under “Forward- Looking Statements and Business Risks”. 1. CORPORATE OVERVIEW PetroTal is a publicly-traded (TSXV: TAL and AIM: PTAL), international oil and gas company incorporated and domiciled in Canada. Through its two subsidiaries in Peru, the Company is currently engaged in the ongoing development of hydrocarbons in Block 95 with a focus on the development of, and production from the Bretana oil field. In addition to further leads in Block 95, the Company has significant exploration prospects and leads in Block 107. During 2017, the Company completed a plan of arrangement (the “Reverse Takeover “RTO”) with Sterling Resources Ltd. pursuant to which Sterling acquired all of the shares of PetroTal LLC Ltd. and, once amalgamated, continued as one operation under the name of Sterling Resources Ltd. The name of the Company was changed in June 2019 to PetroTal Corp. The Company acquired 100% of the subsidiaries from of Gran Tierra Energy Inc. (“GTE”) that held the rights to the exploration blocks in Peru. GTE had 100% working interest in five license contracts: Blocks 95, 107, 123, 129 and 133 with GTE retaining a 20% back-in option in Block 107. In 2019 PetroTal relinquished its rights to Blocks 123, 129 and 133. After the reverse takeover transaction In connection with closing of the Reverse Takeover and the acquisition of the GTE Peruvian assets on December 18, 2017, the Company appointed an experienced Board of Directors, retained the prior PetroTal Management team and raised $34 million gross proceeds through the issuance of subscription receipts, which were subsequently converted into common shares. 11 The Bretana oil field is located in the Maranon Basin of northern Peru. To date, this basin has produced more than one billion barrels of crude oil. Approximately 70% of the oil in the Maranon Basin has been produced from the Vivian formation and approximately 30% from the Chonta formation. The Vivian formation is known as a quality oil reservoir with high permeabilities and strong aquifer support. Generally, this type of reservoir achieves the highest oil recoveries. The Chonta formation is immediately below the Vivian and typically produces medium to light oil, the Company is focused on the Vivian formation. The Company has a 100% working interest in the Bretana oil field. 2. OVERVIEW AND SELECTED INFORMATION The following table summarizes key financial and operating highlights associated with the Company’s performance for the periods ended December 31, 2020, September 30, 2020, June 30, 2020, March 31, 2020 and December 31, 2019. Note that the commodity price derivative is a non-cash item. RESULTS AT A GLANCE (1) (2) (3) Contingent liability will be paid over a three-year period. The field was shut in on May 7, 2020, for the 37 producing days in Q2 2020, production averaged 11,500 bopd. The field was shut in from July 1 to July 14 and from August 9 to September 27, for the 28 producing days in Q3 2020 constrained production averaged 8,000 bopd. 3. 2020 HIGHLIGHTS The Company reached several key operational and financial achievements as described below: Three months ended December 31, 2020 (“Q4”) Highlights - - - - - - - - PetroTal recommenced oil field operations on September 28, 2020 and has remained producing continuously since then. The wells were quickly brought into operation averaging 6,410 bopd in Q4 2020, intentionally constrained to manage oil delivery availability to the Iquitos refinery and the Northern Oil Pipeline (“ONP”). The indigenous communities and government bodies reached agreements that will see increased funding for the local communities, thereby allowing for the ONP to resume full operations; The Company’s stringent COVID-19 protocols continue to ensure that the camp remains safe; The Company sold 397,000 barrels of oil to the Iquitos refinery and the ONP at pump station #1, thereby generating revenues of $12.4 million, net of transportation and fees; PetroTal reached agreement with an international oil trader for an initial shipment to export 106,000 barrels through Brazil into the Atlantic region, via the Amazon river. The December 2020 shipment was sold FOB Bretana, priced at the forward month Brent ICE price, and paid within two weeks of loading at Bretana. Importantly, there are no subsequent oil price adjustments; Operating income of $5.9 million ($11.90/bbl) compared to $2.3 million (10.86/bbl) in Q3 2020; The Company recognized funds flow provided by operations of $1.3 million compared to a deficiency of 0.5 million in Q3 2020; PetroTal produced 6,410 bopd and sales volumes averaged 5,471 bopd, compared to sales of 2,327 bopd in Q3 2020; and, Capital expenditures were $6.3 million compared to $3.4 million in Q3 2020. 12 2020 Operational Highlights - - - - - - Six producing wells and one water disposal well were operating during Q 4 2020, inclusive of the initial water disposal well that was converted to an oil producer; The Company invested $42.3 million in capital expenditures to drill one oil well, build production facilities and standby-related charges, compared to a total capital investment of $88.8 million in 2019; PetroTal produced a total of 2.1 million barrels of oil in 2020, representing average production of 5,675 bopd, an increase of 37% from the average production of 4,131 bopd realized in 2019; Annual independent reserve assessment, as prepared by NSAI (“Netherland Sewell and Associates, Inc.”) shows increases in all reserve categories: o o o Proved ("1P") reserves of 22.3 million barrels ("mmbbl"), an increase of 4% from the 21.5 mmbbl recorded at the end of 2019; Proved plus Probable ("2P") reserves of 51.0 mmbbl, an increase of 7% from the 47.7 mmbbl recorded at the end of 2019; and, Proved plus Probable and Possible ("3P") reserves of 106.1 mmbbl, an increase of 25% from the 84.8 mmbbl recorded at the end of 2019; Original oil in place ("OOIP") estimates for 1P, 2P and 3P reserve categories were unchanged from 2019 at 235, 364 and 579 mmbbls, respectively; and, Net Present Value (after tax, discounted at 10%) (“NPV-10”) represents $271 million ($12.15/bbl) for 1P reserves, $621 million ($12.17/bbl) for 2P reserves and $1.2 billion ($11.03/bbl) for 3P reserves. 2020 Financial Highlights - - - - - - - Generated revenue in 2020 of $76.6 million ($36.71/bbl) compared to $82.8 million ($56.24/bbl) in 2019; Royalties to the Peruvian government were $2.9 million compared to $3.4 million for 2019; Generated funds from operations of $16.6 million compared to $30.3 million in 2019, as a result of the significant decrease of oil prices; Operating and transportation costs, were $44.8 million ($21.49/bbl) compared to $37.7 million ($25.59/bbl) for 2019, an improvement of 21%, on a per barrel basis; Net operating income (netback) was $28.9 million ($13.84/bbl) compared to $41.7 million ($28.34/bbl) in 2019; Cash flow generated was $13.4 million compared to $51.1 million in 2019. Cash flow represents netback inclusive of G&A costs, realized gain (losses) on commodity contracts and all other cash transactions; and, At December 31, 2020, the Company had cash of $9.6 million, compared to $21.1 million at the end of 2019. December 31, 2020 Subsequent events - - - - - On January 19, 2021, the Company executed final agreement with Petroperu, restructuring the contingent derivative liability over three years and extending the oil sales contract with Petroperu for an additional two years. The amount of the contingent liability represented $16.6 million (based on the November 30, 2020 valuation) and was subsequently paid out (along with the $3 million Peruvian-government COVID emergency response loan), from the successful $100 million bond offering; On February 2, 2021, the Company announced completion of a 3-year $100 million senior secured bond with an annual 12% coupon, issued at a 5% discount. The bonds issued by PetroTal are the Company’s only interest bearing debt and the proceeds are for payout of the Petroperu derivative liability with Petroperu and Reactiva loan, totaling $20 million, to support the Company’s crude oil price hedging strategy ($15 million), to finance potential acquisitions ($20 million), with the remainder for continued development of the Bretana oil field; On February 18, 2021, the Company announced its 2021 capital development program of $100 million, to be funded from the bond proceeds and internally generated funds from operations, along with existing cash resources; The Company has hedged approximately 32% of expected April to December 2021 oil production. Additionally, Petroperu has now hedged 100% of oil sales through the ONP. This robust hedging program will ensure funding stability to support the 2021 capital development program should Brent oil price drop materially; and, Pursuant to the Company’s oil market diversification strategy, in Q1 2021 the Company completed a second shipment of 225,000 barrels of oil through Brazil for export into the Atlantic region. The oil sale was FOB Bretana and generated revenue of $8.8 million. 13 4. OUTLOOK AND GROWTH STRATEGY Outlook The capital program prioritizes management's strategy to maintain a strong balance sheet during the period of low oil prices, maximizing activity to fit within cash flow. The Company activity will focus on managing existing production and drilling new wells during 2021. Base maintenance capital would require capital expenditures and additional activities included in the capital program outlined as follows: - - - Completion of production facilities and infrastructure activities which include optimization of existing facilities, wells and some improvements aimed at lowering operating costs; Drilling new wells focused on continuing development in the core area of Bretana oilfield; Continued investment in environmental remediation and social initiatives as part of a sustained long-term effort to improve the physical environment, and to provide training programs and other community initiatives for the residents near the Company’s operations. The capital budget is based on the expected average annual Brent oil price forecast of $50/bbl. Additionally, the Company will continue with an appropriate oil price hedging strategy for the future. Growth strategy PetroTal’s strategy is focused on petroleum assets that have long-life reserves with production growth potential. Employing its knowledge base and technical expertise, the Company is working to optimize its existing assets primary through drilling new oil wells to create long- term value for shareholders. This will be accomplished through the attainment of its main objectives: increasing production, reserves, funds generated from operations and net asset value. PetroTal’s strategic priorities are to: Increase reserves and production; - - Maintain a strong balance sheet by controlling and managing capital expenditures; - - - - - Maintain a strong focus on employee, contractor and community health and safety; and - Manage environmental and social performance to minimize negative ecological impacts and ensure continued Control costs through efficient management of operations; Pursue new and proven technology applications to improve operations and assist exploration endeavors; Expand infrastructure (pipelines, storage, treating capacity) to increase production capacity in a cost-effective manner; Explore undeveloped acreage to identify and create development opportunities; stakeholder support. Throughout the year, PetroTal focused on achieving its priorities and implementing its capital programs in Peru. The Company will fund its capital development program using funds generated from operations and existing cash. Strategic allocation of the work program and budget is designated to provide additional recoverable reserves at the Peruvian oilfields and achieve production growth. 14 5. SELECTED FINANCIAL INFORMATION 5.1 QUARTERLY SUMMARY The field was shut in on May 7, 2020, for the 37 producing days in Q2 2020, production averaged 11,500 bopd. The field was shut in from July 1 to July 14 and from August 9 to September 27, for the 28 producing days in Q3 2020, production averaged 8,000 bopd. EARNINGS STATEMENT INFORMATION Revenue Sales increased to 2,086,226 barrels (5,700 bopd) in 2020, an increase from 1,474,042 barrels (4,033 bopd) in 2019. Sales for Q4 2020 were 5,471 bopd as compared to Q3 2020 of 2,327 bopd and 9,509 bopd in Q4 2019. The Company sells its oil at various sales points. Approximately 1,300 bopd is delivered to the Iquitos refinery priced at the prevailing Brent oil price less a discount inclusive of barge transportation charges. The majority of the oil is delivered and sold to Petroperu at the Saramuro pump station for transportation through the ONP and onward to the Bayovar Port. The price is based on the average monthly Brent oil price, less approximately $4.00/bbl as a quality differential, and is net of all pipeline and marketing fees. When the oil is ultimately sold by Petroperu at Bayovar, PetroTal is subject to a valuation adjustment based on the actual price achieved by 15 Petroperu, whether higher or lower. Annual revenue decreased to $76.6 million ($36.71/bbl) in 2020 from $82.8 million ($52.32/bbl) in 2019. Similarly, sales volumes resulted in Q4 2020 revenue of $17.4 million ($34.52/bbl) compared to $50.5 million ($57.71/bbl) for Q4 2019. Fluctuations in oil sales volumes and revenues were impacted by the global oil price collapse, COVID-19 pandemic and temporary oilfield closures as a result of the pandemic and community/government social issues. Royalties remained consistent, and on a per barrel decreased (2020 -$1.38/bbl) on an absolute basis compared to 2019 ($2.31/bbl) due to the reduction in global oil prices. Royalties on production from the Bretana oilfield are calculated on production, and range between 5% and 20%. The royalty calculation is 5% based on production of 5,000 bopd or less and 20% when production reaches 100,000 bopd or more, with a straight-line calculation between. The royalty regime in Peru is negotiated on a block by block basis, based either on production scales or on economic results. Operating expense in 2020 were $15.7 million ($7.51/bbl), as compared $14.3 million ($9.73/bbl) in 2019. This 23% reduction, on a per barrel basis, is reflective of the mostly fixed costs being allocated over increased oil production, along with negotiated cost reductions. As production increases and oilfield operations are normalized, operating costs, on a per barrel basis, should be reduced further. Transportation expense in 2020 totaled $29.2 million ($13.98/bbl), representing barging, diluent blending and pipeline costs, as compared to $23.4 million ($15.87/bbl) in 2019. Fluctuations are reflective of oil volumes, sales delivery point and transportation timing. General and administrative expense in 2020 was $10.6 million ($5.07/bbl), as compared to $10.8 million ($7.33/bbl) in 2019. Compensation reductions for all employees, inclusive of 20% reductions for management and directors, offset increased costs related to the COVID pandemic and enhanced community support efforts. As production increases, the per barrel cost of G&A will continue to improve. Included in G&A is construction of a new pier for community residents and additional COVID support to the Bretana and neighboring communities. PetroTal recognizes the importance of community alignment and support over the areas in which it operates. 16 The Company capitalized and allocated $2.6 million of G&A compared to $3.1 million in 2019. For the year ended December 31, 2020, non-cash share-based compensation pertaining to performance share units granted to employees was $0.9 million (2019: $0.4 million). Depletion, Depreciation and Amortization (“DD&A”) for 2020 was $12.9 million ($6.22/bbl) as compared to $8.5 million ($5.79/bbl) for 2019. DD&A was determined using the updated annual reserve report information prepared by NSAI at December 31, 2020. On a quarterly basis, the Q4 DD&A is $3.1 million ($6.30/bbl) as compared to $3.8 million ($4.30/bbl) in Q4 2019. DD&A is calculated based on capital invested, production and 2P reserves. Derivative loss of $4.8 million in 2020 is the net fair value of outstanding embedded derivatives, compared to $0.4 million in 2019. The oil sales agreement with Petroperu for sales into the ONP are subject to oil price variations when sold by Petroperu upon arrival at the Bayovar port. Impairment and FX expenses mainly related to the relinquishment of exploratory Block 133 ($0.4 million) expensed during 2019, compared to a $42 thousand foreign expense gain during 2020. Deferred tax expense of $75 thousand was recorded in 2020 compared to $86 thousand in 2019. Financial expense of $2.0 million is mainly related to accretion of decommissioning obligation expense, as compared to $0.4 million accretion expensed during 2019. Reclassification The Company has reclassified its operating expenses to separate out the transportation component from operating expenses and present it separately. The Company has made this change to reflect how management views the performance and disclosure of its operations. The Company has reclassified these costs in the statements of earnings (loss) and comprehensive income (loss). Historical results were reclassified to match the current period presentation. This change did not result in a change in income (loss) before taxes or cash flows from operations. Management believes the reclassifications described below, now align with the nature of the costs presented with the assessment of performance of the company. 5.2 BALANCE SHEET INFORMATION 17 Cash and liquidity At December 31, 2020, the Company held cash of $9.6 million, an $11.5 million reduction from $21.1 million at year-end 2019. The working capital deficiency was $22.2 million at December 31, 2020 as compared to a working capital deficiency of $11.8 million at December 31, 2019. The variance resulted primarily from revenue reduction and increased derivative obligations, both associated with lower global oil prices. Expected oil production increases, as a result of the 2021 capital development program, in conjunction with higher oil prices, establishes the basis for higher cash flow. PetroTal completed a $100 million bond issue in February 2021 that enhanced liquidity significantly, and the Company maintains spending flexibility in all areas, with minimal capital expenditure commitments. VAT receivable Valued Added Tax (VAT) in Peru is levied on the purchase of goods and services and is recoverable on sales of goods and services. The Company recovered $14.6 million during 2020 and expects to recover $10.2 million in the short term based on its estimated oil sales. Trade and other receivables As at December 31, 2020, trade receivables represent revenue related to the sale of crude oil and amounts to be received in the short term. No credit losses on the Company’s trade accounts have been incurred. Capital expenditures The Company primary focus was to increase oil production and building on the success of reactivating the previously-drilled and shut- in initial discovery wells in 2019. The Company incurred $42.3 million of capital expenditures in 2020 compared to $88.8 million in 2019. Early in 2020, one successful oil well was drilled and placed on production. The COVID pandemic curtailed any further drilling in 2020, and the drilling rig and related equipment were placed on reduced standby rates, pursuant to the contracts. In 2019, four successful oil wells were drilled, and the Company converted the initial water disposal well into a producing oil well. Also in 2019, a new water disposal well was drilled into the lower flank of the field with the water being injected at this level supporting aquifer maintenance and serving to enhance oil production. The second focus was on ensuring the Company had adequate facilities to effectively and efficiently handle the increased production. The Company opted for a modular construction format whereby contractors’ design and build the components at manufacturing locations. The components are then transported to and fully assembled at the Bretana oil field. This enhances construction quality and is a cost effective solution for such major infrastructure. The initial phase of the Central Production Facility (“CPF”) was completed and commissioning commenced in early 2020. This CPF, along with the Long Term Testing (“LTT”) equipment, is expected to easily handle 15,000 bopd and beyond. Additional production facilities will be added as needed when production from continued drilling 18 warrants. Some investments were made in exploration Block 107 for permits and maintenance to ensure PetroTal will be in a position to bring in a joint venture partner in the future. Along with the $0.8 million pier built and installed for residents of the Bretana community, the Company continues to invest in a variety of community, social and regulatory (“CSR”) initiatives. An emphasis on environmental, social and governance (“ESG”) is prevalent throughout all areas of our operations. At year end 2020 and 2019, the Company has approximately $5 million of exploration and evaluation assets related to exploration Block 107. Trade and other payables As at December 31, 2020, trade payables and accruals are primarily related to the drilling and completion of wells, along with construction of production processing facilities. The overall payable amount decreased due to payments performed during the year. The Company have secured accommodations with vendors to maintain commercial and extended payment terms. Derivatives (1) Sales have been completed The embedded derivative liability is classified as Level 2 fair value measurement. The service contract for transport of liquid hydrocarbons of the North-Peruvian Oil Pipeline (“ONP”) and Petroperu Saramuro agreements signed with Petroperu during 2020, 19 include a clause to adjust the risk of volatility of the international price of crude oil during the period in which Petroperu provides the service of crude oil usage and until the Company returns the full amount of the volumes that were delivered in advance. The price compensation is based on the 2 day average Brent oil price marker quotes (Brent Platts and Brent ICE) to the points of shipment and returns. In case the average price shipment is greater than the average price return, the Company will compensate Petroperu an amount equivalent to the difference between both averages, multiplied by the volume sold or arranged by Petroperu. If the average price shipment is lower than the average price return, the Company will be compensated by Petroperu. The fair value of the embedded derivative, considering an average future Brent price marker differential, was recorded as a loss on commodity price derivatives at December 31, 2020. At year ended 2020, 1.8 million barrels were delivered to and sold into the ONP, and remain in the pipeline or storage tanks, awaiting final sale by Petroperu and are subject to the same settlement terms as noted above in the ONP contract. Decommissioning obligations The undiscounted uninflated value of its estimated decommissioning liabilities is $23.7 million which includes an addition of $0.7 million related to the drilling campaign of the Company in the Bretana oil field, liabilities settled of $0.3 million, and revisions to decommissioning of $2.7 million. The present value of the obligations was calculated using an average risk-free rate of 2.8% (December 31, 2019: 3.3%) to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimates ranges from 1.9% to 2.0%. The table below sets out the continuity of decommissioning obligations. Share capital Authorized share capital consists of an unlimited number of common shares without nominal or par value. The holders of common shares are entitled to one vote per share and are entitled to receive dividends as recommended by the Board of Directors. On June 18, 2020, the Company completed an equity issue, raising gross proceeds of approximately $18 million (at 10 pence per unit) upon issuance of 141.2 million of units. Each unit is comprised of one common share and one half of one warrant allowing the subscriber to purchase additional shares within 36 months at 16 pence/share upon presentation of a full warrant. In June 2019, the Company issued equity for gross proceeds of $25.5 million upon the issuance of 133.3 million of shares, and had agents warrants exercised and converted into 1.1 million shares for net proceeds of $0.2 million. In December 2019, PetroTal declared a dividend of $0.9 million to all shareholders which was paid in January 2020. As of April 21, 2021, PetroTal has the following securities outstanding: Common shares Performance share units Performance warrants Total 816,667,379 21,889,414 96,351,946 934,908,739 88% 2% 10% 100% 20 5.3 NON-GAAP TERMS This report contains financial terms that are not considered measures under GAAP such as operating netback, operating netback per bbl, transportation and revenues adjusted, funds flow provided by operations, funds flow provided by operations per bbl, funds flow netback per bbl, free funds flow and diluted funds flow per share that do not have any standardized meaning under GAAP and may not be comparable to similar measures presented by other companies. Management uses these non-GAAP measures for its own performance measurement and to provide shareholders and investors with additional measurements of the Company’s efficiency and its ability to fund a portion of its future capital expenditures. Revenue and transportation expense adjustment Revenue and transportation expense adjustment are non-GAAP measure, that includes in transportation ONP pipeline tariff, marketing fee, barging and diluent expenses. Tariff and marketing fees are expenses usually recorded by reducing revenues in the financial statements. Management believes the reclassifications described below, now align with the nature of the costs presented with the assessment of performance of the company. Q4-2020 before reclass 15,149 (5,021) Q4-2020 after reclass 17,374 (7,246) FY 2020 before reclass FY 2020 after reclass 61,740 (14,322) 76,593 (29,175) Q4-2019 before reclass 45,916 (9,702) Q4-2019 after reclass FY 2019 before reclass FY 2019 after reclass 50,483 (14,269) 77,024 (17,592) 82,789 (23,357) Revenues Transportation Funds flow information Funds flow provided by operations (“FFO”), is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. A reconciliation from cash provided by operating activities to funds flow provided by operations is as follows: Funds flow netback is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. The Company considers funds flow netback to be a key measure as it demonstrates Company’s profitability after all cash costs relative to current commodity prices. FFO after investing activities is a non-GAAP measure and the Company considers free funds flow or free cash flow to be a key measure as it demonstrates Company’s ability to fund a return of capital without accessing outside funds and is calculated as follows: 21 Operating netback The Company considers operating netbacks to be a key measure as they demonstrate Company’s profitability relative to current commodity prices. Netback is calculated by dividing net operating income by total revenue. 6. 2020 RESERVE REPORT Block 95 - Bretana oil field Oil production commenced in Bretana in June 2018 via a long-term testing program of the single oil producer. In May 2019, the Company received the approval of the Environmental Impact Assessment (“EIA”) to fully develop the Bretana field in Block 95. This approval provided PetroTal with the necessary permits to execute its development strategy at Bretana. The summary below sets forth PetroTal’s reserves as at December 31, 2020, as presented by NSAI, a qualified independent reserves evaluator. The figures in the following tables have been prepared in accordance with the standards contained in the most recent publication of the Canadian Oil and Gas Evaluation Handbook (“COGE”) and the reserve definitions contained in National Instrument 51- 101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). More detailed information will be included in PetroTal’s (“AIF”) for the year ended December 31, 2020 posted on SEDAR (www.sedar.com) and on PetroTal’s website. Summary of oil reserves and net present values as of December 31, 2020 Company Heavy Oil Reserves (mmbbl) Future Net Revenue Before Income Taxes Discounted at (in USD Million) Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved & Probable Possible Total Proved & Probable & Possible Gross 12.0 10.3 22.3 28.7 51.0 55.1 Net 12.0 10.3 22.3 28.7 51.0 55.1 106.1 106.1 0% 133 316 5% 137 237 449 374 1,124 1,573 2,405 3,978 734 1,108 1,372 2,480 10% 15% 134 183 317 513 830 891 129 144 273 379 652 632 20% 123 115 238 292 530 477 1,721 1,284 1,007 Summary of Pricing and Inflation Rate Assumptions – Forecast Prices and Costs (US$/bbl) Year-End Forecast: Brent January 1, 2020 Brent January 1, 2019 2021 $49.42 $67.94 2022 $52.85 $70.06 2023 $56.04 $71.66 2024 $57.87 $73.27 2025 $59.00 $74.57 2026 $60.15 $76.22 Year-End Crude Oil Reserves (mmbbl) Category Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved plus Probable Possible Total Proved plus Probable & Possible 2020 12.0 10.3 22.3 28.7 51.0 55.1 106.1 2019 11.2 10.3 21.5 26.2 47.7 37.1 84.8 Change 7% 0% 4% 10% 7% 49% 25% 22 Year-End Net Present Value at 10% - before income tax ($ millions) Category Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved plus Probable Possible Total Proved plus Probable & Possible 2020 $135 $182 $317 $513 $830 $891 $1,721 2019 $202 $232 $434 $664 $1,098 $777 $1,875 Change -33% -22% -27% -23% -24% 15% -8% Year-End Net Asset Value ("NAV") per Share – after tax Category Proved Proved plus Probable Proved plus Probable & Possible Reserve Life Index (“RLI”) Category Proved Proved plus Probable Proved plus Probable & Possible Future Development Costs December 31, 2020 December 31, 2019 US$/sh $0.33 $0.76 $1.50 CAD$/sh $0.43 $0.98 $1.93 US$/sh $0.44 $1.11 $1.90 CAD$/sh $0.59 $1.48 $2.53 December 31, 2020 6.4 years 30.3 years The following information sets forth development and abandonment costs deducted in the estimation of PetroTal’s future net revenue attributable to the reserve categories noted below: $119 million Proved Proved & Probable $193 million Proved & Probable & Possible $297 million The future development and abandonment costs are estimates of capital expenditures required in the future for PetroTal to convert the corresponding reserves to proved developed producing reserves. As a result of the Company’s successful drilling program 2020 Proved ("1P") reserves increased by 4%, to 22.3 million barrels ("mmbbl") from 21.5 mmbbl, Proved plus Probable ("2P") reserves increased by 7% to 51.0 mmbbl from 47.7 mmbbl, and Proved plus Probable and Possible ("3P") reserves increased by 25% to 106.1 mmbbl from 84.8 mmbbl. At year-end 2020, Net Present Value (before tax, discounted at 10%) (“NPV-10”) represents $317 million ($14.21/bbl) for 1P reserves, $830 million ($16.27/bbl) for 2P reserves and $1.7 billion ($16.22/bbl) for 3P reserves. Net Present Value (after tax, discounted at 10%) (“NPV-10”) represents $271 million ($12.15/bbl) for 1P reserves, $621 million ($12.17/bbl) for 2P reserves and $1.2 billion ($11.03/bbl) for 3P reserves. Bretana's reserve life index for 1P and 2P reserves is 6.4 years and 14.6 years, respectively. The cumulative capital invested combined with all future development and abandonment costs represents total finding and development costs of $5.32/bbl for 1P reserves, $3.79/bbl for 2P reserves and $2.80/bbl for 3P reserves. Original oil in place ("OOIP") estimates for 1P, 2P and 3P reserve categories were unchanged from 2019 at 235, 364 and 579 mmbbls, respectively. In addition to ongoing development of the Bretana oilfield, there are other prospects within Block 95 and exploration opportunities in Block 107. Exploratory Block 107 – Osheki 23 PetroTal has a 100% working interest in this 623,280 acre block, of which the Osheki prospect is estimated by NSAI to have 278.4 mmbbls of best estimate prospective recoverable oil resources. This estimate is based on a recovery factor of 28.5% of the estimated 970.7 million barrels of best estimate prospective OOIP, using maps generated from seismic acquired in 2007 and 2014. The best estimate risked prospective resources figure for the Osheki prospect is 44.0 mmbbls. The prospect was de-risked with a new 3D geologic model supporting Cretaceous age reservoirs with high quality Permian source rocks. Block 107 has four additional leads that, inclusive of Osheki, that could contain a total of 662 mmbbls barrels of recoverable resource in the high estimate case. One of them is the Constitucion Sur which has been upgraded to a prospect. The best estimate unrisked prospective resources figure for Constitucion Sur is 31.6 mmbbls. This estimate is based on a recovery factor of 29.1% of the 108.5 mmbbls best estimate OOIP. The best estimate of risked prospective resources figure for the Constitucion prospect is 3.2 mmbbls. Drilling permits for the Osheki prospect have been approved and the Company is working on the permits for Constitucion Sur which are expected in Q4 2021. PetroTal continues to seek joint venture partners for the Osheki prospect and other Block 107 leads. 7. SIGNIFICANT JUDGEMENTS AND ESTIMATES Management is required to make judgments, assumptions and estimates that have a significant impact on the Company’s financial results. Significant judgments in the Financial Statements include going concern, financing arrangements, impairment indicators, assessment of transfers from Exploration and Evaluation (“E&E”) to Property, Plant and Equipment (“PP&E”), asset acquisition and joint arrangements. Significant estimates in the Financial Statements include commitments, provision for future decommissioning obligations, recoverable amounts for exploration and evaluation assets and accruals. In addition, the Company uses estimates for numerous variables in the assessment of its assets for impairment purposes, including oil prices, exchange rates, discount rates, cost estimates and production profiles. By their nature, all of these estimates are subject to measurement uncertainty, may be beyond management’s control and the effect on future Financial Statements from changes in such estimates could be significant. Critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Financial Statements are included in the Financial Statements and the accompanying notes as of December 31, 2020 and 2019. Additional information about significant judgements and estimates are included in PetroTal’s audited Financial Statements for the years ended December 31, 2020 and 2019. 8. RELATED PARTY TRANSACTIONS AND TAXES The Company had no related party transactions or off-balance sheet arrangements. The Company’s key management includes the Directors and Officers. Taxes Peruvian law requires the Company to pay a 2% tax on gross revenue, which is booked as a deferred income tax asset and is recoverable once the prior net operating losses of approximately $212 million are exhausted. Due to prior net operating losses the Company does not anticipate having a significant tax liability for the next few years. At such time as there is a tax liability, the amounts pre-paid through the 2% payment will reduce the amount of future tax to be paid. Corporate tax rates for the Company’s license contracts in Peru are 32%. 9. CONTRACTUAL OBLIGATIONS AND COMMITMENTS As of December 31, 2020, the Company holds the following letters of credit guaranteeing its commitments for exploration blocks to Perupetro S.A.: Block 107 107 Beneficiary Perupetro S.A. Perupetro S.A. Amount $1,500 $1,500 $3,000 Commitment 1st exploration well, minimum work 5th exploratory period 2nd exploration well, minimum work 5th exploratory period Expiration December 2021 December 2021 24 10. FORWARD-LOOKING STATEMENTS AND RISKS FOREIGN EXCHANGE RATE RISK The Company’s functional currency is the United States dollar. Foreign exchange gains or losses can occur on translation of working capital denominated in currencies other than the functional currency of the jurisdiction which holds the working capital item. Excluding the impact of changes in the cross-rates, a 1% fluctuation in translation rates would have nil impact on net income or loss, based on foreign currency balances held at December 31, 2020. LIQUIDITY RISK Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. Company has no debt or loans with financial institutions. While the decrease in commodity prices as a result of the COVID-19 pandemic will negatively impact the Company’s financial performance and position, the subsequent events disclosed in Note 21 provides the Company with financial flexibility and the ability to meet obligations as they become due. The Company’s liquidity risk is impacted by current and future commodity prices. If required, the Company will also consider additional short-term financing or issuing equity in order to meet its future liabilities. Declines in future commodity prices could affect the Company’s ability to fund ongoing operations. The current challenging economic climate is having and may continue to have significant adverse impacts on the Company including, but not exclusively: • material declines in revenue and cash flows as a result of the decline in commodity prices; • • • • declines in revenue and operating activities due to reduced capital programs and the shut-in of production; inability to access financing sources; increased risk of non-performance by the Company’s customers and suppliers; and interruptions in operations as the Company adjusts personnel to the dynamic environment. The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on the Company is not known at this time. Estimates and judgments made by management in the preparation of the financial statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period. CREDIT RISK Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial loss to the Company. The Company’s VAT is primarily for sales tax credits on exploration and evaluation expenses incurred in prior years. These credits will be applied to future oil development activities or recovered as per the sale tax recovery legislation currently in effect. The majority of the Company’s trade receivable balances relate to crude oil sales to one customer, being Petroperu, a state owned company. Recently, the Company signed a long term sales agreement and initiated exports through Brazil, with and oil trading company, whereby sales are FOB Bretana, and secured by a letter of credit. The Company’s policy is to enter into agreements with customers that are well established and well financed entities in the oil and gas industry, including Petroperu, such that the level of risk is mitigated. The Company has not experienced any material credit losses in the collection of its trade receivables. Impairment to a financial asset is only recorded when there is objective evidence of impairment and the loss event has an impact on future cash flow and can be reliably estimated. Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. Management believes that there is no risk on the recoverability and or applicability of the sales tax credits. Therefore, no impairment to the carrying value of these assets has been estimated. The Company has deposited its cash and cash equivalents with reputable financial institutions, with which management believes the risk of loss to be remote. The maximum credit exposure associated with financial assets is their carrying value. At December 31, 2020, the cash and cash equivalents were held with seven different institutions from three countries, mitigating the credit risk of a collapse of one particular bank. WORKFORCE MAY BE EXPOSED TO WIDESPREAD PANDEMIC PetroTal operations are located in areas relatively remote from local towns and villages and represent a concentration of personnel working and residing in close proximity to one another. Should an employee or visitor become infected with a serious illness that has the potential to spread rapidly, this could place workforce at risk. The 2019/2020 outbreak of the novel coronavirus in China and other countries around the world is one example of such an illness. The Company takes every precaution to strictly follow industrial hygiene and occupational health guidelines. There can be no assurance that this virus or another infectious illness will not impact company’s personnel and ultimately its operations. 25 Additional information regarding risk factors including, but not limited to, risks related to political developments in Peru and environmental risks is available in the Company’s AIF, a copy of which may be accessed through the SEDAR website (www.sedar.com). Certain statements contained in this MD&A may constitute forward-looking statements. These statements relate to future events or the Company’s future performance, including, but not limited to: PetroTal's business strategy, objectives, strength, focus and outlook, drilling, completions, workovers and other activities including expanding infrastructure and exploring undeveloped acreage and the anticipated costs and results of such activities, environmental remediation and social initiatives, the ability of the Company to achieve drilling success consistent with management's expectations, anticipated future production and revenue, oil production levels, the 2021 capital program and budget, including drilling plans, balance sheet strength, COVID-19 surveillance and control process, hedging program and the terms thereof, and future development and growth prospects. All statements other than statements of historical fact may be forward-looking statements. In addition, statements relating to expected production, reserves, prospective resources, recovery, costs and valuation are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Forward-looking statements are often, but not always, identified by the use of words such as “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. The forward-looking statements are based on certain key expectations and assumptions made by the Company, including, but not limited to, expectations and assumptions concerning the ability of existing infrastructure to deliver production and the anticipated capital expenditures associated therewith, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices and the actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labor, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the accuracy of PetroTal's geological interpretation of its drilling and land opportunities, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance of new wells, the Company's growth strategy, general economic conditions and availability of required equipment and services. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. The Company believes that the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon by investors. These statements speak only as of the date of this MD&A and are expressly qualified, in their entirety, by this cautionary statement. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of reserve estimates, the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price volatility, price differentials and the actual prices received for products, exchange rate fluctuations, legal, political and economic instability in Peru, access to transportation routes and markets for the Company's production, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. In addition, the Company cautions that current global uncertainty with respect to the spread of the COVID-19 virus and its effect on the broader global economy may have a significant negative effect on the Company. While the precise impact of the COVID-19 virus on the Company remains unknown, rapid spread of the COVID-19 virus may continue to have a material adverse effect on global economic activity, and may continue to result in volatility and disruption to global supply chains, operations, mobility of people and the financial markets, which could affect interest rates, credit ratings, credit risk, inflation, business, financial conditions, results of operations and other factors relevant to the Company. Please refer to the risk factors identified in the AIF which is available on SEDAR at www.sedar.com. Although the Company believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. The Company cannot guarantee future results, levels of activity, performance, or achievements. The risks and other factors, some of which are beyond the Company’s control, could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A. The forward-looking statements contained in this MD&A are expressly qualified by the foregoing cautionary statement. Subject to applicable securities laws, the Company is under no duty to update any of the forward-looking statements after the date hereof or to compare such statements to actual results or changes in the Company’s expectations. Financial outlook information contained in this 26 MD&A about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information should not be used for purposes other than for which it is disclosed herein. Prospective resources are the quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Estimates of prospective resources included in this document relating to the Osheki prospect are based upon an independent assessment completed by NSAI with an effective date of September 30, 2018, and prepared in accordance with the COGE and the standards established by NI 51-101. For additional information about the Company’s prospective resources, see the Company’s press release dated September 12, 2018. 27 ADDITIONAL INFORMATION Additional information about PetroTal Corp. and its business activities, including PetroTal’s AIF and audited Financial Statements for the years ended December 31, 2020 and 2019 are available on the Company's website at www.petrotal-corp.com, and at www.sedar.com, or below: DIRECTORS Mark McComiskey Chair of the Board Eleanor Barker Ryan Ellson Gary Guidry Roger Tucker Gavin Wilson Manuel Pablo Zuniga-Pflucker OFFICERS AND SENIOR EXECUTIVES Manuel Pablo Zuniga-Pflucker President and Chief Executive Officer Douglas Urch EVP and Chief Financial Officer Estuardo Alvarez-Calderon VP Exploration and Production Glen Priestley VP Treasury and Planning Ronald Egusquiza Peru General Manager CORPORATE HEADQUARTERS PetroTal Corp. 11451 Katy Freeway, Suite 500 Houston, Texas 77079 Office: 713.609.9101 info@petrotal-corp.com www.petrotal-corp.com LEGAL COUNSEL Stikeman Elliott LLP Calgary, Alberta AUDITORS Deloitte LLP Calgary, Alberta REGISTERED OFFICE PetroTal Corp. 4300 Bankers Hall West, 888-3rd Street Calgary, Alberta NOMINATED & FINANCIAL ADVISER Strand Hanson Limited London, United Kingdom OPERATING OFFICE PetroTal Peru SRL Calle Andres Reyes 437, Piso 8 Edificio Platinum Plaza Torre 2 – San Isidro Lima, Peru JOINT BROKERS Stifel Nicolaus Europe Limited London, United Kingdom Auctus Advisors LLP London, United Kingdom STOCK EXCHANGES TSX Venture Exchange Toronto, Canada TSXV: TAL AIM Stock Exchange London, United Kingdom AIM: PTAL OTC Stock Exchange New York, USA OTC: PTALF RESERVES EVALUATORS Netherland, Sewell & Associates, Inc. Dallas, Texas TRANSFER AGENT AND REGISTRAR Computershare Trust Company of Canada Calgary, Alberta London, United Kingdom Equity Stock Transfer New York, NY GLOSSARY / ABBREVIATIONS MD&A IFRS CPF bbl(s) mbbls mmbbl bopd COGE NI 51-101 AIF ONP Netback LTT OOIP Management’s Discussion and Analysis International Financial Reporting Standards Central Production Facility Barrel(s) Thousand barrels Million barrels Barrels of oil per day Canadian Oil and Gas Evaluation handbook National Instruments - Standards of Disclosure for Oil and Gas Activities Annual Information Form North Peruvian Oil pipeline agreement Benchmark to assess the profitability based on revenues less royalties, operating and transportation costs Long Term Testing Original Oil in Place 28 TSXV: TAL / AIM: PTAL / OTC : PTALF AUDITED CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2020 and 2019 AUDITED CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2020 and 2019 TSXV: TAL / AIM: PTAL / OTC: PTALF TABLE OF CONTENTS 1. Management’s report ……………………………………………………………………………………………………. 2. Independent auditor’s report ………………………………………………………………………………………… 3. Consolidated balance sheets………………………………………………………………………………………….. 4. Consolidated statements of earnings (loss) and comprehensive income (loss)……………….. 5. Consolidated statements of changes in equity……………………………………………………………….. 6. Consolidated statements of cash flows ………………………………….………………………………….….. 7. Notes to the Consolidated Financial Statements ………………….……………………………………….. 3 4 6 7 8 9 10 30 MANAGEMENT’S REPORT The accompanying audited Consolidated Financial Statements and all information in the management discussion and analysis and notes to the Consolidated Financial Statements are the responsibility of management. The Consolidated Financial Statements were prepared by management in accordance with International Accounting Standards outlined in the notes to the Consolidated Financial Statements. Other financial information appearing throughout the report is presented on a basis consistent with the Consolidated Financial Statements. Management maintains appropriate systems of internal controls. Policies and procedures are designed to give reasonable assurance that transactions are appropriately authorized, assets are safeguarded, and financial records properly maintained to provide reliable information for the presentation of Consolidated Financial Statements. The Audit Committee meets quarterly with management and the independent auditors to review auditing matters, financial reporting issues, and to satisfy itself that all parties are properly discharging their responsibilities. The Audit Committee also reviews the Consolidated Financial Statements, the management’s discussion and analysis of financial results, and the independent auditor’s report. The Audit Committee reports its findings to the Board of Directors for its approval of the Consolidated Financial Statements for issuance to the shareholders. The Consolidated Financial Statements have been audited, on behalf of the shareholders, by the Company’s independent auditors, in accordance with Canadian generally accepted auditing standards. Independent auditor has full and free access to the Audit Committee. Signed “Manuel Pablo Zuniga-Pflucker” Manuel Pablo Zuniga-Pflucker Chief Executive Officer Signed “Douglas Urch” Douglas Urch Chief Financial Officer April 21, 2021 31 Deloitte LLP 700, 850 2 Street SW Calgary, AB T2P 0R8 Canada Tel: 403-267-1700 Fax: 587-774-5379 www.deloitte.ca Independent Auditor's Report To the Shareholders of PetroTal Corp. Opinion We have audited the consolidated financial statements of PetroTal Corp. (the "Company"), which comprise the consolidated balance sheets as at December 31, 2020 and 2019, and the consolidated statements of earnings (loss) and comprehensive income (loss), changes in equity and cash flows for the years then ended, and notes to the consolidated financial statements, including a summary of significant accounting policies (collectively referred to as the "financial statements"). In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2020 and 2019, and its financial performance and its cash flows for the years then ended in accordance with International Financial Reporting Standards ("IFRS"). Basis for Opinion We conducted our audit in accordance with Canadian generally accepted auditing standards ("Canadian GAAS"). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the financial statements in Canada, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Other Information Management is responsible for the other information. The other information comprises of the Management’s Discussion and Analysis. Our opinion on the financial statements does not cover the other information and we do not and will not express any form of assurance conclusion thereon. In connection with our audit of the financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated. We obtained Management’s Discussion and Analysis prior to the date of this auditor’s report. If, based on the work we have performed on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact in this auditor’s report. We have nothing to report in this regard. 32 Responsibilities of Management and Those Charged with Governance for the Financial Statements Management is responsible for the preparation and fair presentation of the financial statements in accordance with IFRS, and for such internal control as management determines is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error. In preparing the financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so. Those charged with governance are responsible for overseeing the Company's financial reporting process. Auditor's Responsibilities for the Audit of the Financial Statements Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian GAAS will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements. As part of an audit in accordance with Canadian GAAS, we exercise professional judgment and maintain professional skepticism throughout the audit. We also: • Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. • Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management. • Conclude on the appropriateness of management’s use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial statements or, if such disclosures are inadequate, to 33 modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern. • Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation. • Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Company to express an opinion on the financial statements. We are responsible for the direction, supervision and performance of the group audit. We remain solely responsible for our audit opinion. We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. We also provide those charged with governance with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards. The engagement partner on the audit resulting in this independent auditor’s report is David Langlois. Chartered Professional Accountants Calgary, Alberta April 21, 2021 34 35 36 37 38 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2020 and 2019. All amounts are stated in thousands of United States Dollars ($) unless otherwise indicated. 1. CORPORATE INFORMATION PetroTal Corp. (the “Company” or “PetroTal”) is a publicly-traded energy company incorporated and domiciled in Canada. The Company is engaged in the exploration, appraisal and development of crude oil and natural gas in Peru, South America. The Company’s registered office is located at 4300 Bankers Hall West, 888 –3rd Street S.W., Calgary, Alberta, Canada. These Consolidated Financial Statements (the “Financial Statements”) have been prepared on a going concern basis, which assumes that the Company will continue its operations for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of business. The Company evaluated subsequent events (Note 22) and transactions that occurred after the balance sheet date up to the date that the Financial Statements were issued. Management is currently evaluating the impact of the pandemic on the industry and has concluded that while it is reasonably possible that the virus could have a negative effect of the Company’s financial position, results of its operations, the specific impact is not readily determinable as of the date of these Financial Statements. The Financial Statements do not include any adjustment that might result from the outcome of this uncertainty. These Financial Statements were approved for issuance by the Company’s Board of Directors on April 21, 2021, on the recommendation of the Audit Committee. 2. BASIS OF PREPARATION STATEMENT OF COMPLIANCE The Company prepares its annual Financial Statements in accordance with International Financial Reporting Standards (“IFRS”). BASIS OF MEASUREMENT These Financial Statements have been prepared on a historical cost basis except for certain financial instruments that have been measured at fair value. In addition, these Financial Statements have been prepared using the accrual basis of accounting. PRINCIPLES OF CONSOLIDATION The Company’s Financial Statements include the accounts of the Company and its subsidiaries. The Financial Statements of the subsidiaries are prepared for the same reporting period as the parent company’s, using consistent accounting practices. Inter-company balances and transactions, and any unrealized gains arising from inter-company transactions with the Company’s subsidiaries, were eliminated on consolidation. The entities included in the Company’s Financial Statements are PetroTal Corp. and its 100% owned subsidiaries PetroTal USA Corp., PetroTal LLC, PetroTal Energy International (Peru) Holdings B.V., PetroTal Peru B.V., Petrolifera Petroleum Del Peru S.R.L. and PetroTal Peru S.R.L. RECLASSIFICATION For 2019, the Company has reclassified its operating expenses to separate out the transportation component from operating expenses and present it separately. The Company has made this change to reflect how management views the performance and disclosure of its operations. The Company has reclassified these costs in the consolidated statements of earnings (loss) and comprehensive income (loss). Historical results were reclassified to match the current period presentation. This change did not result in a change to income (loss) before taxes or cash flows from operations. Management believes the reclassifications described below, now align with the nature of the costs presented with the assessment of performance of the Company. 39 USES OF ACCOUNTING ASSUMPTIONS, ESTIMATES AND JUDGMENTS The preparation of the Company’s Financial Statements requires management to make judgement, estimates, and assumptions that affect the application of accounting policies and the reported amount of assets, liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and other factors that are considered relevant. Actual results may differ from estimates. The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the same period if the revision affects only that period or in the period of the revision and future periods if the revision affects current and future periods. Critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Financial Statements are summarized below: Functional Currency The functional currency of each of the Company’s entities is the United States dollar, which is the currency of the primary economic environment in which the entities operate. Exploration and Evaluation Assets The accounting for exploration and evaluation (“E&E”) assets requires management to make certain estimates and assumptions, including whether exploratory wells have discovered economically recoverable quantities of reserves. Designations are sometimes revised as new information becomes available. If an exploratory well encounters hydrocarbon, but further appraisal activity is required in order to conclude whether the hydrocarbons are economically recoverable, the well costs remain capitalized as long as sufficient progress is being made in assessing the economic and operating viability of the well. Criteria used in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected additional development activities, commercial evaluation and regulatory matters. The concept of “sufficient progress” is an area of judgment, and it is possible to have exploratory costs remain capitalized for several years while additional drilling is performed, or the Company seeks government, regulatory or partner approval of development plans. Petroleum and natural gas assets are grouped into cash generating units (“CGUs”) identified as having largely independent cash flows and are geographically integrated. The determination of the CGUs was based on management’s interpretation and judgement. Impairment Indicators The Company monitors internal and external indicators of impairment relating to the exploration and evaluation assets. Among others, the following are the types of indicators used: • • • • The entity’s right to explore in an area has expired during the period or will expire in the near future without renewal; No further exploration or evaluation work is planned or budgeted in the specific area; The decision to discontinue exploration and evaluation in an area because of the absence of commercial reserves; or Sufficient data exists to indicate that the book value will not be fully recovered from future development and production. The assessment of impairment indicators requires the exercise of judgment. If an impairment indicator exists, then the recoverable amounts of individual assets are determined based on the higher of value-in-use and fair values less costs of disposal calculations. These require the use of estimates and assumptions, such as future oil and natural gas prices, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves and operating performance. These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs. Decommissioning Obligations Decommissioning obligations will be incurred by the Company at the end of the operating life of wells or supporting infrastructure. The ultimate asset decommissioning costs and timing are uncertain and cost estimates can vary in response to many factors including changes to relevant legal and regulatory requirements, the emergence of new restoration techniques, experience at other production sites. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The expected amount of expenditure is estimated using a discounted cash flow calculation with a risk-free discount rate. Liabilities for environmental costs are recognized in the period in which they are incurred, normally when the asset is developed, and the associated costs can be estimated. 40 Deferred Tax Assets & Liabilities The estimation of income taxes includes evaluating the recoverability of deferred tax assets based on an assessment of the Company’s ability to utilize the underlying future tax deductions against future taxable income prior to expiry of those deductions. Management assesses whether it is probable that some or all of the deferred income tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income, which in turn is dependent upon the successful discovery, extraction, development and commercialization of oil and gas reserves. To the extent that management’s assessment of the Company’s ability to utilize future tax deductions changes, the Company would be required to recognize more or fewer deferred tax assets, and future income tax provisions or recoveries could be affected. The measurement of deferred income tax provision is subject to uncertainty associated with the timing of future events and changes in legislation, tax rates and interpretations by tax authorities. Provisions, Commitments and Contingent Liabilities Amounts recorded as provisions and amounts disclosed as commitments and contingent liabilities are estimated based on the terms of the related contracts and management’s best knowledge at the time of issuing the Consolidated Financial Statements. The actual results ultimately may differ from those estimates as future confirming events occur. SIGNIFICANT ACCOUNTING POLICIES a. Cash Cash includes deposits held with banks in Canada, the United States and Peru that are available on demand and highly liquid. b. Property, Plant and Equipment Property, plant and equipment (“PP&E”) is recorded at cost less accumulated depreciation. Depreciation begins when the asset is put into service and is calculated annually using the straight-line method. The cost of maintenance and repairs is charged to expense as incurred. The cost of significant renewals and improvements is added to the carrying amount of the respective asset. When assets are retired, or otherwise disposed of, the cost and related accumulated depreciation are removed from the balance, and any resulting gain or loss is reflected in the consolidated statements of earnings (loss) and comprehensive income (loss). c. d. When commercial production in an area has commenced, PP&E properties, excluding surface costs are depleted using the unit-of- production method over their proved plus probable reserve life. Proved plus probable reserves are determined annually by qualified independent reserve engineers. Changes in factors such as estimates of proved plus probable reserves that affect unit- of-production calculations are accounted for on a prospective basis. Leases Effective January 1, 2020 the Company adopted IFRS 16 – Leases, using the modified retrospective approach, which requires the cumulative effect of initial application to be recognized in retained earnings. IFRS 16 eliminates the distinction between operating and financing leases and provides a single lessee accounting model that requires the lessee to recognize assets and liabilities for all leases on its balance sheet. Leases to explore for or use oil or natural gas are specifically excluded from this scope. The Company excludes initial direct costs when measuring the amount of right-of-use assets, and apply a single discount rate to portfolios of leases with similar characteristics. Impairment Financial assets carried at amortized cost At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at amortized cost is impaired. If such evidence exists, the Company recognizes an impairment loss in net earnings (loss). Impairment losses are reversed in subsequent periods if the impairment loss decrease can be related objectively to an event occurring after the impairment was recognized. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. 41 Non-financial assets At each reporting date, the carrying amounts of the Company’s non-financial assets are reviewed to determine whether there is indication of impairment, except for E&E assets, which are reviewed when circumstances indicate impairment may exist. If there is indication of impairment, the asset's recoverable amount is estimated and compared to its carrying value. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the cash-generating unit). The recoverable amount of an asset or a cash-generating unit ("CGU") is the greater of its value in use and its fair value less costs to sell. The Company’s CGUs are not larger than a segment. In assessing both fair value less costs to sell and value in use, the estimated future cash flows are discounted to their present value using an after-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. An impairment loss is recognized if the carrying amount of an asset or its CGU (Company has a single segment) exceeds its estimated recoverable amount. Impairment losses are recognized in net earnings (loss). Fair value less costs to sell and value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. E&E assets are tested for impairment when they are transferred to petroleum properties and also if facts and circumstances suggest that the carrying amount of E&E assets may exceed the recoverable amount. Impairment indicators are evaluated at a CGU level. Indication of impairment includes: 1. Expiry or impending expiry of lease with no expectation of renewal 2. Lack of budget or plans for substantive expenditures on further E&E 3. Cessation of E&E activities due to a lack of commercially viable discoveries; and 4. Carrying amounts of E&E assets are unlikely to be recovered in full from a successful development project. e. f. Impairment losses recognized in prior years are assessed at each reporting date for indication that the loss has decreased or no longer exists. An impairment loss may be reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized. Inventory Inventory consists of oil crude and supplies to be used in the production and exploration activities, and is measured at the lesser of acquisition cost and net realizable value. The cost of oil crude inventory includes all costs incurred in bringing the inventory to its storage location. These costs, including operating expenses, royalties, transportation and depletion, are capitalized in the ending inventory balance. The cost of the inventory is recognized using the weighted average method. Financial Instruments Effective January 1, 2020, the Company adopted IFRS 9 - Financial Instruments, which replaced IAS 39 Financial Instruments: Recognition and Measurement. This standard introduced a single approach to determine whether a financial asset is measured at amortized cost or fair value. The approach is based on how an entity manages its financial instruments in the context of its business model and the contractual cash flow characteristics of its financial assets. For financial liabilities, IFRS 9 stipulates that where the fair value option is applied, the change in fair value resulting from an entity’s own credit risk is recorded in other comprehensive income (loss) rather than net earnings (loss), unless this creates an accounting mismatch. On initial recognition, financial instruments are measured at fair value. Measurement in subsequent periods depends on the classification of the financial instrument: • Fair value through profit or loss - subsequently carried at fair value with changes recognized in net earnings (loss). Financial instruments under this classification include cash and cash equivalents, and derivative commodity contracts; and • Amortized cost - subsequently carried at amortized cost using the effective interest rate method. Financial instruments under this classification includes accounts receivable, accounts payable and accrued liabilities and long-term debt. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Derivative instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting. As a result, the Company's policy is to classify all financial derivative contracts at fair value through profit or loss and to record them on the Consolidated Balance Sheet at fair value with a corresponding gain or loss in net earnings (loss). Attributable transaction costs are recognized in net earnings (loss) when incurred. 42 The estimated fair value of all derivative instruments is based on quoted market prices and/or third party market indications and forecasts. Embedded derivatives are derivatives embedded in a host contract. They are recorded separately from the host contract when their economic characteristics and risks are not closely related to those of the host contract; when the terms of the embedded derivatives are the same as those of a freestanding derivative; and when the combined contract is not measured at fair value through profit or loss. Refer to Note 14 for the classification and measurement of these financial instruments. Company adopted this standard using the modified retrospective approach, whereby the cumulative effect of initial adoption of the standard is recognized as an adjustment to retained earnings. There was no effect on the Company's retained earnings or prior period amounts as a result of adopting this standard. The Company’s financial instruments consist of cash, trade and other receivables, trade and other payables, and derivative obligations. These are included in current assets and current liabilities, respectively due to their short-term nature. The Company initially measures financial instruments at fair value. g. Exploration and Evaluation Assets E&E costs are those expenditures for an area where technical feasibility and commercial viability have not yet been determined. All costs directly associated with the exploration and evaluation of oil and natural gas reserves are initially capitalized. These costs include acquisition costs, exploration costs, geological and geophysical costs, decommissioning costs, E&E drilling, sampling and appraisals. Costs incurred prior to acquiring the legal rights to explore an area are expensed as incurred. At each reporting date, the carrying amounts of the Company’s exploration and evaluation assets are reviewed to determine whether there is any indication that those assets are impaired. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment, if any. The recoverable amount is the higher of fair value less costs to sell and value in use. If the recoverable amount of an asset is estimated to be less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount and the impairment loss is recognized in profit or loss for the year. The exploration and evaluation phase of a particular project is completed when both the technical feasibility and commercial viability of extracting oil or gas are demonstrable for the project or there is no prospect of a positive outcome for the project. Exploration and evaluation assets with commercial reserves will be reclassified to development and production assets and the carrying amounts will be assessed for impairment and adjusted (if appropriate) to their estimated recoverable amounts. When an area is determined to be technically feasible and commercially viable the accumulated costs are transferred to property, plant and equipment, where they are depleted. Exploration and evaluation assets are not amortized during the exploration and evaluation stage. When an area is determined not to be technically feasible and commercially viable or the Company decides not to continue with its activity, the unrecoverable costs are charged to comprehensive income (loss) as impairment of exploration and evaluation assets. h. Decommissioning Obligations The Company recognizes a decommissioning liability in relation to the evaluation and exploration assets and to property, plant and equipment, in the period in which a reasonable estimate of the fair value can be made of the statutory, contractual, constructive or legal liabilities associated with the retirement of the oil and gas properties, facilities and pipelines. The amount recognized is the estimated cost of decommissioning, discounted to its present value using a discount rate. The estimates are reviewed periodically. Changes in the provision resulting from changes to the timing of expenditures, costs or risk-free rates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment or exploration and evaluation assets. The unwinding of the discount on the decommissioning provision is charged to the consolidated statement of loss and comprehensive loss. Actual costs incurred upon settlement of the obligations are charged against the provision to the extent of the liability recorded and the remaining balance of the actual costs is recorded in the consolidated income statement. i. Income Taxes Income tax expense is comprised of current and deferred tax. Current tax and deferred tax are recognized in net income or loss except to the extent that it relates to a business combination or items recognized directly in equity or in other comprehensive income or loss. Current income taxes are recognized for the estimated income taxes payable or receivable on taxable income or loss for the current year and any adjustment to income taxes payable in respect of previous years. Current income taxes are determined using tax rates and tax laws that have been enacted or substantively enacted by the year- end date. Deferred tax assets and liabilities are recognized where the carrying amount of an asset or liability differs from its tax 43 base, except for taxable temporary differences arising on the initial recognition of goodwill and temporary differences arising on the initial recognition of an asset or liability in a transaction which is not a business combination and at the time of the transaction affects neither accounting nor taxable profit or loss. Recognition of deferred tax assets for unused tax losses, tax credits and deductible temporary differences is restricted to those instances where it is probable that future taxable profit will be available against which the deferred tax asset can be utilized. At the end of each reporting period the Company reassesses unrecognized deferred tax assets. The Company recognizes a previously unrecognized deferred tax asset to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered. j. Revenue Recognition Effective January 1, 2019, Company adopted IFRS 15 Revenue from Contracts with Customers, which replaced IAS 18 Revenue, IAS 11 Construction Contracts and related interpretations. This standard established a comprehensive framework for determining whether, how much and when revenue from contracts with customers is recognized. Under IFRS 15, revenue is recognized when a customer obtains control of the good or services as stipulated in a performance obligation. Determining whether the timing of the transfer of control is at a point in time or over time requires judgement and can significantly affect when revenue is recognized. In addition, the entity must also determine the transaction price and apply it correctly to the goods or services contained in the performance obligation. The Company's revenue is derived exclusively from contracts with customers. Revenue associated with the sale of crude oil and gas is measured based on the consideration specified in contracts with customers. Revenue from contracts with customers is recognized when the Company satisfies a performance obligation by transferring a good or service to a customer. A good or service is transferred when the customer obtains control of the good or service. The transfer of control of oil and gas usually coincides with title passing to the customer and the customer taking physical possession. Company mainly satisfies its performance obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant. Revenues from the sale of crude oil and gas are recognized by reference to actual volumes delivered at contracted delivery points and prices. Prices are determined by reference to quoted market prices in active markets, adjusted according to specific terms and conditions applicable per the sales contracts. Revenues are recognized prior to the deduction of transportation costs. Revenues are measured at the fair value of the consideration received. Company adopted this standard using the modified retrospective approach, whereby the cumulative effect of initial adoption of the standard is recognized as an adjustment to retained earnings. There was no effect on the Company's retained earnings or prior period amounts as a result of adopting this standard. k. l. Share Capital Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity. Foreign Currency Translation Transactions in foreign currencies are initially translated into the functional currency using the exchange rate on the transaction date. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the income statement. Each subsidiary in the group is measured using the currency of the primary economic environment in which the entity operates, which is its functional currency. m. Earnings per Share The Company presents basic and diluted earnings per share (“EPS”) data for its common shares (the “Common Shares”). Basic EPS is calculated by dividing the net profit or loss attributable to common shareholders of the Company by the weighted average number of Common Shares outstanding during the period. Diluted EPS is determined by dividing the net profit or loss attributable to common shareholders by the weighted average number of Common Shares outstanding during the year, plus the weighted average number of Common Shares that would be issued on conversion of all dilutive potential Common Shares into Common Shares. Those potential Common Shares comprise share options granted. n. Fair Value Measurements 44 Financial instruments recorded at fair value in the consolidated balance sheet (or for which fair value is disclosed in the notes to the Consolidated Financial Statements) are categorized based on the fair value hierarchy of inputs. The three levels in the hierarchy are described below: Level I Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide continuous pricing information. Level II Pricing inputs are other than quoted prices in active markets included in Level I. Prices in Level II are either directly or indirectly observable as of the reporting date. Level II valuations are based on inputs, including quoted forward for commodities, time value, credit risk and volatility factors, which can be substantially observed or corroborated in the marketplace. Level III Valuations are made using inputs for the asset or liability that are not based on observable market data. The Company uses Level III inputs for fair value measurements in inputs such as commodity prices in impairment assessments. 3. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS Amendments to IFRS 3 – “Business Combinations” – Definition of a Business (“IFRS 3”) The Company elected to early adopt the amendments to IFRS 3 effective January 1, 2020, which will be applied prospectively to acquisitions that occur on or after January 1, 2020. The amendments introduce an optional concentration test, narrow the definitions of a business and outputs, and clarify that an acquired set of activities and assets must include an input and a substantive process that together significantly contribute to the ability to create outputs. These amendments do not result in changes to the Company’s accounting policies of applying the acquisition method. NEW ACCOUNTING STANDARDS ISSUED BUT NOT EFFECTIVE New accounting standards and interpretations were issued and are mandatory for accounting periods after December 31, 2020. Certain of the new accounting standards and interpretations, which are not expected to have a significant impact on the Company’s Financial Statements upon adoption, are as follows: • • Conceptual framework for financial reporting, and Amendments to IAS 1 – Presentation of Financial Statements and IAS 8 – Accounting policies changes in accounting estimates and errors, definition of material. 4. CASH The following table sets out cash balances held in different currencies: As a part of the Peruvian government’s response to the hardships brought about by COVID-19, the Company received a government guaranteed loan (Reactiva program) of $2.8 million. A requirement of that loan was to escrow 20% of the proceeds, $0.6 million, which is presented as non-current restricted cash. The restriction on this cash should be lifted when 80% of the 36-month loan has been repaid. 5. EXPLORATION AND EVALUATION ASSETS The following table sets out a continuity of the Exploration and Evaluation Assets: 45 The rights to explore and exploit Block 133 have been returned and accepted by Petroperu S.A. in August 2019. The net book value of the Block 133 was fully expensed during the third quarter 2019 ($447). 6. PROPERTY, PLANT AND EQUIPMENT For the year ended December 31, 2020, $1.1 million of the depreciation, depletion and amortization expense was recorded as inventory (December 31, 2019: $0.5 million). In the first quarter of 2020, indicators of impairment were presented due to global commodity price forecast deteriorating from decreases in demand and an increase of supply around the world. As a result of the indicators of impairment, the Company performed an impairment test on its Peru Cash Generating Unit (CGU) whereby the recoverable amount was compared against its carrying amount. The recoverable amount was determined using value in use, after-tax cash flows for proved plus probable reserves and after-tax discount rate of 13.5%. Based on the results of the impairment test completed, no impairment expense was recognized. The Company determined there were no indicators of impairment of the property, plant and equipment balance at December 31, 2020. 7. VAT RECEIVABLE Valued Added Tax (VAT) in Peru is levied on the purchase of goods and services and is recoverable on sales of goods and services. The Company recovered $14.6 million during 2020 and expects to recover $10.2 million in the short term based on its estimated oil sales. 46 8. TRADE AND OTHER RECEIVABLES As at December 31, 2020, trade receivables represent revenue related to the sale of crude oil and collections to be received in the short term. No credit losses on the Company’s trade accounts have been incurred. 9. TRADE AND OTHER PAYABLES As at December 31, 2020, trade payables and accruals are primarily related to the drilling and completion of wells, as well as construction of production processing facilities. 10. PREPAID EXPENSES As at December 31, 2020, prepaid expenses are comprised of rent, insurances and prepaid services (consultants and other services) related to the Company’s activities to obtain credit facilities. In accordance with Petroperu agreement a prepaid amount of $4.3 million was paid to offset the future settlement of the derivatives obligation. 11. DECOMMISSIONING OBLIGATIONS The undiscounted uninflated value of its estimated decommissioning liabilities is $23.7 million which includes an addition of $0.7 million related to the drilling campaign of the Company in the Bretana oil field, liabilities settled of $0.3 million, and revisions to decommissioning of $2.7 million. The present value of the obligations was calculated using an average risk-free rate of 2.8% (December 31, 2019: 3.3%) to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash 47 flow estimates. The inflation rate used in determining the cash flow estimates ranges from 1.9% to 2.0%. The table above sets out the continuity of decommissioning obligations. 12. INVENTORY Product inventory consists of the Company's crude oil barrels, which are valued at the lower of cost or net realizable value. Costs include operating expenses, royalties, transportation and depletion associated with crude oil barrels. Costs capitalized as inventory will be expensed when the inventory is sold. As at December 31, 2020, crude inventory balance of $4,134 consists of 167,222 barrels of crude oil valued at $24.72 per barrel (December 31, 2019: $1,549 – 93,767 barrels at $16.52 per barrel). Materials and supplies, including diluent, are expected to be consumed in the short-term. 13. REVENUES NET OF ROYALTY The Company’s oil production revenue is determined pursuant to the terms of the revenue agreements. The transaction price for crude is based on the commodity price in the month of production, adjusted for quality, allowable deductions and other factors. Commodity prices are based on market indices. 14. FINANCIAL INSTRUMENTS The table above details the Company’s carrying value and fair value of financial instruments including cash, trade and other receivables, lease obligations, and trade and other payables, all of which are classified as financial assets and liabilities and reported at amortized cost. The Company is exposed to various financial risks arising from normal-course business exposure. These risks include market risks relating to foreign exchange rate fluctuations and commodity price risk as well as liquidity. COMMODITY PRICE DERIVATIVES The embedded derivative liability is classified as Level 2 fair value measurement. The service contract for transport of liquid hydrocarbons of the North-Peruvian Oil Pipeline (“ONP”) and Petroperu Saramuro agreements signed with Petroperu during 2020, include a clause to adjust the risk of volatility of the international price of crude oil during the period in which Petroperu provides the service of crude oil usage and until the Company returns the full amount of the volumes that were delivered in advance. The price compensation is based on the 2 day average Brent oil price marker quotes (Brent Platts and Brent ICE) to the points of shipment and returns. In case the average price shipment is greater than the average price return, the Company will compensate Petroperu an amount equivalent to the difference between both averages, multiplied by the volume sold or arranged by Petroperu. If the average price shipment is lower than the average price return, the Company will be compensated by Petroperu. The fair value of the embedded derivative, considering an average future Brent price marker differential, was recorded as a loss on commodity price derivatives at December 31, 2020. 48 As of December 31, 2020, 1.8 million barrels of oil have been delivered to and sold into the ONP, and remain in the pipeline or storage tanks, awaiting final sale by Petroperu and are subject to the same settlement terms as noted above in the ONP contract. FOREIGN EXCHANGE RATE RISK The Company’s functional currency is the United States dollar. Foreign exchange gains or losses can occur on translation of working capital denominated in currencies other than the functional currency of the jurisdiction which holds the working capital item. Excluding the impact of changes in the cross-rates, a 1% fluctuation in translation rates would have nil impact on net income or loss, based on foreign currency balances held at December 31, 2020. LIQUIDITY RISK Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. The Company has no debt or loans with financial institutions. While the decrease in commodity prices as a result of the COVID-19 pandemic will negatively impact the Company’s financial performance and position, the subsequent events disclosed in Note 22 provides the Company with financial flexibility and the ability to meet obligations as they become due. The Company’s liquidity risk is impacted by current and future commodity prices. If required, the Company will also consider additional short-term financing or issuing equity in order to meet its future liabilities. Declines in future commodity prices could affect the Company’s ability to fund ongoing operations. The current challenging economic climate is having and may continue to have significant adverse impacts on the Company including, but not exclusively: • material declines in revenue and cash flows as a result of the decline in commodity prices; • • • • declines in revenue and operating activities due to reduced capital programs and the shut-in of production; inability to access financing sources; increased risk of non-performance by the Company’s customers and suppliers; and interruptions in operations as the Company adjusts personnel to the dynamic environment. 49 The situation is dynamic and the ultimate duration and magnitude of the impact on the economy and the financial effect on the Company is not known at this time. Estimates and judgments made by management in the preparation of the financial statements are increasingly difficult and subject to a higher degree of measurement uncertainty during this volatile period. CREDIT RISK Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial loss to the Company. The Company’s VAT is primarily for sales tax credits on exploration and evaluation expenses incurred in prior years. These credits will be applied to future oil development activities or recovered as per the sale tax recovery legislation currently in effect. The majority of the Company’s trade receivable balances relate to crude oil sales to one customer, being Petroperu, a state owned company. Recently, the Company signed a long term sales agreement and initiated exports through Brazil, with an oil trading company, whereby sales are FOB Bretana, and secured by a letter of credit. The Company’s policy is to enter into agreements with customers that are well established and well financed entities in the oil and gas industry such that the level of risk is mitigated. The Company has not experienced any material credit losses in the collection of its trade receivables. Impairment to a financial asset is only recorded when there is objective evidence of impairment and the loss event has an impact on future cash flow and can be reliably estimated. Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. Management believes that there is no risk on the recoverability and or applicability of the sales tax credits. Therefore, no impairment to the carrying value of these assets has been estimated. The Company has deposited its cash and cash equivalents with reputable financial institutions, with which management believes the risk of loss to be remote. The maximum credit exposure associated with financial assets is their carrying value. At December 31, 2020, the cash and cash equivalents were held with seven different institutions from three countries, mitigating the credit risk of a collapse of one particular bank. 15. SHARE CAPITAL Authorized share capital consists of an unlimited number of common shares without nominal or par value. The holders of common shares are entitled to one vote per share and are entitled to receive dividends as recommended by the Board of Directors. In June 2019, the Company issued equity for gross proceeds of $25.5 million upon the issuance of 133.3 million of shares, and had agents warrants exercised and converted into 1.1 million shares for net proceeds of $0.2 million. In December 2019, PetroTal declared a dividend of $0.9 million to all shareholders which was paid in January 2020. In Q1 2020, the Company received $0.2 million from the exercise of warrants. On June 18, 2020, the Company completed an equity issue, raising gross proceeds of approximately $18 million (at 10 pence per unit) upon issuance of 141.2 million of units. Each unit is comprised of one common share and one half of one warrant allowing the subscriber to purchase additional shares within 36 months at 16 pence/share upon presentation of a full warrant. DIVIDEND DECLARED On December 12, 2019, the Company declared an interim dividend of Canadian Dollars (“CAD$”) 0.0017 cash for each common share to be paid to shareholders on January 20, 2020, representing in aggregate a total dividend payment of approximately CAD$1.1 million ($0.9 million). The dividend declared was paid in January 2020. Due to the financial impact of the global oil price disruption, the Company has suspended declaration and payment of dividends in order to manage cash for business operations. 50 PERFORMANCE WARRANTS The performance warrants have an exercise price of $0.187 per share and vested upon achievement of certain oil production targets, within a specified period. Each warrant will be adjusted as to the number of shares to be issued on the exercise date and the exercise price of the warrant. INVESTORS’ WARRANTS In connection with the brokered private placement offering on June 12, 2020, investors received one common share and one half of one warrant allowing the subscriber to purchase additional shares within 36 months at 16 pence/share upon presentation of a full warrant. The following table sets out a continuity of outstanding warrants: SHARE-BASED COMPENSATION The Company granted performance share units (“PSUs”) to employees and deferred share units (“DSUs”) to directors of the Company. The grant date fair value of performance share units (“PSUs”) granted to employees is recognized as share-based compensation expense with a corresponding increase in contributed surplus over the vesting period. The Company granted PSUs to employees in accordance of the provisions of the Company’s PSU plan. The PSUs either vest after three years or equally over three years and each PSU will entitle the holder to acquire between zero and two common shares of the Company, subject to the achievement of performance conditions relating to the Company’s total shareholder return, net asset value and certain production and operational milestones. The company determined the fair value of the PSUs through a combination of Black-Scholes and a probability weighted model. The following table details the terms of the PSUs outstanding as at December 31, 2020: The Board of Directors, after reviewing the Company’s total shareholder return, net asset value and certain production and operational milestones, has determined that the 2020 units are exchangeable for 0.1 share per unit (2019 Plan: 1.575). The following assumptions were used for the Black-Scholes valuation of the PSUs granted: For the year ended December 31, 2020, the Company recognized $0.9 million of share-based compensation expense in general and administrative expense (December 31, 2019: $0.4 million). The Company issued an aggregate of 2,301,599 DSUs pursuant to the Company’s DSU plan to the directors of the Company. The DSUs vest immediately and may only be redeemed upon a holder ceasing to be a director of PetroTal. No common shares will be issued under the DSU plan; all DSUs granted are settled in cash. The DSUs are valued at the closing share price on the reporting date 51 For the year ended December 31, 2020, the Company recognized $0.2 million of DSU expense in general and administrative expense and contributed surplus (December 31, 2019: $0.3 million). The following table details the PSU and DSU activity: 16. FINANCIAL EXPENSE At December 31, 2020, the Company had a financial liability of $2.8 million pertaining to a Peruvian backed loan received in Q2 2020. The loan has an interest rate of 1.12% and is payable over 36 months. The loan was paid in February 2021. 17. TAXES The Company utilizes the liability method of accounting for income taxes. Under the liability method, deferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the net deferred tax assets will not be realized. The Company’s ability to realize deferred tax assets is assessed throughout the year and a valuation allowance is established, if required. The Company recognizes the impact of a tax position only if it is more likely than not to be sustained upon examination based on the technical merits of the position. The Company also routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts, including interest where appropriate. The Company recognizes a tax benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination, based on the technical merits of the position. The Company’s effective tax rate is impacted each year by the relative pre-tax income (loss) earned by the Company’s operations in Canada, U.S., Peru and the rest of the world. The Company is subject to statutory tax rates of 21% in the U.S., 28% in Canada and 32% in Peru (exploration activities of the Company in Peru are subject to a 30% statutory tax rate plus 2% in accordance with Law 27343). The Company files federal income tax returns as well as local income tax returns in the various jurisdictions. The movement in deferred income tax balances is as follows: 52 The valuation allowance primarily relates to Canadian and Peruvian net operating loss carryforwards, which reduces the Company’s net deferred tax asset to an amount that will more likely than not be realized within the carryforward period. In Peru the tax loss carry-forward related to Block 95 will expire in four years for a total of $212.7 million losses. In Canada non-capital losses can be carried forward for twenty years for a total of $47.0 million losses, $3.0 million for US losses. There is generally no carryback period, and the carryover period starts with the taxable year following the loss and continues indefinitely. The Company has a tax rate in each of the three license contracts of 32%; however, due to accumulated tax losses, the Company only expects to pay the 2% tax on revenue that is recoverable against any future tax payable. The balance of the 2% tax that is recoverable against any future tax payable at December 31, 2020 was $0.6 million (December 31, 2019: $0.2 million) and is included in other receivables. 18. GENERAL AND ADMINISTRATIVE EXPENSES The Company reduced salaries to employees due to the pandemic from May to November 2020, and continued support the oil field community in Peru, providing infrastructure and medical supplies during 2020. 19. RELATED PARTY TRANSACTIONS The Company had no related party transactions or off-balance sheet arrangements. The Company’s key management includes the Directors and Officers. 20. COMMITMENTS As of December 31, 2020 lease liabilities recorded for $0.3 million has the following minimum year payments under its office lease: Year 2021 2022 2023 Thereafter Total Amount 97 101 40 - 238 53 IFRS 16 was applied by the Company and as such, booked a right-of-use asset relating to the head office lease of $0.4 million (balance net of amortization of $0.3 million at December 31, 2019) and included in property, plant and equipment, with a corresponding increase to lease obligations. The lease obligation was calculated using an average risk-free rate of 4.69%. As of December 31, 2020, the Company holds the following letters of credit guaranteeing its commitments in the exploration blocks: Block 107 107 Beneficiary Perupetro S.A. Perupetro S.A. Amount $1,500 $1,500 $3,000 21. CAPITAL STRUCTURE Commitment 1st exploration well, minimum work 5th exploratory period 2nd exploration well, minimum work 5th exploratory period Expiration December 2021 December 2021 The Company’s objective when managing its capital is to ensure it has sufficient funds to maintain its ongoing operations, to pursue the acquisition of oil and gas properties, and to maintain a flexible capital structure that optimizes the cost of capital at an acceptable risk. The Company manages its capital structure and adjusts it according to the funds available to the Company, to support the exploration and development of its interests in its existing oil and gas properties, and to pursue other opportunities as they arise. The Company defines its capital as follows: 22. SUBSEQUENT EVENTS On January 19, 2021, the Company executed final agreement with Petroperu, restructuring the contingent derivative liability over three years and extending the oil sales contract with Petroperu for an additional two years. The amount of the contingent liability represented $16.6 million (based on the November 30, 2020 valuation) and was subsequently paid out (along with the $3 million Peruvian-government COVID emergency response loan), from the successful $100 million bond offering. On February 2, 2021, the Company announced completion of a 3-year $100 million senior secured bond with an annual 12% coupon, issued at a 5% discount. The bonds issued by PetroTal are the Company’s only interest bearing debt and the proceeds are for payout of the Petroperu derivative liability with Petroperu and Reactiva loan, totaling $20 million, to support the Company’s crude oil price hedging strategy ($15 million), to finance potential acquisitions ($20 million), with the remainder for continued development of the Bretana oil field. On February 18, 2021, the Company announced its 2021 capital development program of $100 million, to be funded from the bond proceeds and internally generated funds from operations, along with existing cash resources. The Company has hedged approximately 32% of expected April to December 2021 oil production. Additionally, Petroperu has now hedged 100% of oil sales through the ONP. This robust hedging program will ensure funding stability to support the 2021 capital development program, in the event Brent oil price drop materially. 54 

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