PetroTal
Annual Report 2019

Plain-text annual report

PetroTal Announces 2019 Year‐End Financial and Operating Results  Record levels of oil production, cash flow and income   Calgary and Houston – June 15, 2020 — PetroTal Corp.  (“PetroTal” or the “Company”) (TSX‐ V: TAL and AIM: PTAL) is pleased to announce its financial and operating results for the year  and the three months (“Q4”) ended December 31, 2019.    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, 2019, which are available on SEDAR at www.sedar.com  and  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, 2019. All amounts herein are in United  States dollars (“USD”) unless otherwise stated.  2019 HIGHLIGHTS  The  Company  reached  several  key  operational  and  financial  achievements  during  2019  as  described below:  Q4 Highlights  ‐ Drilled  and  completed  the  Company’s  first  horizontal  well  (4H),  having  a  500  meter  lateral and utilizing autonomous inflow control device (“AICD”) valves to maximize oil  production;  ‐ Drilled and completed the 5H well, the longest horizontal well drilled in Peru. The well  reached the target Vivian formation at a vertical depth of 2,696 meters and then with an  863 meter horizontal section inside the main productive oil reservoir;  ‐ Commissioning of the new $31.6 million Central Production Facility (“CPF”) commenced  on December 22, 2019 with the successful hydrostatic test of the new 20,000 barrel oil  storage tank;  ‐ Earned net income of $18.2 million ($0.03 per share basic) compared to a net loss of $2.2  million in Q4 2018;  ‐ Higher operating net back of $28.6 million compared to $2.3 million in Q4 2018;   ‐ For  Q4  2019  the  Company  recognized  funds  flow  generated  of  $22.2  million,  as  compared to utilization of negative $1.9 million in Q4 2018;  ‐ Achieved a record quarterly oil production of 7,767 bopd, an increase of 670% over Q4  2018 (1,158 bopd), and an increase of 63% over Q3 2019 (4,760 bopd);  ‐ Q4 2019 sales volumes averaged 9,509 bopd compared to 1,199 bopd in Q4 2018; and,  ‐ Capital expenditures were $26.9 million in Q4 2019 compared to $4.4 million in Q4 2018.                 2019   Operational Highlights  ‐ At  December 31,  2019,  six  producing  wells  and  one  water  disposal  were  operating,  inclusive of the initial water disposal that was converted to an oil producer;  ‐ The Company invested $88.4 million to drill five producing oil wells, a water disposal well  and build production facilities, nearly a three fold increase from capital expenditures of  $23.2 million in 2018;  ‐ The Company achieved an exit rate production of 13,300 bopd at the end of 2019 with  the Q4 average being 7,767 bopd. PetroTal produced a total of 1.5 million barrels of oil  in 2019, representing average oil production of 4,131 bopd, an increase of 431% from the  average production of 958 bopd realized in 2018;  ‐ NSAI Report shows increases in all reserve categories:  o   Proved ("1P") reserves of 21.5 million barrels ("mmbbl"), an increase of 20% from the      17.9 mmbbl recorded at the end of 2018;  o   Proved plus Probable ("2P") reserves of 47.7 mmbbl, an increase of 21% from the 39.4      mmbbl recorded at the end of 2018; and,  o   Proved plus Probable and Possible ("3P") reserves of 84.8 mmbbl, an increase of 8%      from the 78.7 mmbbl recorded at the end of 2018;  ‐ Net Present Value (before tax, discounted at 10%) (“NPV‐10”) represents $434 million  ($20.19/bbl)  for  1P  reserves,  $1.1  billion  ($23.02/bbl)  for  2P  reserves  and  $1.9  billion  ($22.11/bbl) for 3P reserves; and,  ‐ Original oil in place ("OOIP") estimates for each category of reserves also increased, with  the 2P estimate increasing from 329 mmbbl to 364 mmbbl.  2019 Financial Highlights  ‐ Generated revenue of $77 million ($52.32/bbl) compared to $10 million ($59.10/bbl) in  2018;   ‐ Royalties  to  the  Peruvian  government  were  $3.4  million  (4%  of  revenue)  during  2019  compared to $0.5 million (5% of revenue) for 2018;  ‐ Generated funds from operations of $51.9 million compared to $30 thousand in 2018, as  a result of the significant increase in revenue generation;   ‐ Operating and transportation costs, were $31.9 million ($21.68/bbl) for 2019 compared  to $4.9 million ($27.60/bbl) for 2018, an improvement of 22% on a per barrel basis;  ‐ Net operating income (netback) in 2019 was $41.4 million ($28.09/bbl) compared to $5.1  million ($28.72/bbl) in 2018;  ‐ Cash flow generated was $29.7 million compared to negative $3.4 million in 2018. Cash  flow  represents  netback  inclusive  of  G&A  costs,  realized  gain  (losses)  on  commodity  contracts and all other cash transactions; and,  ‐ At  December  31,  2019,  the  Company  had  cash  of  $21.1  million,  compared  to  $26.3  million at the end of 2018.  2019   Other Highlights  ‐ On November 4, 2019, the Company announced the addition of Mr. Douglas Urch, as  Executive Vice President and Chief Financial Officer of the Company;  ‐ On December 12, 2019, the Company’s board of directors declared its inaugural dividend  of $0.9 million to shareholders of record on December 20, 2019; and,  ‐ On  December  19,  2019,  Ms.  Eleanor  Barker  and  Dr.  Roger  Tucker  were  appointed  as  Independent Non‐Executive Directors.          The  following  table  summarizes  key  financial  and  operating  highlights  associated  with  the  Company’s performance for the years ended December 31, 2019 and 2018. See the Financial  Statements, MD&A and AIF for further details.  Results at a glance  Financial    Crude oil revenues    Royalties    Commodity price derivatives loss    Net operating income    Net income (loss)       Basic and diluted (US$/share)    Funds generated from operations    Capital expenditures  Operating    Average production (bopd)    Average sales (bopd)    Average Brent oil price (US$/barrel)    Average realized price (US$/barrel)    Netback (US$/barrel)    Cash flow   Balance sheet     Cash    Working Capital    Total assets    Current liabilities    Equity   December 31   2019   December 31   2018                          77,024                           (3,394)                                367                           41,719                           20,152                               0.03                           51,061                           88,763                           10,487                              (493)                                     ‐                             5,096   (4,621)   (0.01)                                   30                           23,207                             4,131                             4,033                             64.31                             52.32                             28.09                           29,692                                 958                                 964                             63.84                             59.10                             28.72   (3,362)                          21,101                        (11,762)                       194,181                           59,286                        121,057                           26,259                           26,053                           96,097                             9,582                           77,527                  Q4‐19  $/bbl               FY 2019  $/bbl                Q4‐18  $/bbl                FY 2018  $/bbl                          1,158                       110,287                           63.84   ‐12.1%        1,199   SALES:  Average Production (bopd)  Bbls Sold  Average Brent price ($/bbl)  Quarterly Difference Variation price (%)  Average sold (bopd)  Oil revenue  Less:  Royalties  Operating expense  Transportation expense  Derivative loss (income)  NET OPERATING INCOME  Netback as % of Revenue  G & A   Accretion expense  Finance expense  CASH FLOW  Deferred income taxes  Depletion and depreciation  Impairment and foreign exchange  Net Income (loss)                          7,767                       874,802                           63.26   ‐17.0%        9,509   $45,916   $52.32  $2.31  $1,813   $6,047   $9.73  $9,702   $11.95  $0.25  ($213)  $28,566   $28.09                          4,131                    1,472,042                           64.31   ‐18.6%        4,033   $77,024   $56.09  $3.04  $3,394   $14,319   $22.82  $9.32  $17,592   $0.00  $367   $41,352   $20.91  $52.49  $2.07  $6.91  $11.09  ‐$0.24  $32.65  $6.91  $0.14  $0.27  $0.05  $4.30  $0.14  62.2%  $6,048   $126   $238   $22,154   $45   $3,760   $126   $18,223   $7.33  $0.28  $0.31  $0.06  $5.79  $0.63  53.7%  $10,789   $36.95  $0.81  $0.00  $416   $455   $29,692   $86   $8,528   $927   $20,152   ‐$7.18  $7.39  $2.75  $336   $6,186   $59.10  $2.78  $2,516   $19.73  $7.87  $1,028   $0.00  $0   $2,306   $28.72  37.3%  $4,075   $44.18  $3.48  $0.00                             958                       177,465                           63.84   ‐7.4%           964   $10,487   $493   $3,501   $1,397   $0   $5,096   48.6%  $7,840   $618   $0   ($3,362)  ($792)  $1,404   $647   ($4,621)  ‐$4.46  $7.91  $3.65  $89   $0   ($1,858)  ($792)  $815   $303   ($2,184)                                                                                                                                                     Manuel Pablo Zuniga‐Pflucker, President and Chief Executive Officer, commented:  “As  a Company,  we  achieved  a  great  deal in  2019.    We  set  ourselves a  number  of  ambitious  targets at the beginning of the year and were able to meet or exceed all of them.  We were also  able to generate significant value for our shareholders by increasing our production by 431%  year‐on‐year.  Our ability to deliver an exit rate of 13,300 bopd for 2019 is a testament to the  expertise and hard work of PetroTal’s workforce during the period.  Whilst we are currently focusing on balance sheet strength and liquidity, in light of the difficult  trading environment, we remain well placed to deliver value for all our stakeholders.  In closing,  I  would  like  to  thank  PetroTal’s  shareholders,  directors,  employees  and  contractors  for  their  continued  support.  We  look  forward  to  announcing  further  developments  as  the  year  progresses.”   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  Bretaña  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 Northern Peru and is led by a Board of Directors that is focused on  safely and cost effectively developing the Bretaña 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 contact:  Douglas Urch  Executive Vice President and Chief Financial Officer  Durch@PetroTal‐Corp.com  T: (713) 609‐9101  Manuel Pablo Zuniga‐Pflucker  President and Chief Executive Officer  Mzuniga@PetroTal‐Corp.com  T: (713) 609‐9101  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  Numis Securities Limited (Joint Broker)  John Prior / Emily Morris   T: +44 (0) 207 260 1000  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 and completion activities and the results of such activities; construction of production  facilities; the ability of the Company to achieve drilling success consistent with management’s expectations; anticipated future  production  and  revenue;  future  development  and  growth  prospects;  and  the  Company’s  ability  to  resume  operations  in  accordance with developing public health efforts to contain COVID‐19.  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, 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 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.  FOFI  DISCLOSURE:  This  press  release  contains  future‐oriented  financial  information  and  financial  outlook  information  (collectively,  “FOFI”)  about  PetroTal’s  prospective  results  of  operations,  production,  NPV‐10,  future  net  revenue,  future  development  costs,  temporary  shut  down  of  operations,  the  anticipated  resumption  of  operations,  storage  capacity,  cost  reductions 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.   PRESENTATION OF OIL AND GAS INFORMATION: The reserves information herein sets forth PetroTal's reserves as at December  31, 2019, as presented in the independent reserves report prepared by NSAI, in accordance with the standards contained in 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 18, 2020, more detailed information is included in the AIF.  This press release contains metrics commonly used in the oil and natural gas industry, such as operating netbacks (calculated  on a per unit basis as oil revenues less royalties and barging, pipeline and lifting costs). These terms have been calculated by  management and do not have a standardized meaning and may not be comparable to similar measures presented by other  companies, and therefore should not be used to make such comparisons. Management uses these oil and gas metrics for its  own performance measurements and to provide shareholders with measures to compare PetroTal’s operations over time. All  oil and gas disclosure contained in this press release complies with the 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  Canadian  Oil  and  Gas  Evaluation  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.  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.                        TSXV:TAL / AIM: PTAL AUDITED CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2019 and 2018 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 7 8 9 10 11 2 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 June 15, 2020 3 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, 2019 and 2018, and the consolidated statements of earnings (loss) and comprehensive income (loss), statements of changes in equity and statements of 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, 2019 and 2018, 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 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. 4 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 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. 5 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. /s/ Deloitte LLP Chartered Professional Accountants Calgary, Alberta June 15, 2020 6 7 8 9 10 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2019 and 2018. All amounts are stated in thousands of United States Dollars ($) unless otherwise indicated. 1. CORPORATE INFORMATION PetroTal Corp. formerly Sterling Resources Ltd, (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 21) 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 June 15, 2020, 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 comprise the Financial Statements of the Company and the wholly-owned group of companies. 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, are 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 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. 11 Operating Transportation General and administrative AIM listing costs December 31, 2018 Before reclassification 4,898 - 6,180 1,660 Reclassification (1,397) 1,397 1,660 (1,660) December 31, 2018 After reclassification 3,501 1,397 7,840 - 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. 12 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. 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, 2019 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. 13 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. 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. 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. e. f. 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, 2019, 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 14 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. 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. 15 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 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, 2018, 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. 16 n. Fair Value Measurements 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, 2019, which will be applied prospectively to acquisitions that occur on or after January 1, 2019. 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, 2019. 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: 17 5. EXPLORATION AND EVALUATION ASSETS The following table sets out a continuity of the Exploration and Evaluation Assets: The rights to explore and exploit Block 133 have been returned and accepted by Petroperu S.A. in August 2019. Management of the Company considers Block 133 value to be zero. The net book value of the Block 133 was fully expensed during the third quarter 2019 ($447). 6. PROPERTY, PLANT AND EQUIPMENT For the twelve months ended December 31, 2019, $471 of the depreciation, depletion and amortization expense was recorded as inventory (December 31, 2018: $136). The Company determined there were no indicators of impairment of the property, plant and equipment balance at December 31, 2019. 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 $10,400 during 2019 and expects to recover $12,747 in the short term based on its estimated oil sales. 18 8. TRADE AND OTHER RECEIVABLES As at December 31, 2019, trade receivables represent revenue related to the sale of crude oil and payments were received in January 2020. No credit losses on the Company’s trade accounts have been incurred. 9. TRADE AND OTHER PAYABLES As at December 31, 2019, trade payables and accruals are primarily related to the drilling and completion campaign of the Company’s five wells, as well as construction of new production processing facilities. 10. ADVANCES AND PREPAID EXPENSES As at December 31, 2019, prepaid expenses are related to rent, insurances and prepaid services (consultants and other professional services) related to the Company’s activities to obtain debt and capital for projects in course. 11. DECOMMISSIONING OBLIGATIONS The Company has estimated undiscounted decommissioning liabilities to be $21,591. The net present value of its estimated decommissioning liabilities is $17,562, which includes an addition of $10,176 related to the construction of production facilities and drilling campaign of the Company in the Bretaña oil field, and a revision of $3,804 based upon a change in the un-risked interest rate. The present value of the obligations was calculated using an average risk-free rate of 3.3 percent (December 31, 2018: 4.7 percent) 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 percent to 2.0 percent (December 31, 2018: 1.9 to 2.1 percent). The table above sets out the continuity of decommissioning obligations. 19 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, 2019, crude inventory balance of $1,549 consists of 93,767 barrels of crude oil valued at $16.52 per barrel (December 31, 2018: $178 – 5,552 barrels at $32.18 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 liabilities, and trade and other payables, all of which are classified as financial 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 2019, 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, 2019. 20 Subsequent to December 31, 2019, 2.1 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 one percent fluctuation in translation rates would have nil impact on net income or loss, based on foreign currency balances held at December 31, 2019. 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 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. 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, 2019, 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. 21 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 raised additional equity of $25.5 million gross ($23.7 million net of fees) by the issuance of 133.3 million common shares and had agents warrants exercised and converted into 1.1 million common shares for net proceeds of $0.2 million. DIVIDEND DECLARED The Company did not declare any cash dividends or distributions on common shares in prior years. On December 12, 2019, the Company declared an interim dividend of Canadian Dollars (“CAD$”) 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. PERFORMANCE WARRANTS The performance warrants had 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. As of December 31, 2019, all the warrants have vested. The following table sets out a continuity of outstanding performance warrants: AGENTS’ WARRANTS As compensation for the services rendered in connection with the brokered private placement offering, the Agents received warrants which entitled the holder to purchase one common share of the Company at an exercisable price of $0.187 per converted Agents’ warrant in June 2019. The following table sets out a continuity of outstanding performance 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 22 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, 2019: 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 units exchangeable for up to one share will be issued one share per unit, and that the units exchangeable for up to two shares will be issued 1.575 shares per unit (2018 Plan: 1.334). The following assumptions were used for the Black-Scholes valuation of the PSUs granted: For the year ended December 31, 2019, the Company recognized $0.4 million of share-based compensation expense in general and administrative expense (December 31, 2018: $0.1 million). The Company issued an aggregate of 1,357,299 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. At December 31, 2019, $0.4 million was included in accounts payable relating to the DSUs. For the year ended December 31, 2019, the Company recognized $0.3 million of DSU expense in general and administrative expense and contributed surplus (December 31, 2018: $0.1 million). The following table details the PSU and DSU activity: 16. FINANCIAL EXPENSES 23 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: 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 $144 million losses. In Canada non-capital losses can be carried forward for twenty years for a total of $47 million losses. For US losses of $3 million arising in taxable years ending in 2018 and later, 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 percent; however, due to accumulated tax losses, the Company only expects to pay the two percent tax on revenue that is recoverable against any future tax payable. The balance of the two percent tax that is recoverable against any future tax payable at December 31, 2019 was $0.2 million (December 31, 2018: $0.1 million) and is included in other receivables. 18. RELATED PARTY TRANSACTIONS The Company had no related party transactions or off-balance sheet arrangements. The Company’s key management is considered to the Directors and Officers. 24 19. COMMITMENTS As of December 31, 2019 , lease liabilities recorded in the book for $309, has the following minimum year payments under its office lease: Year 2020 2021 2022 2023 Thereafter Total Amount 94 97 101 40 - 332 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 percent. As of December 31, 2019, 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 20. 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: 21. SUBSEQUENT EVENTS Subsequent to the year-end, on March 11, 2020, the World Health Organization characterized the outbreak of a strain of the novel coronavirus (COVID-19) as a pandemic which has resulted in a series of public health and emergency measures that have been put in place to combat the spread of the virus. In May 2020, the Company was notified by Petroperu, the operator of Peru’s ONP that it has temporarily shut down the pipeline as a result of a directive from the Peruvian government intended to combat the spread of COVID-19 in the communities adjacent to the pipeline operations. The directive states that no employees over the age of 65 or with serious chronic diseases should be working in the high-risk regions of Peru. In conjunction with the pipeline shut-down, the Company shut-in operations at the Bretaña oilfield. The duration and impact of COVID-19 is unknown at this time and it is not possible to reliably estimate the impact that the length and severity of these developments will have on the financial results and condition of the Company in future periods. 25 Significant declines in crude oil spot prices and in the equity markets have occurred for various reasons linked to the pandemic and other conditions impacting worldwide oil prices. The impairment tests for the Company’s oil assets are based on fair value less costs of disposals. In accordance with IFRS, the Company has not reflected these subsequent conditions in the recoverable amount estimates of the oil assets as at December 31, 2019. Impairment indicators for the Company’s oil assets exist at March 31, 2020 due to significant declines in forecasted oil prices from December 31, 2019 to March 31, 2020. On a monthly basis, the Company tracks the impact of fluctuating oil prices on volumes sold under both the Swap Contract and Sales Contract, as a commodity derivative and, as a result of the recent drastic drop in oil prices, the contingent liability accruing under these contracts is approximately $18 million and $24 million, respectively, at the end of March 2020. Given the current ONP timetable, it is expected that oil delivered pursuant to the Swap Contract will be sold by Petroperu in Q3 2020, and oil delivered pursuant to the Sales Contract will be sold by Petroperu commencing in Q4 2020. Under the terms of the Sales Contract, the Company is required to settle this contingent liability when the balance exceeds $10 million. On June 11, 2020, the Company entered into a contract with Petroperu to crystallize the contingent liability to be paid over a three-year period in equal instalments with an interest rate of approximately 7%. The agreement is secured by the Company’s assets. The Company remains exposed to fluctuations in the commodity price from the crystallization date of June 2020 and will realize the benefit or loss of fluctuations in the commodity price when the oil is delivered as described above. On June 12, 2020, the Company entered into a broker agreement to place 141.2 million of placing units, raising gross proceeds of approximately $18 million (at 10 pence per unit). Each placing unit will be 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. 26 TSXV:TAL / AIM: PTAL MANAGEMENT’S DISCUSSION AND ANALYSIS For the years ended December 31, 2019 and 2018 TABLE OF CONTENTS 1. Corporate overview ……………………………………………………………………………………………………….……… 2. Overview and selected annual information...……………………………………………………..………………….. 3. 2019 Highlights………………………………………………………………………………………………………………………. 4. Outlook and growth strategy ..…………………...………………..……………………………………………………….. 5. Selected financial information………………………………………………………………………………………………… 6. 2019 Reserve Report………………………. ……………………………………………………………………..…….………. 7. Significant judgements and estimates ……………………………………………………………………..…….……… 8. Subsequent events ………………………………………………………………………………………………………………… 9. Related party transactions and taxes ……………………………………….……..…………………………………….. 10. Contractual obligations and commitments……………………………………………………………………………… 11. Forward-looking statements and business risks ……………………………………………………………………… 3 4 4 5 6 12 14 15 15 16 16 2 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, 2019 and 2018, is dated June 15, 2020, and should be read in conjunction with the Company’s audited Consolidated Financial Statements (the “Financial Statements”) for the twelve months ended December 31, 2019 and 2018. 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 Bretaña oil field. Additionally, the Company has 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 and, once amalgamated, continued as one operation under the name of Sterling Resources Ltd. The name of the Company was changed in June 2018 to PetroTal Corp. The Company acquired 100% of the subsidiaries from 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 2018 and 2019, PetroTal relinquished its rights to Blocks 123, 129 and 133. After the reverse takeover transaction 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. 3 The Bretaña 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 Bretaña oil field. 2. OVERVIEW AND SELECTED ANNUAL INFORMATION 3. 2019 HIGHLIGHTS The Company reached several key operational and financial achievements during 2019 as described below: Three months ended December 31, 2019 (“Q4”) Highlights - Drilled and completed the Company’s first horizontal well (4H), having a 500 meter lateral and utilizing autonomous inflow control device (“AICD”) valves to maximize oil production; - Drilled and completed the 5H well, the longest horizontal well drilled in Peru. The well reached the target Vivian formation at a - - vertical depth of 2,696 meters and then with an 863 meter horizontal section inside the main productive oil reservoir; Commissioning of the new $31.6 million Central Production Facility (“CPF”) commenced on December 22, 2019 with the successful hydrostatic test of the new 20,000 barrel oil storage tank; Earned net income of $18.2 million ($0.03 per share basic) compared to a net loss of $2.2 million in Q4 2018; - - Higher operating net back of $28.6 million compared to $2.3 million in Q4 2018; - For Q4 2019 the Company recognized funds flow generated of $22.2 million, as compared to utilization of negative $1.9 million in Q4 2018; Achieved a record quarterly oil production of 7,767 bopd, an increase of 670% over Q4 2018 (1,158 bopd), and an increase of 63% over Q3 2019 (4,760 bopd); - Q4 2019 sales volumes averaged 9,509 bopd compared to 1,199 bopd in Q4 2018; and, - Capital expenditures were $26.9 million in Q4 2019 compared to $4.4 million in Q4 2018. 4 2019 Operational Highlights - - At December 31, 2019, six producing wells and one water disposal were operating, inclusive of the initial water disposal that was converted to an oil producer; The Company invested $88.4 million to drill five producing oil wells, a water disposal well and build production facilities, nearly a three fold increase from capital expenditures of $23.2 million in 2018; The Company achieved an exit rate production of 13,300 bopd at the end of 2019 with the Q4 average being 7,767 bopd. PetroTal produced a total of 1.5 million barrels of oil in 2019, representing average oil production of 4,131 bopd, an increase of 431% from the average production of 958 bopd realized in 2018; - NSAI Report shows increases in all reserve categories: - o Proved ("1P") reserves of 21.5 million barrels ("mmbbl"), an increase of 20% from the 17.9 mmbbl recorded at the end of 2018; o Proved plus Probable ("2P") reserves of 47.7 mmbbl, an increase of 21% from the 39.4 mmbbl recorded at the end of 2018; and, o Proved plus Probable and Possible ("3P") reserves of 84.8 mmbbl, an increase of 8% from the 78.7 mmbbl recorded at the end of 2018; - Net Present Value (before tax, discounted at 10%) (“NPV-10”) represents $434 million ($20.19/bbl) for 1P reserves, $1.1 billion ($23.02/bbl) for 2P reserves and $1.9 billion ($22.11/bbl) for 3P reserves; and, - Original oil in place ("OOIP") estimates for each category of reserves also increased, with the 2P estimate increasing from 329 mmbbl to 364 mmbbl. 2019 Financial Highlights - Generated revenue of $77 million ($52.32/bbl) compared to $10 million ($59.10/bbl) in 2018; - Royalties to the Peruvian government were $3.4 million (4% of revenue) during 2019 compared to $0.5 million (5% of revenue) for 2018; - Generated funds from operations of $51.9 million compared to $30 thousand in 2018, as a result of the significant increase in revenue generation; - Operating and transportation costs, were $31.9 million ($21.68/bbl) for 2019 compared to $4.9 million ($27.60/bbl) for 2018, an improvement of 22% on a per barrel basis; - Net operating income (netback) in 2019 was $41.4 million ($28.09/bbl) compared to $5.1 million ($28.72/bbl) in 2018; - Cash flow generated was $29.7 million compared to negative $3.4 million in 2018. Cash flow represents netback inclusive of G&A costs, realized gain (losses) on commodity contracts and all other cash transactions; and, At December 31, 2019, the Company had cash of $21.1 million, compared to $26.3 million at the end of 2018. - 2019 Other Highlights - On November 4, 2019, the Company announced the addition of Mr. Douglas Urch, as Executive Vice President and Chief Financial Officer of the Company; - On December 12, 2019, the Company’s board of directors declared its inaugural dividend of $0.9 million to shareholders of record on December 20, 2019; and, - On December 19, 2019, Ms. Eleanor Barker and Dr. Roger Tucker were appointed as Independent Non-Executive Directors. 4. OUTLOOK AND GROWTH STRATEGY Outlook The capital program prioritizes management's strategy to maintain a strong balance sheet during the current 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 2020, if pricing allows. 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 Bretaña oilfield as pricing allows; - 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. 5 The capital budget is based on the expected average annual Brent oil price forecast. Additionally, as credit capacity allows, the Company will arrange a hedging strategy for the future. Growth strategy Company’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 stakeholder 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; support. Throughout the year, PetroTal focused on achieving its priorities and implementing its capital programs in Peru. The Company funded its capital programs using funds generated from operations, existing cash and equity proceeds. Strategic allocation of the work program and budget is designated to provide additional recoverable reserves at the Peruvian oilfields and achieve growth in production. 5. SELECTED FINANCIAL INFORMATION 5.1 QUARTERLY SUMMARY (IN THOUSANDS OF USD) 6 EARNINGS STATEMENT INFORMATION Revenue As a result of the successful drilling and completion of oil producing wells in the Bretaña oil field during 2019, sales increased to 1,474,042 barrels (4,033 bopd) from 177,465 barrels (964 bopd) in 2018. Sales for Q4 2019 increased to 9,509 bopd as compared to Q3 2019 of 4,073 bopd and 1,199 bopd in Q4 2018. The Company sells its oil at various sales points. Approximately 1,200 bopd is delivered to the Iquitos refinery priced at the prevailing Brent oil price less a discount inclusive of barging transportation charges. The majority of the oil is delivered and sold to Petroperu at the Saramuro pump station for transportation through the North Peruvian Oil Pipeline (“ONP”) and onward to the Bayovar Port. The price is based on the average monthly Brent oil price, less approximately $4.00/bbl quality differential, and is net of all pipeline and marketing fees. When the oil is ultimately sold by Petroperu at Bayovar, PetroTal will receive a valuation adjustment based on the actual price achieved by Petroperu, whether higher or lower. As a result of higher sales volumes, annual revenue increased to $77.0 million ($52.32/bbl) in 2019 from $10.5 million ($59.1/bbl) in 2018. Similarly, higher sales volumes resulted in Q4 2019 revenue of $45.9 million ($52.49/bbl), up from $6.2 million ($56.09/bbl) for Q4 2018. Royalties per barrel in 2019 ($2.31/bbl) increased on an absolute basis due to higher oil production levels, compared to 2018 royalties per barrel of $2.78/bbl. In our current blocks, royalty is calculated on production, and ranges between five percent and twenty percent. The royalty calculation is five percent based on production of 5,000 bopd or less and twenty percent 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 per barrel in 2019 ($9.73/bbl) is affected by record oil production (mainly production from Q3 and Q4) compared to 2018 ($19.73/bbl). Management previously stated that operating costs on a per unit basis should decrease in the future due to production increases and fixed operating expenses being spread over a greater number of barrels produced. Transportation expense per barrel in 2019 ($11.95/bbl) is affected by the increased volume of crude sales occurring at the Saramuro delivery point resulting in a sales price net of ONP pipeline tariffs plus diluent used, compared to 2018 ($7.87/bbl). General and administrative expense in 2019 of $10.8 million is higher than 2018 ($7.8 million) due to increased full year activities, and with increased volumes the per barrel comparison is more in line with management expectations. 7 As production increases, management believes the per barrel cost of G&A should continue to improve. Q4 2019 administrative expenses increased due to reorganization charges and year-end accruals. Included in G&A is construction of a new pier for residents of the Bretaña community, at a cost of $0.8 million. PetroTal appreciates all the support from the community and is pleased to offer this gift for the residents to assist their easier access to the Maranon river. The Company capitalized and allocated $3.1 million of G&A during 2019 as compared to $3.5 million in 2018. For the year ended December 31, 2019, non-cash share-based compensation pertaining to performance share units granted to employees was $0.4 million (2018: $0.2 million). Depletion, Depreciation and Amortization (“DD&A”) for 2019 was $8.5 million ($5.79/bbl) as compared to $1.4 million ($7.91/bbl) for 2018. 2019 DD&A was calculated using the updated annual reserve report information prepared by NSAI at December 31, 2019. On a quarterly bases, the Q4 DD&A is $3.8 million ($4.30/bbl) as compared to $0.8 million ($7.39/bbl) in Q4 2018. DD&A is calculated based upon capital expenditures, production and 2P reserves. Derivative loss of $0.4 million in 2019 is the net fair value of outstanding embedded derivatives compared to $nil in 2018. The agreements signed with Petroperu in 2019, include a clause to adjust the risk of volatility of the global crude oil prices 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 (average minimum expected term of 6 months). Additionally, 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 the 2019 year, compared to $40 thousand impairment expensed during 2018. Deferred taxes expense of $86 thousand was recorded in 2019 compared to a $0.8 million deferred tax recovery in 2018. No additional deferred tax assets occurred in 2019. Financial expense of $0.7 million is mainly related to accretion of decommissioning obligation expense ($0.4 million) and other finance charges, as compared to $0.6 million accretion expensed during 2018. 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. 8 5.2 BALANCE SHEET INFORMATION (IN THOUSANDS OF USD) Variances occurred at year ended 2019 and 2018 Cash and liquidity At December 31, 2019, the Company held cash of $21.1 million, a $5.2 million reduction from $26.3 million at year-end 2018. Working capital deficiency was $12.2 million at December 31, 2019 as compared to working capital of $26 million at December 31, 2018. The variance resulted primarily from the Company’s increased capital program and CPF construction, thereby utilizing cash, and increasing payables and receivables. Based on the enhanced values in the 2019 year-end reserve evaluation by NSAI, the Company continues to make progress towards establishing a credit facility. Having access to such a facility will strengthen PetroTal’s liquidity. Higher oil production, as a result of the 2019 development program, established the basis for higher cash flow, albeit fluctuating commodity price will have an impact. To deal with reduced cash flow, the Company maintains flexibility to reduce its cost structure, as needed. Such measures include deferring capital expenditures, seeking cost reductions from suppliers and extension of payment terms. Taking these steps will help to ensure the survival and sustenance of resource operations in Peru for all parties. 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 $10.4 million during 2019 (due to higher sales volume) and expects to recover $12.7 million in 2020 based on estimated oil sales. 9 Trade and other receivables As at December 31, 2019, trade receivables representing revenue related to the sale of crude oil and payments were received in January 2020. No credit losses on the Company’s trade accounts have been incurred. Capital expenditures The Company followed a dual prong growth strategy in 2019. The primary focus was to increase oil production with new wells, building on the success of reactivating the previously-drilled and shut-in initial discovery well in 2018. The Company incurred $88.8 million of capital expenditures compared to $23.2 million in 2018. Four successful oil wells were drilled in 2019, and the Company converted the initial water disposal well into a producing oil well. A new water disposal well was drilled into the lower flank of the field and the water being injected at this level is supporting aquifer maintenance and serving to enhance oil production. The second focus was on ensuring the Company had adequate facilities to effectively and safely 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 Bretaña oil field. This enhances construction quality and is a cost effective solution for such major infrastructure. At the end of 2019, the CPF was completed and commissioning commenced in early 2020. This CPF, along with the 2018 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 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 Bretaña 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 2019 and 2018, the Company has approximately $5 million of exploration and evaluation assets related to exploration Block 107. Trade and other payables Trade and other payables increased in 2019 as a result of the Company’s increased capital and drilling campaign in the last half of the year, thereby increasing payables and accruals. The payables are reflective of payment terms noted in the supplier contracts. 10 Derivatives The embedded derivative liability is classified as Level 2 fair value measurement. The service contract for transport of liquid hydrocarbons of ONP and Petroperu Saramuro agreements signed with Petroperu during 2019, 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 of estimated settlement, 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 of estimated settlement, the Company will be compensated by Petroperu. The $367 thousand 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, 2019. 2.1 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. Decommissioning obligations At December 31, 2019, the Company has estimated decommissioning liabilities to be $21.6 million, of which, the net present value is $17.6 million, inclusive of an addition of $10.2 million related to the construction of production facilities and the drilling campaign of the Company in the Bretaña oil field, and a revision of $3.8 million based upon a change in the un-risked interest rate. Of the total year-end 2019 amount of $17.6 million, $4.4 million is classified as short term, and $13.2 million as long term. At year-end 2018, the decommissioning obligation was $11.1 million, of which $2.1 million was classified as short term and $9.1 million as long term. 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 raised additional equity of $25.5 million gross ($23.7 million net of fees) by 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, PetroTal declared a dividend of $0.9 million to all shareholders and it was paid in January 2020. As of June 15, 2020, PetroTal has the following securities outstanding: Common shares Performance share units Performance warrants Total 5.3 NON-GAAP TERMS 673,351,810 10,871,353 26,750,000 710,973,163 95% 1% 4% 100% This report contains financial terms that are not considered measures under GAAP such as operating netback, operating netback per bbl, funds flow provided by operations, funds flow provided by operations per boe, funds flow netback per boe, free funds flow and diluted funds flow per share that do not have any standardized meaning under IFRS 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. 11 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 as follows: Funds flow provided by operations or 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. Free funds flow is a non-GAAP measure that is determined by funds flow provided by operations less capital expenditures. 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: 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. 2019 RESERVE REPORT Block 95 - Bretaña oil field Oil production commenced in Bretaña 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 Bretaña field in Block 95. This approval provided PetroTal with the necessary permits to execute its development strategy at Bretaña. The summary below sets forth PetroTal’s reserves as at December 31, 2019, as presented by NSAI, independent reserves evaluator. The figures in the following tables have been prepared in accordance with the standards contained in 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 annual information form (“AIF”) for the year ended December 31, 2019 posted on SEDAR (www.sedar.com) and on PetroTal’s website. 12 Summary of oil reserves and net present values as of December 31, 2019 Company Heavy Oil Reserves (mmbbl) Category Proved Developed Producing 11,250.1 Gross Net 11,250.1 Discounted at 0% Future Net Revenue Before Income Taxes USD Thousands Discounted at 10% 204,290.5 207,244.7 201,440.7 192,565.3 183,014.7 at 15% at 5% Discounted at 20% Proved Undeveloped 10,286.2 10,286.2 392,945.3 297,596.5 232,072.1 185,241.2 150,588.0 Total Proved Probable 21,536.2 21,536.2 597,235.8 504,841.1 433,512.8 377,806.5 333,602.8 26,152.9 26,152.9 1,089,017.4 836,244.1 664,253.6 542,575.8 453,319.3 Total Proved plus Probable 47,689.1 47,689.1 1,686,253.1 1.341,085.2 1,097,766.4 920,382.3 786,922.0 Possible 37,109.8 37,109.8 1,691,266.8 1,107,715.7 777,454.0 575,264.2 442,898.0 Total Proved plus Probable & Possible 84,798.9 84,798.9 3,377,519.9 2,448,800.9 1,875,220.4 1,495,646.5 1,229,820.0 Summary of Pricing and Inflation Rate Assumptions – Forecast Prices and Costs (US$/bbl) Year-End Forecast: Brent January 1, 2020 Brent January 1, 2019 2020 $66.33 $68.20 2021 $67.94 $70.98 2022 $70.06 $73.35 2023 $71.66 $75.40 2024 $73.27 $77.35 2025 $74.57 $79.40 Year-End Crude Oil Reserves (mmbbl) Category Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved plus Probable Possible Total Proved plus Probable & Possible 2019 11.2 10.3 21.5 26.2 47.7 37.1 84.8 2018 1.6 16.3 17.9 21.5 39.4 39.3 78.7 Change 600% -37% 20% 22% 21% -6% 8% Represents gross and net barrels since PetroTal owns a 100% working interest and a 100% net revenue interest in these properties. Royalties are paid from sales proceeds. Year-End Net Present Value at 10% - before income tax ($ millions) Category Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved plus Probable Possible Total Proved plus Probable & Possible 2019 $202 $232 $434 $665 $1,098 $777 $1,875 2018 $52 $99 $151 $385 $536 $718 $1,254 Change 287% 134% 187% 72% 105% 8% 50% Year-End Net Asset Value ("NAV") per Share – before income tax Category Proved Proved plus Probable Proved plus Probable & Possible December 31, 2019 CAD$/sh $0.87 $2.17 $3.72 US$/sh $0.65 $1.63 $2.79 December 31, 2018 US$/sh $0.28 $0.72 $1.00 CAD$/sh $0.37 $0.96 $1.33 Represents NPV-10 divided by common shares issued as of December 31 of each respective year. Canadian share prices are converted at the respective year end foreign exchange conversion rates. 13 Reserve Life Index (“RLI”) Category Proved Proved plus Probable Proved plus Probable & Possible Future Development Costs December 31, 2019 7.7 years 17.0 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: $124 million Proved Proved plus Probable $194 million Proved plus Probable plus Possible $299 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 in 2019 Proved ("1P") reserves increased by 20%, to 21.5 million barrels ("mmbbl") from 17.9 mmbbl, Proved plus Probable ("2P") reserves increased by 21% to 47.7 mmbbl from 39.4 mmbbl, and Proved plus Probable and Possible ("3P") reserves increased by 8% to 84.8 mmbbl from 78.7 mmbbl. At year-end 2019, Net Present Value (before tax, discounted at 10%) (“NPV-10”) represents $434 million ($20.19/bbl) for 1P reserves, $1.1 billion ($23.02/bbl) for 2P reserves and $1.9 billion ($22.11/bbl) for 3P reserves. Related to 2019 oil production of 1.5 mmbbl, reserve additions replaced 240% of 1P reserves, 553% of 2P reserves and 407% of 3P reserves. Bretaña's reserve life index for 1P and 2P reserves is now 7.7 years and 17.0 years, respectively. The cumulative capital invested combined with all future development and abandonment costs represents total finding and development costs of $12.04/bbl for 1P reserves, $5.32/bbl for 2P reserves and $4.06/bbl for 3P reserves. Original oil in place ("OOIP") estimates for each category of reserves also increased, with the 2P estimate increasing from 329 mmbbl to 364 mmbbl. In addition to ongoing development of the Bretaña oilfield, there are other prospects within Block 95 and exploration opportunities in Block 107. Exploratory Block 107 – Osheki PetroTal has a 100% working interest in these 623,280 acres block of which the Osheki prospect is estimated by NSAI to have 534 mmbo of mean prospective recoverable oil resources. This estimate is based on a recovery factor of 30 percent of the estimated 1.78 billion barrels of mean prospective original oil in place (“OOIP”), using maps generated from seismic acquired in 2007 and 2014. The mean risked prospective resources figure for the Osheki prospect is 85 mmbbl. 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, could contain a total of 4.6 billion barrels of recoverable resource in the high estimate case. One of them is the Constitucion Sur lead that the Company expects to upgrade to a prospect. The mean unrisked prospective resources figure for Constitucion is 68.5 mmbo. Drilling permits for the Osheki prospect have been approved and the Company is evaluating a drilling program for Constitucion Sur in future years. 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 14 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, 2019 and 2018. Additional information about significant judgements and estimates are included in PetroTal’s audited Financial Statements for the years ended December 31, 2019 and 2018. 8. SUBSEQUENT EVENTS Subsequent to the year-end, on March 11, 2020, the World Health Organization characterized the outbreak of a strain of the novel coronavirus (COVID-19) as a pandemic which has resulted in a series of public health and emergency measures that have been put in place to combat the spread of the virus. In May 2020, the Company was notified by Petroperu, the operator of Peru’s ONP that it has temporarily shut down the pipeline as a result of a directive from the Peruvian government intended to combat the spread of COVID-19 in the communities adjacent to the pipeline operations. The directive states that no employees over the age of 65 or with serious chronic diseases should be working in the high-risk regions of Peru. In conjunction with the pipeline shut-down, the Company shut-in operations at the Bretaña oilfield. The duration and impact of COVID-19 is unknown at this time and it is not possible to reliably estimate the impact that the length and severity of these developments will have on the financial results and condition of the Company in future periods. Significant declines in crude oil spot prices and in the equity markets have occurred for various reasons linked to the pandemic and other conditions impacting worldwide oil prices. The impairment tests for the Company’s oil assets are based on fair value less costs of disposals. In accordance with IFRS, the Company has not reflected these subsequent conditions in the recoverable amount estimates of the oil assets as at December 31, 2019. Impairment indicators for the Company’s oil assets exist at March 31, 2020 due to significant declines in forecasted oil prices from December 31, 2019 to March 31, 2020. On a monthly basis, the Company tracks the impact of fluctuating oil prices on volumes sold under both the Swap Contract and Sales Contract, as a commodity derivative and, as a result of the recent drastic drop in oil prices, the contingent liability accruing under these contracts is approximately $18 million and $24 million, respectively, at the end of March 2020. Given the current ONP timetable, it is expected that oil delivered pursuant to the Swap Contract will be sold by Petroperu in Q3 2020, and oil delivered pursuant to the Sales Contract will be sold by Petroperu commencing in Q4 2020. Under the terms of the Sales Contract, the Company is required to settle this contingent liability when the balance exceeds $10 million. On June 11, 2020, the Company entered into a contract with Petroperu to crystallize the contingent liability to be paid over a three-year period in equal installments with an interest rate of approximately 7%. The agreement is secured by the Company’s assets. The Company remains exposed to fluctuations in the commodity price from the crystallization date of June 2020 and will realize the benefit or loss of fluctuations in the commodity price when the oil is delivered as described above. On June 12, 2020, the Company entered into a broker agreement to place 141.2 million of placing units, raising gross proceeds of approximately $18 million (at 10 pence per unit). Each placing unit will be 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. 9. RELATED PARTY TRANSACTIONS AND TAXES The Company had no related party transactions or off-balance sheet arrangements. The Company’s management compensation is the following: Salaries, incentives and short-term benefits Director’s fees Stock based compensation Total compensation December 31 2019 2,552 476 195 3,223 December 31 2018 2,150 238 202 2,590 Taxes Peruvian law requires the Company to pay a two percent tax on gross revenue, which is booked as a deferred income tax asset and is 15 recoverable once the prior net operating losses of approximately $144 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 two percent payment will reduce the amount of future tax to be paid. Corporate tax rates for the Company’s license contracts in Peru are 32 percent. 10. CONTRACTUAL OBLIGATIONS AND COMMITMENTS As of December 31, 2019, 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 December 2021 2nd exploration well, minimum work 5th exploratory period December 2021 Expiration 11. 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 one percent fluctuation in translation rates would have nil impact on net income or loss, based on foreign currency balances held at December 31, 2019. 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. 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, 2019, 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. 16 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 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. Certain statements contained in this MD&A may constitute forward-looking statements. These statements relate to future events or the Company’s future performance. All statements other than statements of historical fact may be forward-looking statements. forward- looking statements are often, but not always, identified by the use of words such as “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. 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. 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 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. 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, 2019 and 2018 are available on the Company's website at www.petrotal-corp.com, and at www.sedar.com, or below: DIRECTORS Mark McComiskey Chairman 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 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 Elliot LLP Calgary, Alberta AUDITORS Deloitte LLP Calgary, Alberta REGISTERED OFFICE PetroTal Corp. 4300 Bankers Hall West, 888-3erd Street Calgary, Alberta NOMINATED & FINANCIAL ADVISER Strand Hanson Limited London, United Kingdom OPERATING OFFICE PetroTal Peru SRL Calle Dean Valdivia 148, Piso 11 Edificio Platinum Plaza Torre 1 – San Isidro Lima, Peru JOINT BROKERS Stifel Nicolaus Europe Limited London, United Kingdom Numis Securities Limited London, United Kingdom STOCK EXCHANGES Toronto Stock Exchange Toronto, Canada TAL:TSXV 17 RESERVES EVALUATORS Netherland, Sewell & Associates, Inc. Dallas, Texas Estuardo Alvarez-Calderon VP Exploration and Production Glen Priestley VP Treasury and Planning Ronald Egusquiza Peru General Manager AIM Stock Exchange London, United Kingdom PTAL:AIM OTC Stock Exchange New York, USA PTALF:OTC 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 Sh 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 Shares Annual information form North Peruvian oil pipeline agreement Benchmark to assess the profitability based on commodity price, operating and transportation costs Long Term Testing Original Oil in place 18 PETROTAL CORP. ANNUAL INFORMATION FORM For the Financial Year Ended December 31, 2019 Dated June 15, 2020 Table of Contents GLOSSARY ................................................................................................................................................. 1 CONVENTIONS ........................................................................................................................................... 3 ABBREVIATIONS ........................................................................................................................................ 3 CONVERSION ............................................................................................................................................. 3 ADDITIONAL INFORMATION CONCERNING RESERVES DATA ............................................................ 4 SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS ..................................................... 5 NAME, ADDRESS AND INCOMPANY ........................................................................................................ 9 GENERAL DEVELOPMENT OF THE BUSINESS ....................................................................................10 DESCRIPTION OF THE BUSINESS OF THE COMPANY .......................................................................12 STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION ...............................14 INDUSTRY CONDITIONS .........................................................................................................................23 RISK FACTORS .........................................................................................................................................29 DIVIDENDS ................................................................................................................................................47 DESCRIPTION OF SHARE CAPITAL .......................................................................................................48 MARKET FOR SECURITIES AND TRADING HISTORY ..........................................................................48 PRIOR SALES ...........................................................................................................................................48 ESCROWED SECURITIES .......................................................................................................................48 DIRECTORS AND OFFICERS ..................................................................................................................49 LEGAL PROCEEDINGS AND REGULATORY ACTIONS ........................................................................52 INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS ................................52 TRANSFER AGENT AND REGISTRAR ....................................................................................................53 MATERIAL CONTRACTS ..........................................................................................................................53 PROMOTERS ............................................................................................................................................53 INTERESTS OF EXPERTS .......................................................................................................................53 ADDITIONAL INFORMATION ...................................................................................................................53 Exhibit 1 Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluators .... 1-1 Exhibit 2 Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure .................. 2-1 - 1 - GLOSSARY Certain terms and abbreviations used in this Annual Information Form are defined below: "ABCA" means the Business Corporations Act (Alberta), as amended, including the regulations promulgated thereunder. "Acquisition" has the meaning attributed thereto in "Three Year History – Financial Year Ended December 31, 2017". "affiliate" or "associate" when used to indicate a relationship with a person or company, has the meaning set forth in the Securities Act (Alberta). "AIF" means this annual information form dated June 15, 2020 for the financial year ended December 31, 2019. "AIM" means AIM, the market of that name operated by the London Stock Exchange. "AIM Rules" means the AIM Rules for Companies published by the London Stock Exchange from time to time (including, without limitation, any guidance notes or statements of practice) and those other rules of the London Stock Exchange which govern the admission of securities to trading on, and the regulation of, AIM. "Arrangement" has the meaning attributed thereto in "Three Year History – Financial Year Ended December 31, 2017" below. "Board" or "Board of Directors" means the board of directors of the Company, as constituted from time to time, including where applicable, any committee thereof. "Bretaña Assets" means the Company's heavy oil assets which are located on Block 95 of onshore Peru. "Common Shares" means the common shares in the capital of the Company. "Company" or "PetroTal" means PetroTal Corp., formerly known as Sterling Resources Ltd. "Financing" has the meaning ascribed thereto under "Three Year History – Financial Year Ended December 31, 2017". "GTE" means Gran Tierra Energy Inc. "GTEIH" means Gran Tierra Energy International Holdings Ltd., a wholly owned subsidiary of GTE. "GTRL" means Gran Tierra Resources Limited, a wholly owned indirect subsidiary of GTE. "Hydrocarbon Law" means the Organic Hydrocarbon Law No. 26221 enacted by the government of Peru in 1993, which unified text was approved by Supreme Decree No. 042-2005-EM, and the regulations thereunder. "Income Tax Law" means the Legislative Decree No. 774, which Unified Text was approved by the Supreme Decree No. 179-2004-EF, and its regulations, approved by the Supreme Decree 122-94-EF, including all its amendments. "Ministry" means the Ministry of Energy and Mines of Peru. - 2 - "NI 51-101" means National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities of the Canadian Securities Administrators. "NI 51-102" means National Instrument 51-102 – Continuous Disclosure Obligations of the Canadian Securities Administrators. "NSAI" means Netherland, Sewell & Associates, Inc. "NSAI Report" means the report prepared by NSAI dated March 3, 2020, evaluating the crude oil reserves attributed to the Bretaña Assets as at December 31, 2019. "ONP" means the North Peruvian Pipeline, which transports crude oil from Station 1, in San Jose de Saramuro (Loreto), to tide-water market on Peru's west coast at the Port of Bayovar. "Perupetro" means Perupetro S.A., a private state-owned company responsible for promoting, negotiating, underwriting and monitoring contracts for exploration and production of hydrocarbons in Peru. "Peru HoldCo" means Gran Tierra International (Peru) Holdings B.V., a limited company existing under the laws of Curaçao. "Peru HoldCo Shares" means shares in the capital of Peru HoldCo. "Peruvian Business" means Peru HoldCo and its direct and indirect subsidiaries and petroleum and natural gas properties and related assets, including the Bretaña Assets, all of which were acquired by the Company by virtue of the acquisition of the Peru HoldCo Shares pursuant to the Acquisition. "PetroPeru" means Petróleos del Perú S.A., a private state-owned company dedicated to the transportation, refining, distribution and sale of fuel and other products derived from oil. "PetroTal Ltd." means PetroTal Ltd., a Company incorporated under the ABCA. "PetroTal LLC" means PetroTal LLC (formerly Talara Oil & Gas LLC), a Texas limited liability company and a wholly-owned subsidiary of the Company. "Performance Warrants" means performance warrants to purchase Common Shares issued to certain directors, officers and employees of the Company. "PetroTal Shareholders" means the holders of PetroTal Shares. "PetroTal Shares" means the common shares in the capital of PetroTal prior to the closing of the Arrangement. "PetroTal USA" means PetroTal USA Corp., a Texas limited liability company and a wholly-owned subsidiary of the Company. "Placing" has the meaning ascribed thereto under "Three Year History – Financial Year Ended December 31, 2019". "Tax Act" means the Income Tax Act (Canada), as amended, including the regulations promulgated thereunder. "TSXV" or "Exchange" means the TSX Venture Exchange. "United States" or "U.S." means the United States of America, its territories and possessions, any state of the United States of America and the District of Columbia. - 3 - CONVENTIONS Unless otherwise indicated, references herein to "$" or "dollars" are to United States dollars. All financial information with respect to the Company has been presented in United States dollars in accordance with International Financial Reporting Standards ("IFRS"). The information in this AIF is stated as at December 31, 2019, unless otherwise indicated. ABBREVIATIONS Oil, Natural Gas and Natural Gas Liquids Bbl Bbls Mbbls Bbls/d NGLs Mcf barrel barrels thousand barrels barrels per day natural gas liquids thousand cubic feet Other API BOE BOE/D m3 MBOE an indication of the specific gravity of crude oil measured on the American Petroleum Institute gravity scale. Liquid petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil. barrel of oil equivalent of natural gas and crude oil on the basis of 1 BOE for 6 (unless otherwise stated) Mcf of natural gas (this conversion factor is an industry accepted norm and is not based on either energy content or current prices) barrel of oil equivalent per day cubic metres 1,000 barrels of oil equivalent $000 or M$ thousands of dollars CONVERSION The following table sets forth certain standard conversions from Standard Imperial Units to the International System of Units (or metric units). To Convert From Mcf Cubic metres Bbls Cubic metres Feet Metres Miles Kilometres Acres Hectares To Cubic metres Cubic feet Cubic metres Bbls Metres Feet Kilometres Miles Hectares Acres Multiply By 28.174 35.494 0.159 6.290 0.305 3.281 1.609 0.621 0.405 2.471 - 4 - ADDITIONAL INFORMATION CONCERNING RESERVES DATA Reserve Categories Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on: • • • analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, specifically the forecast prices and costs. Reserves are classified according to the degree of certainty associated with the estimates. (a) (b) (c) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Other criteria that must also be met for the categorization of reserves are provided in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time (the "COGE Handbook"). Each of the reserve categories (proved, probable and possible) may be divided into developed and undeveloped categories: (a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. (i) (ii) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. (b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned. In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing - 5 - and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status. Levels of Certainty for Reported Reserves The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserve estimates are prepared). Reported reserves should target the following levels of certainty under a specific set of economic conditions: (a) (b) (c) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; at least a 50 percent probability that the quantities actually recovered will equal or exceed the estimated proved plus probable reserves; and at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves. A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook. Interests in Reserves, Wells and Properties "gross" means: (a) in relation to an issuer's interest in reserves, its "company gross reserves", which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the issuer; (b) in relation to an issuer's interest in wells, the total number of wells in which an issuer has an interest; and (c) in relation to an issuer's interest in properties, the total area of properties in which an issuer has an interest. "net" means: (a) in relation to an issuer's interest in reserves, its working interest (operating or non- operating) share after deduction of royalty obligations, plus its royalty interests in reserves; (b) in relation to an issuer's interest in wells, the number of wells obtained by aggregating the issuer's working interest in each of its gross wells; and (c) in relation to an issuer's interest in a property, the total area in which an issuer has an interest multiplied by the working interest owned by the issuer. "working interest" means the percentage of undivided interest held by an issuer in the oil and/or natural gas or mineral lease granted by the mineral owner which interest gives the issuer the right to "work" the property (lease) to explore for, develop, produce and market the leased substances. SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS Certain statements contained in this AIF may constitute forward-looking statements. These statements relate to future events or the Company's future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "predict", "potential", "intend", "could", "might", "should", "believe" and similar expressions. These - 6 - 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. 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 AIF should not be unduly relied upon by investors. These statements speak only as of the date of this AIF and are expressly qualified, in their entirety, by this cautionary statement. Forward-looking statements or information in this AIF include, but are not limited to: • • • • • • • • • the performance characteristics of the Company's oil properties; future commodity prices and costs of and supply and demand for crude oil in each market in which production is sold; future gains or losses from risk management contracts; future production volumes in 2020 and 2021, production volumes and production declines; future revenues and production costs (including royalties) and revenues and production costs per commodity unit; future capital expenditures and their allocation to specific activities or periods, particularly with respect to the estimated maintenance capital and number of wells to be drilled as part of the 2020 capital program; future growth plans through 2020 and 2021; future drilling and completion of wells; future decommissioning costs, inflation rates and discount rates used to determine the net present value of such costs; • measurement and recoverability of reserves and timing of such recoverability; • estimates of ultimate recovery from wells; • future finding and development costs, production costs, transportation costs, interest and financing costs, and general and administrative costs; • effect of existing or future contractual obligations including agreements pertaining to processing, transportation and marketing of oil; future availability and cost of drilling rigs, completion and other oilfield services; • • dates or time periods by which wells will be drilled and completed, facility construction completed and brought into service and geographical areas developed; • operating and other costs, world-wide supply and demand for petroleum products, royalty rates and treatment under governmental regulatory regimes; • productive capacity of wells, anticipated or expected production rates and anticipated dates of commencement of production and timing of results therefrom; the size of the oil reserves of the Company and anticipated future cash flows from such reserves; future sources of funding for capital programs and future availability of such sources; future asset acquisitions or dispositions; future abandonment and reclamation costs; future tax liabilities and future use of tax pools and losses; • • ability to meet current and future obligations; • • • • • development plans; • anticipated land expiries; • • • treatment under governmental regulatory regimes and tax and royalty laws; the ability to obtain financing on acceptable terms or at all; and currency, exchange and interest rates. With respect to forward-looking statements contained in this AIF, the Company has made assumptions regarding, among other things: • oil production levels; • • prevailing climatic conditions, commodity prices, interest and exchange rates; the success of the Company's operations and exploration and development activities; - 7 - the impact of increasing competition; • • availability of skilled labour, services and drilling equipment; • • timing and amount of capital expenditures; the legislative and regulatory environments of the jurisdictions where the Company carries on business or has operations; conditions in general economic and financial markets; the ability of the Company to secure necessary personnel, equipment and services; • • • government regulation in the areas of taxation, royalty rates and environmental protection; • • access to transportation routes and markets for the Company's production; and the Company's ability to obtain additional financing on satisfactory terms. • future operating costs: The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and elsewhere in this AIF: • • the global public health crisis in respect of the outbreak of the novel coronavirus ("COVID-19"), including volatility and disruptions in the supply and demand for crude oil, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people; volatility in market prices for oil and natural gas, interest and exchange rates, including between Peruvian soles and United States dollars; • uncertainties associated with estimating oil and natural gas reserves; • • the risks of the oil and gas industry, such as operational risks and market demand; legal, political and economic instability in Peru, including disruptions caused by guerrilla or indigenous groups; changes to trade relations, including between Peru and the United States; transportation and third party facility capacity constraints and access to sales markets; the ability of management to execute its business plan; • • • • governmental regulation of the oil and gas industry, including environmental regulation; • actions taken by governmental authorities, including increases in taxes and changes in government regulations and incentive programs; inadequate infrastructure in Peru; • geological, technical, drilling and processing problems; • • exploration and development activities are capital intensive and involve a high degree of risk; • • • potential delays or changes in plans with respect to exploration or development projects or capital risks and uncertainties involving geology of oil and gas deposits; risks inherent in marketing operations, including credit risk; expenditures; • availability of sufficient financial resources to fund the Company's capital expenditures; • • • unanticipated operating events which could reduce production or cause production to be shut-in or stock market volatility and market valuations; failure to realize the anticipated benefits of acquisitions and dispositions; delayed; • hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; • environmental risks (including climate change) and the cost of compliance with current and future environmental laws, including climate change laws along with risks relating to increased activism and public opposition to fossil fuels; • encountering unexpected formations or pressures, premature decline of reservoirs, and the premature and/or stronger than expected invasion of water into producing formations; the ability to add production and reserves through development and exploration activities; • • uncertainties in regard to the timing of exploration and development activities; • • changes in general economic, market and business conditions; the effect of litigation proceedings on the Company's business; - 8 - • the possibility that government policies or laws, including laws and regulations related to the environment, may change or governmental approvals may be delayed or withheld; • uncertainty in amounts and timing of royalty payments; • uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom; failure to obtain industry partner and other third party consents and approvals, as and when required; the availability of capital on acceptable terms or at all; cyber-security issues; competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel; and the other factors considered under "Risk Factors" below. • • • • • Statements relating to "reserves" are deemed to be forward-looking statements or information, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitable in the future. There are numerous uncertainties inherent in estimating quantities of proved, probable and possible reserves, including many factors beyond the control of the Company. The reserve data included herein represents estimates only. In general, estimates of economically recoverable oil reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil reserves attributable to any particular group of properties and classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The actual production, revenues, taxes and development and operating expenditures of the Company with respect to these reserves will vary from such estimates, and such variances could be material. The Company has included the above summary of assumptions and risks related to forward-looking information provided herein in order to provide investors with a more complete perspective on the Company's current and future operations and such information may not be appropriate for other purposes. This AIF may contain forward-looking statements attributed to third party industry sources. Readers are cautioned that the foregoing lists of factors are not exhaustive. The forward-looking statements contained herein, and the documents incorporated by reference herein, are expressly qualified by this cautionary statement. Except as required by applicable securities laws, the Company does not undertake any obligation to publicly update or revise any forward-looking statements and readers should also carefully consider the matters discussed under the heading "Risk Factors" below. The forward-looking statements or information contained herein are made as of the date hereof and the Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. Caution Respecting Reserves Information The determination of oil and natural gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved and probable reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability - 9 - and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions. The recovery and reserve estimates of oil, NGLs and natural gas reserves provided herein (including the documents incorporated by reference) are estimates only. Actual reserves may be greater than or less than the estimates provided herein. The estimated future net revenue from the production of the Company's natural gas and petroleum reserves does not represent the fair market value of the Company's reserves. Caution Respecting BOE In this AIF, the abbreviation BOE means a barrel of oil equivalent on the basis of 1 BOE to 6 Mcf of natural gas when converting natural gas to BOEs. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf to 1 BOE is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio of oil compared to natural gas based on currently prevailing prices is significantly different than the energy equivalency conversion ratio of 6 Mcf to 1 BOE, utilizing a conversion ratio of 6 Mcf to 1 BOE may be misleading as an indication of value. For example, the conversion ratio specified in the Block 95 License Contract is 5.626 Mcf to 1 BOE. NAME, ADDRESS AND INCORPORATION The Company was incorporated under the Companies Act (Alberta) on August 31, 1979 under the name of "Peoples Oil Limited". The Company was continued pursuant to articles of continuance under Section 261 of the ABCA on July 2, 1982. The Company changed its name to "Sterling Resources Ltd." on February 10, 1997. On December 18, 2017, the Company completed the Arrangement with PetroTal Ltd. under the ABCA, pursuant to which the Company: (i) acquired all of the issued and outstanding shares of PetroTal Ltd.; and (ii) amalgamated with PetroTal Ltd. and continued as one Company under the name "Sterling Resources Ltd.". See "Three-Year History – Financial Year Ended December 31, 2017". The Company changed its name to "PetroTal Corp." on June 4, 2018. On October 25, 2018, the Company amended its articles in order to comply with the AIM Rules. The Company's head office is located at 11451 Katy Freeway, Suite 500, Houston, Texas 77079. The registered office of the Company is located at Suite 4300, 888 3rd St SW, Calgary Alberta T2P 5C5. As of the date hereof, the Company is a reporting issuer in British Columbia, Alberta, Saskatchewan, Manitoba, Ontario, New Brunswick, Nova Scotia, Prince Edward Island and Newfoundland. The Common Shares are listed on the TSXV under the trading symbol "TAL" and on AIM under the trading symbol "PTAL". - 10 - The following diagram illustrates the inter-corporate relationships among the Company and its subsidiaries as at the date hereof: GENERAL DEVELOPMENT OF THE BUSINESS Three-Year History Since incorporation, the Company has been involved in the acquisition of petroleum and natural gas rights and the exploration for, and the development and production of, crude oil and natural gas. In its early years, the Company focused on onshore activities in Canada and the United States, and gained its first international assets in Romania in 1997 divesting these assets in 2015. In 1998, the Company acquired assets in the United Kingdom ("UK"), divesting these assets in 2017. Financial Year Ended December 31, 2017 On March 16, 2017, the Company sold the entire issued share capital of the Company's operating subsidiary Sterling Resources (UK) Ltd. to Oranje-Nassau Energie B.V. for a purchase price of $97.0 million. In addition, intercompany debt in the amount of $16.8 million was settled between Sterling Resources (UK) Ltd. and the Company. This transaction amounted to the sale of all or substantially all of the Company's assets and, as a result of the transaction, the Company no longer had active business operations or assets other than the cash proceeds from the transaction. At the time of announcement of the sale transaction, it was the intention of the Company to undertake a voluntary winding-up and dissolution following the completion thereof and, to that end, the Board paid an initial cash distribution to Shareholders in the aggregate amount of $92.8 million on June 30, 2017 or $0.63 per Common Share. Further distributions of the Company's remaining cash assets were at that time anticipated to be made on or prior to September 30, 2017 and during the 2018 fiscal year, respectively, prior to ultimately dissolving. On or about June 29, 2017, the Company became aware of PetroTal LLC and the potential for a transaction pursuant to which the Company would complete a reverse take-over of PetroTal LLC in connection with the acquisition of the Peruvian Business. Petrolifera Petroleum Del Peru S.R.L. (Peru corporation) PetroTal Peru S.R.L. (Peru corporation) PetroTal Peru B.V(2) (Curaçao corporation) PetroTal International (Peru) Holdings B.V. (Curaçao corporation) PetroTal LLC (Texas corporation) PetroTal Corp. (Alberta corporation Parent Co) 3.46% 100% 96.7% 100% 3.3% 96.54% PetroTal USA Corp. (Texas corporation) 100% 100% - 11 - On November 9, 2017: (a) the Company and PetroTal Ltd. entered into an arrangement agreement in respect of the reverse take-over by way of statutory plan of arrangement (the "Plan of Arrangement") involving the Company and PetroTal Ltd. (the "Arrangement"); and (b) the Company, PetroTal Ltd., GTE and GTEIHL entered into a share purchase agreement pursuant to which, and in the manner set forth in the Plan of Arrangement, the Company would acquire from GTE all of the issued and outstanding Peru HoldCo Shares in consideration for: (i) Common Shares and (ii) an option to retain a 20% working interest in Block 107 following the drilling of an initial exploration well, and the Company would thereby acquire the Peruvian Business (the "Acquisition"). In conjunction with the Arrangement and the Acquisition, on December 12, 2017, PetroTal Ltd. completed a brokered private placement offering of subscription receipts ("Subscription Receipts") at a price of $1.00 per Subscription Receipt for aggregate gross proceeds of $34 million (the "Financing"). On December 18, 2017, pursuant to the Arrangement and the Acquisition: (a) each Subscription Receipt was converted into one PetroTal Share; (b) each PetroTal Share was exchanged for 5.35 Common Shares, resulting in the issuance of an aggregate of 203,300,005 Common Shares; (c) the Company and PetroTal Ltd. were amalgamated and continued as one Company under the name "Sterling Resources Ltd."; (d) the Company acquired all the issued and outstanding Peru HoldCo Shares for 187,250,000 Common Shares; and (e) the Company's Board and management team were reconstituted. Following the completion of the Arrangement and the Acquisition, the new management team began to execute on its development and exploration plan in respect of the Peruvian Business. Financial Year Ended December 31, 2018 On January 22, 2018, management advised investors that they expected first oil from the Bretaña field in 10-12 months through long term testing and that, shortly thereafter, a new oil producing well would be spud. Management brought in facilities in stages and was able to bring the Bretaña field online in five months, at a cost that was approximately 25% less than the $24 million budgeted. On June 4, 2018, the Company changed its name from "Sterling Resources Ltd." to "PetroTal Corp.". On July 1, 2018 the Company began recording first production and revenue and set forth to bring the remaining facilities to ramp up production in the field. On October 25, 2018, in advance of listing the Common Shares on AIM, the Company amended its articles in order to comply with the AIM Rules. In November 2018, all oil and water handling facilities were in place and the field was placed on commercial production on November 30, 2018 with the declaration of commerciality in the field. On December 24, 2018, the Common Shares commenced trading on AIM under the trading symbol "PTAL". Financial Year Ended December 31, 2019 On April 18, 2019, Charles Fetzner resigned as Vice President, Asset Development of the Company. On April 22, 2019, the Company completed its second development oil well in the Bretaña field. In May 2019, the Company received approval of the Environmental Impact Assessment under the Environmental Impact Assessment System and Supreme Decree No. 039-2014-EM to allow for drilling of development oil wells and installation of related facilities in Block 95 of the Bretaña field. On May 31, 2019, the Company completed a brokered placing of 133,333,333 Common Shares at a price of £0.15 ($USD.19) on Share for aggregate gross proceeds of £20 million ($USD25.5 million) (the "Placing"). On December 12, 2019, the Company declared an interim dividend of Canadian Dollars - 12 - (“CAD$”) 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$1.14 million ($0.9 million) constituting approximately one-third of the expected total dividend payments in respect of the half year period from July 1, 2019 to December 31, 2019. On June 18, 2019, the Company completed its third development oil well. It was the Company’s first well equipped with an electric submersible pump for optimizing future well productivity. On August 21, 2019, the Company completed its second water disposal well and converted its existing water disposal well into an oil producer. On October 21, 2019, the Company completed its fourth development oil well. It was the Company's first horizontally completed well utilizing autonomous inflow control device valves aimed to maximize production output. On November 4, 2019, Douglas C. Urch replaced Greg Smith as Executive Vice President and Chief Financial Officer of the Company. Concurrent with his appointment as an officer of the Company, Mr. Urch resigned as a director and Chairman of the Board and Mark McComiskey, an existing director, was appointed as Chairman. On December 16, 2019, the Company completed its fifth development oil well. It was the Company's second horizontal well equipped with autonomous inflow control device valves and the longest horizontal well drilled to date in Peru. On December 19, 2019, Eleanor Barker and Roger Tucker were appointed as directors of the Company. On December 27, 2019, the Company entered into an oil sales contract with PetroPeru concurrent with the commissioning of the Company's first central production facility. Pursuant to the oil sales contract, the Company will utilize the NOP, owned and operated by PetroPeru, in order to deliver crude oil from Pump Station No. 1 in the Saramuro region to be ultimately sold by PetroPeru at the terminal facilities in Port Bayovar. See "Forward Contracts and Marketing". Recent Developments In January 2020, the Company announced a capital spend program of $99 million, expected to be fully funded with funds generated from operations and existing cash resources. The budget will primarily be allocated to expand the Peruvian Business to drill 4 new horizontal oil production wells, a water disposal well and a second processing facility in order to increase total field facility capacities. The capital investment program is weighted to the last half of the year and will continue to be monitored closely in light of the reduced oil price environment. On February 18, 2020, the Company began drilling a sixth development oil well, which is anticipated to have the longest lateral completion to date. Significant Acquisitions The Company has not completed any significant acquisitions during its most recently completed financial year for which disclosure is required under Part 8 of NI 51-102. DESCRIPTION OF THE BUSINESS OF THE COMPANY General The Company's business plan is focused on building value through the development and exploration of oil assets in Peru on its 1.5 million net acres of undeveloped land. The Company's immediate focus is to: (a) - 13 - continue to develop the Bretaña Assets, one of the largest undeveloped discoveries in Peru, by applying management's knowledge and leveraging management's experience with the local suppliers and regulatory bodies; and (b) secure a farm-in partner to finance the drilling of the Block 107 Osheki prospect. Specialized Skill and Knowledge The Company relies on the specialized skill and knowledge of its permanent staff to compile, interpret and evaluate technical data, drill and complete wells, design and operate production facilities and numerous additional activities required to explore for and produce oil and natural gas. From time to time, the Company employs consultants and other service providers to provide complementary experience and expertise to carry out its oil and natural gas operations effectively. It is the belief of management of the Company that its officers and employees, who have significant technical, operational and financial experience in the oil and gas industry, hold the necessary skill sets to successfully execute the Company's business strategy in order to achieve its corporate objectives. Competitive Conditions The oil and natural gas industry is intensely competitive in all its phases. The Company competes with numerous other participants in the search for, and the acquisition of, oil and natural gas properties and in the marketing of oil and natural gas. The Company's competitors include resource companies that have greater financial resources, staff and facilities than those of the Company. Competitive factors in the distribution and marketing of oil and natural gas include price and methods and reliability of delivery. The Company's ability to acquire additional property rights, to discover and produce reserves, to construct and operate production facilities and to identify and enter into advantageous commercial arrangements is dependent upon: (i) the Company developing and maintaining close working relationships with its industry partners; (ii) its ability to select and evaluate suitable properties for acquisition and development; (iii) its ability to consummate commercially attractive transactions in a competitive environment; and (iv) the maintenance of adequate financial capacity. The Company believes that its competitive position is equivalent to that of other oil and gas issuers of similar size and at a similar stage of development. See "Risk Factors - Competition". Cyclical Nature of Industry The Company's operational results and financial condition are dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely during recent years and are determined by supply and demand factors, including weather and general economic conditions, as well as political and macroeconomic conditions in other oil and natural gas regions. During 2018, crude oil pricing staged a gradual recovery through the first ten months of the year before collapsing in November over concerns of supply outpacing demand. In 2019, crude oil pricing decreased compared to 2018 as a result of a lower oil demand forecast due to trade tensions between the U.S. and China which continued to affect the global economy and fears of an oversupplied market, despite rising tensions in the Middle East. In 2020, COVID-19 and talk of supply increases from Saudi Arabia and Russia have dramatically decreased the price of crude oil. Any decline in oil and natural gas prices could have an adverse effect on the Company's financial condition. See "Risk Factors". Health, Safety and Environmental Policies PetroTal constantly monitors and actively manages its approach to environmental concerns. The Company believes that it is in compliance with applicable existing environmental laws and regulations and is not aware of any proposed environmental legislation or regulations with which it would not be in material compliance. Procedures are put in place to ensure that the utmost care is taken in the day-to-day management of the Company's oil and gas properties. However, in the future, the natural resources industry may become subject to more stringent environmental protection rules. This could increase the cost of doing business and may have a negative impact on future earnings. - 14 - PetroTal is committed to meeting industry standards in each jurisdiction in which it operates with respect to human rights, environment, health and safety policies. Management, employees and contractors are governed by and required to comply with PetroTal's environment, health and safety policy as well as all applicable national, state and local legislation and regulations. PetroTal has established roles and responsibilities to facilitate effective management of its environment, health and safety policy throughout the organization. It is the primary responsibility of the managers, supervisors and other senior field staff of PetroTal to oversee safe work practices and ensure that rules, regulations, policies and procedures are being followed. PetroTal maintains and will continue to maintain a safe and environmentally responsible work place, and will continue to provide training, equipment and procedures to all individuals in adhering to our policies. PetroTal will also solicit and take into consideration input from its neighbors, communities and other stakeholders in regard to protecting people and the environment. See "Industry Conditions" and "Risk Factors". Employees As at December 31, 2019, the Company had 50 employees in Peru and 10 employees in Houston. Reorganizations Other than as disclosed in "General Development of the Business", there have been no material reorganizations of the Company within the three most recently completed financial years or completed during or proposed for the current financial year. STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION Disclosure of Reserves Data and Other Information as of Financial Year Ended December 31, 2019 The reserves data herein is based upon the NSAI Report. The reserves data set forth below is based upon an evaluation of the NSAI Report. The NSAI Report summarizes the crude oil reserves of the Bretaña Assets and the net present values of future net revenue for these reserves using forecast prices and costs. No gas market is expected to exist for the Company's properties so natural gas reserves were not estimated in the NSAI Report. The NSAI Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101. Additional information not required by NI 51-101 has been presented to provide continuity and additional information which the Company believes is important to the readers of this information. The following tables provide summary information presented in the NSAI Report effective December 31, 2019 and based on an average of forecasts of Brent Crude futures prices prepared by three Canadian independent consultants as of December 31, 2019. The Report on Reserves Data by NSAI and the Report of Management and Directors on Oil and Gas Disclosure are attached as Exhibit 1 and Exhibit 2, respectively, to this AIF. All of the Company's reserves are onshore in the Bretaña field located at the northern edge of Block 95 in northern Peru. The NSAI Report is based on certain factual data supplied by the Company and NSAI's opinion of reasonable practice in the industry. For the purposes of the NSAI Report, NSAI did not perform any field inspections, examinations of mechanical operation, condition of facilities or possible environmental liability. The Company's gross revenue shown in the NSAI Report is the Company's share of the gross (100%) revenue from its properties prior to any deductions. Future net revenue is provided after deductions for the Company's share of royalty burden, capital costs, abandonment and reclamation costs and operating expenses but before consideration of any income taxes. Estimated Peruvian incomes taxes are a simplification of current tax law and were not prepared by a tax accountant or lawyer. The Company's financial statements and management's discussion and analysis for the year ended December 31, 2019 should be consulted for additional information regarding the Company's taxes. - 15 - There are numerous uncertainties inherent in estimating quantities of crude oil reserves and the future cash flows attributed to such reserves. In general, such estimates are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results. For those reasons, estimates of the economically recoverable crude oil reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by NSAI represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of crude oil reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein. The information relating to the Company's crude oil reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans, timing and costs related thereto, forecast operating costs, anticipated production and abandonment costs. See "Special Note Regarding Forward-Looking Statements", "Industry Conditions" and "Risk Factors". Throughout the following summary tables, differences may arise due to rounding. SUMMARY OF OIL RESERVES AND NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2019 FORECAST PRICES AND COSTS Heavy Oil(1) Gross (Mbbl) Net(2) (Mbbl) Proved Developed Producing Undeveloped 11,250.1 11,250.1 10,286.2 10,286.2 21,536.2 21,536.2 Total Proved 26,152.9 26,152.9 Total Probable 47,689.1 47,689.1 Total Proved plus Probable Total Possible 37,109.8 37,109.8 Total Proved plus Probable plus Possible 84,798.9 84,798.9 Notes: Totals may not add because of rounding. (1) PetroTal owns a 100% working interest and a 100% net revenue interest in these properties. (2) Net reserves do not include deductions for royalty expense for net oil volumes. Government royalties are included in property and mineral taxes. - 16 - NET PRESENT VALUE OF FUTURE NET REVENUE Before Income Tax Discounted at Various Rates 10% M$ 15% M$ 5% M$ Unit Value Before Income Tax Discounted at 10% $/Bbl 20% M$ 0% M$ 204,290.5 207,244.7 201,440.7 392,945.3 297,596.5 232,072.1 597,235.8 504,841.1 433,512.8 664,253.6 836,244.1 1,089,017.4 1,686,253.1 1,341,085.2 1,097,766.4 192,565.3 185,241.2 377,806.5 542,575.8 920,382.3 183,014.7 150,588.0 333,602.8 453,319.3 786,922.0 1,691,266.8 1,107,715.7 777,454.0 575,264.2 442,898.0 17.91 22.56 20.13 25.40 23.02 20.95 3,377,519.9 2,448,800.9 1,875,220.4 1,495,646.5 1,229,820.0 22.11 Description Proved Producing Undeveloped Total Proved Total Probable Total Proved plus Probable Total Possible Total Proved plus Probable plus Possible Notes: Totals may not add because of rounding. (1) Utilizes an average of forecasts of Brent Crude futures prices prepared by three Canadian independent consultants as of December 31, 2019 as detailed below. (2) Future net revenue is after deductions for the Company's share of royalty burdens, capital costs, abandonment and reclamation costs and operating expenses by before consideration of any Peruvian income taxes. After Income Tax Discounted at Various Rates 10% 5% M$ M$ 15% M$ 20% M$ 0% M$ 138,917.5 267,202.8 406,120.3 740,531.8 1,146,652.1 140,926.4 202,365.6 343,291.9 568,646.0 911,937.9 136,979.7 157,809.0 294,788.7 451,692.4 746,481.2 130,944.4 124,450.0 125,964.0 102,399.8 256,908.4 226,849.9 368,951.5 308,257.1 625,860.0 535,107.0 1,150,061.4 753,246.7 528,668.7 391,179.7 301,170.6 2,296,713.5 1,665,184.6 1,275,149.9 1,017,039.6 836,277.6 Description Proved Producing Undeveloped Total Proved Total Probable Total Proved plus Probable Total Possible Total Proved plus Probable plus Possible Notes: Totals may not add because of rounding. (1) Utilizes an average of forecasts of Brent Crude futures prices prepared by three Canadian independent consultants as of December 31, 2019 as detailed below. (2) Future net revenue is after deductions for the Company's share of royalty burdens, capital costs, abandonment and reclamation costs, operating expenses and Peruvian income taxes. - 17 - TOTAL FUTURE NET REVENUE (UNDISCOUNTED) AS OF December 31, 2019 FORECAST PRICES AND COSTS Reserves Category Revenue (M$) Property and Mineral Taxes (M$) Operating Costs (M$) Capital Development Costs (M$) Aband / Other Costs (M$) Future Net Revenue Before Income Taxes (M$) Income Tax (M$) Future Net Revenue After Income Taxes (M$) Total Proved 1,445,465.1 69,382.3 654,403.7 100,228.2 24,215.1 597,235.8 191,115.4 406,120.3 Total Proved Plus Probable Total Proved Plus Probable Plus Possible 3,278,930.7 157,194.9 1,241,045.8 163,934.2 30,502.6 1,686,253.1 539,600.9 1,146,652.1 6,093,140.0 291,895.9 2,124,493.4 261,150.1 38,080.6 3,377,519.9 1,080,806.4 2,296,713.5 Forecast Costs and Price Assumptions The forecast cost and price assumptions are based on Brent Crude futures prices and are adjusted for quality, transportation fees and market differentials. Crude oil benchmark reference pricing, inflation and exchange rates utilized by NSAI in the NSAI Report were an average of forecasts of Brent Crude futures prices prepared by three Canadian independent consultants as of December 31, 2019, as follows: SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS as of December 31, 2019 FORECAST PRICES AND COSTS Year Forecast 2020 2021 2022 2023 2024 2025 2026 2027 Thereafter Oil Price ($US/Bbl) 66.33 67.94 70.06 71.66 73.27 74.57 76.22 77.83 Escalation Rate of 2% on January 1 of each year Estimated future abandonment and reclamation costs related to a working interest have been taken into account by NSAI in determining reserves that should be attributed to a property and in determining the aggregate future net revenue therefrom, there was deducted the reasonable estimated future well abandonment and reclamation costs. No allowance was made, however, for the abandonment of any facilities. The forecast price and cost assumptions assume the continuance of current laws and regulations. Reconciliations of Changes in Reserves and Future Gross Revenue The following table reconciles the Company's gross reserves from December 31, 2018 to December 31, 2019, using forecast prices and costs. Gross reserves include oil volumes to be used to generate power for the field. - 18 - Proved (Mbbl) 17,898.2 4,542.5 600.2 (1,504.7) 21,536.2 Proved plus Probable (Mbbl) 39,353.8 9,589.7 250.3 (1,504.7) 47,689.1 Opening balance, beginning of year Technical Revision Economic Factors Less Production Total Reserves, end of year Additional Information Relating to Reserves Data Undeveloped Reserves Undeveloped reserves are attributed by NSAI in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Probable undeveloped reserves are those reserves that are less certain to be recovered than proved undeveloped reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production. Proved and probable undeveloped reserves have been assigned in accordance with engineering and geological practices as defined under NI 51-101. The Company plans to continue to develop the reserves by drilling a series of horizontal wells into the productive formation. The Company anticipates that 5 new wells will be required to produce the proved undeveloped reserves and an additional 9 new wells will be required to produce the proved plus probable reserves. There are a number of factors that could result in delayed or cancelled development, including the following: (a) changing economic conditions (due to commodity pricing, operating and capital expenditure fluctuations); (b) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (c) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion formation is no longer economic); (d) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (e) surface access issues (including those relating to land owners, weather conditions and regulatory approvals). See "Risk Factors". Significant Factors or Uncertainties Affecting Reserves Data The process of evaluating reserves is inherently complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and natural gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions and other factors and assumptions that may affect the reserve estimates and the present value of the future net revenue therefrom. These factors and assumptions include, among others: (a) historical production in the area compared with production rates from analogous producing areas; (b) initial production rates; (c) production decline rates; (d) ultimate recovery of reserves; (e) success of future development activities; (f) timing and costs of future development activities; (g) marketability of production; (h) effects of government regulations; and (i) other government levies imposed over the life of the reserves. As circumstances change and additional data becomes available, reserve estimates also change. Estimates are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and government restrictions. Revisions to reserve estimates can arise from changes in year-end prices, - 19 - reservoir performance and geologic conditions or production. These revisions can be either positive or negative. While the Company does not anticipate any significant economic factors or significant uncertainties that will affect any particular components of the reserves data, the reserves can be affected significantly by fluctuations in product pricing, capital expenditures, costs to abandon and reclaim properties, operating costs, royalty regimes and well performance that are beyond the Company's control. See "Risk Factors". Future Development Costs The following table sets forth development costs deducted in the estimation of the Company's future net revenue attributable to the reserve categories noted below: Year 2020 2021 2022 2023 2023-2028 Thereafter Total Undiscounted Forecast Development Costs (M$) Proved Reserves Proved Plus Probable Reserves Proved Plus Probable Plus Possible Reserves 91,685.0 8,246.7 296.5 - - - 100,228.2 93,885.0 69,752.7 296.5 - - - 163,934.2 103,385.0 110,858.7 46,906.4 - - - 261,150.1 Future development costs are capital expenditures required in the future for the Company to convert proved undeveloped reserves, probable reserves and possible reserves to proved developed producing reserves. The undiscounted development costs are $100 million for proved reserves, $164 million for proved plus probable reserves and $261 million for proved plus probable plus possible reserves (in each case based on forecast prices and costs). The Company expects to use a combination of internally generated cash from operations, working capital and the issuance of new equity or debt where and when it believes appropriate to fund future development costs set out in the NSAI Report. There can be no guarantee that funds will be available or that the Board of Directors will allocate funding to develop all of the reserves attributable in the NSAI Report. Failure to develop those reserves could have a negative impact on the Company's future cash flow. Interest expense or other costs of external funding are not included in the reserves and future net revenue estimates set forth above and would reduce the reserves and future net revenue to some degree depending upon the funding sources utilized. The Company does not anticipate that interest or other funding costs would make further development of any of the Company's properties uneconomic. Other Information The following table sets forth the number and status of the Company's wells effective December 31, 2019. - 20 - Producing Oil Non-Producing(3) Oil Gross(1) Net(2) Gross(1) Net(2) Peru Total 6 6 6 6 1 1 1 1 Notes: (1) (2) (3) "Gross" means total number of wells in which the Company holds an interest. "Net" means the aggregate of the percentage working interests of the Company in the gross wells. "Non-Producing" means wells that may or may not have been previously on production (oil and water) the date production will be obtained from these wells is uncertain. Properties with no Attributed Reserves The following table summarizes, effective December 31, 2019, the gross and net acres of undeveloped properties in which the Company had an interest and also the number of net acres for which its rights to explore, develop or exploit could expire within one year. Undeveloped Acres Gross 1,466,500 1,466,500 Net 1,466,500 1,466,500 Developed(1) Acres Gross 10,000 10,000 Net 10,000 10,000 Total Acres Gross 1,476,500 1,476,500 Net 1,476,500 1,476,500 Peru Total Note: (1) The acres shown as "Developed" refer to the expected size of the Bretaña field. Significant Factors or Uncertainties Relevant to Properties With No Attributed Reserves There are several economic factors and significant uncertainties that affect the anticipated exploration and development of the Company's properties with no attributed reserves. The Company will be required to make substantial capital expenditures in order to explore, exploit, develop, prove and produce oil from these properties in the future. If the Company's cash flow is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or, if available, on terms acceptable to the Company. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain opportunities and reduce or terminate its operations. The inability of the Company to access sufficient capital for its exploration and development activities could have a material adverse effect on the Company's ability to execute its business strategy to develop these prospects. See "Risk Factors". The significant economic factors that affect the Company's development of its lands to which no reserves have been attributed are future commodity prices for oil and the Company's outlook relating to such prices, and the future costs of drilling, completing, equipping, tie-in and operating the wells at the time that such activities are considered in the future. The significant uncertainties that affect Company's development of such lands are: (a) the future drilling and completion results the Company achieves in its development activities; (b) drilling and completion results achieved by others on lands in proximity to the Company's lands; and (c) future changes to applicable regulatory or royalty regimes that affect timing or economics of proposed development activities. All of these uncertainties have the potential to delay the development of such lands. Alternatively, uncertainty as to the timing and nature of the evolution or development of improved exploration drilling, completion and production technologies have the potential to accelerate development activities and enhance the economics relating to such lands. - 21 - Forward Contracts and Marketing PetroTal is exposed to market risks resulting from fluctuations in commodity prices, foreign exchange rates and interest rates in the normal course of operations. A variety of derivative instruments may be used by PetroTal to reduce its exposure to fluctuations in commodity prices and foreign exchange rates. The Company primarily sells crude oil based on prevailing market pricing. The Company has entered into an oil sales contract with PetroPeru, whereby PetroPeru has agreed to purchase crude oil at Pump Station No.1 located in San Jose de Saramuro, approximately 460 kilometers from the Bretaña field. The crude oil delivered to Station No. 1 is sold based on the monthly average reference price of the Brent Index minus discounts. PetroPeru ultimately sells the crude oil at the Bayovar Terminal, located in the department of Piura, and provides the Company with a valuation adjustment based on the actual price achieved, whether higher or lower. The oil sales contract continues for a one-year period and may be extended by mutual agreement of both parties. The service contract for transport of liquid hydrocarbons of the North-Peruvian Oil Pipeline (“NOP”) and Petroperu Saramuro agreements signed with Petroperu during 2019, 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. On a monthly basis, the Company tracks the impact of fluctuating oil prices on volumes sold under both the Swap Contract and Sales Contract, as a commodity derivative and, as a result of the recent drastic drop in oil prices, the contingent liability accruing under these contracts is approximately $18 million and $24 million, respectively, at the end of March 2020. Given the current ONP timetable, it is expected that oil delivered pursuant to the Swap Contract will be sold by Petroperu in Q3 2020, and oil delivered pursuant to the Sales Contract will be sold by Petroperu commencing in Q4 2020, Under the terms of the Sales Contract, the Company is required to settle this contingent liability when the balance exceeds $10 million. On June 15, 2020, the Company entered into a contract with Petroperu to crystalize the contingent liability to be paid over a three year period in equal installments with an interest rate around 7%. The agreement is secured by the Company’s assets. The Company remains exposed to fluctuations in the commodity price from the crystallization date of June 2020 and will realize the benefit or loss of fluctuations in the commodity price when the oil is delivered as described above. The $367 thousand fair value of the embedded derivative, considering an average future Brent price marker differential was recorded as a loss on derivative expense and related derivative liability as at December 31, 2019. Volume Bbl Sales price US$/Bbl Future price US$/Bbl Net Balance M$ NOP Agreement August 2019 delivery October 2019 delivery December 2019 delivery PetroPeru Saramuro December 2019 delivery December 2019 delivery December 2019 delivery Totals 200,001 207,922 172,009 254,172 40,200 85,142 59.66 64.37 68.17 64.30 64.30 65.17 64.65 63.44 62.46 997 (193) (982) 64.00 64.00 64.00 (77) (12) (100) (367) - 22 - Tax Horizon Based on NSAI production forecasts, planned capital expenditures and the forecast commodity pricing applied in the NSAI Report, the Company estimates that it will not be required to pay current income taxes until December 2021. The current corporate income tax is 32% and allows for the Company to deduct prior capital spent against future net income. See "Risk Factors – Tax Risk". Costs Incurred The following table summarizes the Company's gross property acquisition costs, exploration costs and development costs for the year ended December 31, 2019. Property Acquisition Costs Capital Investment ($M) Costs ($M) Proved Properties - Unproved Properties - Exploration Costs 0.4 Development Costs 88.4 Exploration and Development Activities The following table summarizes the gross and net exploration and development wells in which the Company participated during the year ended December 31, 2019. Natural gas wells Oil wells Water wells Stratigraphic test wells Dry holes Total Planned Capital Expenditures Development Wells Net Gross - - 6 6 1 1 - - - - 7 7 Exploration Wells Net - - - - - - Gross - - - - - - Total Wells Gross - 6 1 - - 7 Net - 6 1 - - 7 The Company plans to continue to develop the reserves by drilling a series of horizontal wells into the productive formation. The Company anticipates that 5 new wells will be required to produce the Company's proved undeveloped reserves and an additional 9 new wells will be required to produce the Company's proved plus probable reserves. Additionally, water injection wells, and equipment to inject the water back into the formation for environmental purposes, will be required. The Company plans to focus on the development of the proved plus probable reserves for the foreseeable future. As of the date hereof, the Company has drilled and completed 5 wells in Bretaña in 2019 and expects to drill up to 5 additional wells by the end of 2020. Production Estimates The following table discloses for each product type the total average daily volume of production estimated by NSAI in the NSAI Report for 2020 in the estimates of future net revenue from gross proved and gross proved plus probable reserves disclosed above. Proved Peru Total Proved Probable Peru Heavy Oil (Bbls/d) 3,934 3,934 4,776 - 23 - Heavy Oil (Bbls/d) 4,776 8,710 Total Probable Total Proved plus Probable Other Oil and Gas Information The Company's primary development asset, the Bretaña oil field, is located in the Marañón Basin of Northern Peru that has been producing since the early 1970's. The Bretaña field was drilled by Gran Tierra Energy Inc. (GTE) after completing a detailed seismic program. The initial well eventually tested 3,095 Bbls/d, with an average of 2,550 Bbls/d, and was shut in pending the installation of facilities. GTE had also drilled a water disposal well that will be used to reinject any water produced with future oil production. PetroTal has brought the initial well back online. PetroTal is initially delivering its crude oil to the Iquitos refinery via double-hull barges, and also delivering crude oil using the existing ONP (North Peruvian Pipeline) that has capacity to deliver the crude to the West Coast of Peru. The Talara refinery near the delivery point has capacity to accept the crude oil production from Bretaña. Alternatively, the Company could export the crude oil. Bretaña (Block 95) Block 95, where the Bretaña Assets are located, is on the southeastern flank of the Marañón Basin. The surface terrain is characterized by rainforest flood plains that can be covered by overflow of the Ucayali River for five to six months of the year. The field itself is a large, gently dipping four-way closure with a northwest-southeast trend. In 1974, Amoco Corporation drilled the 1-X discovery well, which encountered oil within the Upper Cretaceous Vivian Formation and flowed at approximately 800 barrels of 18.5 degree- API oil per day. There are established infrastructure and export routes in northcentral onshore Peru, consisting of barging and the ONP. It is expected that the ONP will be in full operation for the production stage of Bretaña and that the barges will be available for the production stage of Bretaña to transport crude to the ONP access point at Pump Station No. 1 in San Jose de Saramuro. As at December 31, 2019, the Bretaña Assets included approximately 10,000 gross proved developed (10,000 net developed acres) acres of total land, which is the expected area of the Bretaña oil field. The Bretaña Assets include 6 gross (6 net producers ) wells in total, including the oil producer which was brought on production during the year and 1 water injector wells as the other three wells were previously plugged and abandoned (1-X-ST1, BS-2). As at December 31, 2019, 6 producing wells and one water disposal were operating on the Bretaña Assets. The Company has a 100% working interest in the Bretaña Assets. The initial water disposal was converted to an oil producer. The following wells have been drilled and completed by the Company in the Bretaña field; 2-1XD, 01, 2XD, 3D, 4H, 5H and 2WD. The northern portion of the field is covered by sparse 2-D seismic line while the south has more extensive coverage of 2-D and 3-D cube data. INDUSTRY CONDITIONS land tenure, acquisitions, The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including refining, transportation, marketing, pricing and taxation) imposed by legislation enacted by various levels of government in Peru, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect the Company's operations in a manner materially different than they would affect other oil and gas companies of similar size which are also operating in Peru. All legislation is published in the Official Gazette, "El Peruano" and the Company is transfers, exploration, development, production, - 24 - unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry in Peru. Legislation and Regulation Hydrocarbon Legislation Peru's hydrocarbon legislation, which includes the Hydrocarbon Law, governs the Company's operations in Peru. This legislation: (a) covers the entire range of petroleum operations; (b) defines the roles of Peruvian government agencies that regulate and interact with the oil and gas industry; (c) provides that private investors (both national and foreign) (hereafter, "Contractors") may make investments in the petroleum sector; and (d) promotes the development of hydrocarbon activities by fostering competition and access. Under the Peruvian legal system, the state is the owner of all sub-surface hydrocarbons located within its borders. The Peruvian government plays an active role in petroleum operations through various entities and agencies, including: • Perupetro: the state company responsible for promoting and overseeing investment in hydrocarbon exploration and production activities that is empowered, on behalf of the state, to enter into contracts with Contractors relating to exploration and production of petroleum and natural gas; • • • • • • the Ministry: the government department that establishes energy, mining and environmental protection policies, enacts rules applicable to these sectors and supervises compliance with such policies and rules; the Vice-Ministry of Hydrocarbons: the government department responsible for communicating with oil and gas companies that have current or planned investments in Peru; the General Directorate of Hydrocarbons: the agency of the Ministry responsible for regulating the development of oil and gas fields; the Direccion General de Asuntos Ambientales Energeticos: the agency of the Ministry responsible for reviewing and approving environmental regulations related to environment risks that result from hydrocarbon exploration and production activities; the Organismo Supervisor de la Inversión en Energía y Minería (OSINERGMIN): the government agency that monitors occupational health and safety standards in the hydrocarbon industry; the Environmental Evaluation and Fiscalization Entity (Organismo de Evaluación y Fiscalización Ambiental) (OEFA): the agency within the Ministry of the Environment that is responsible for ensuring Contractors' compliance with environmental rules and sanctioning non-compliant companies; and • Servicio Nacional de Certificación Ambiental para las Inversiones Sostenibles (SENACE): the agency within the Ministry of the Environment which is in charge of the review and approval of detailed Environmental Impact Studies. The Company is subject to the laws and regulations of all of these entities and agencies as well as the Ministry of Agriculture, the Ministry of Culture and the Dirección General de Capitanías y Guardacostas del Perú (DICAPI). Exploration and Production Agreements - 25 - Contractors must enter into license agreements and/or service contracts with Perupetro prior to engaging in oil and gas exploration and production activities in Peru. License agreements give Contractors the right to both produce and sell hydrocarbons, whereas service contracts only entitle Contractors to produce hydrocarbons. Peru's laws allow for other contract models, but such models must be authorized by the Ministry. Perupetro will only contract with Contractors that meet the qualifications specified in the regulations under the Hydrocarbon Law. These qualifications require Contractors to have the technical, legal, economic and financial capacity to comply with all obligations they will assume under the contracts. Perupetro's assessment of whether Contractors are qualified is based, among other things, on the characteristics of the land in question, the level of the Contractors' investments and whether the Contractors' operations are governed by satisfactory environmental protection rules. When a Contractor is a foreign investor, it must either: (a) incorporate a Peruvian subsidiary; or (b) register a local branch with local representatives in Peru. Once Perupetro has confirmed qualifications, the qualified Contractor must be registered on the Hydrocarbons Contractors Registry, administered by the Peruvian Public Records Office. The Company operates in Peru through PetroTal Peru S.R.L., a wholly-owned subsidiary of Peru HoldCo, and Petrolifera Petroleum Del Peru S.R.L. The Company is required to guarantee its subsidiary's obligations. Such guarantee provides for joint and several liability to Perupetro with respect to the fulfillment of PetroTal Peru S.R.L.'s responsibilities, including with respect to minimum work program requirements. On August 2, 2018, Perupetro qualified the Company as an operator in Peru after which the Company made application and filed the needed paperwork to issue new guarantees to Perupetro. The Company and its subsidiaries have been qualified by Perupetro with respect to all license agreements. Perupetro reviews Contractors' qualifications each time they prepare to enter into an exploration and production agreement. Pursuant to the license agreements, Contractors acquire the right to explore for and produce hydrocarbons in a specified area. Perupetro transfers the property right in the extracted hydrocarbons to the licensee and, in consideration for such right, the licensee must pay a royalty to the state. The determination of the royalties is made according to the production of hydrocarbons in the area of such agreement. The payment of the royalty depends on the valorization methodology established in each license agreement. The licensee is entitled to market or export such hydrocarbons in any manner whatsoever, in accordance with the terms of the license agreement, and can fix hydrocarbon sales prices according to market forces, subject to a limitation in the case of natural emergencies, in which case the law stipulates such manner of marketing. License agreements contemplate an exploration phase and an exploitation phase. Oil and gas licenses are typically granted for fixed terms with opportunity for extension. The duration of the license agreements is based on the nature of the hydrocarbons discovered. The license agreement duration for crude oil is 30 years, while the contract duration for natural gas and condensates is 40 years. These durations include the exploration and discovery phases. In the event a block contains both oil and gas the 40-year term may apply to oil exploration and production as well. The license agreement commences on the date established in the license agreement. Most contracts include an exploration phase and an exploitation phase, unless the contract is solely an exploitation contract. Within the contract term, seven years is allotted to exploration, with the possibility of an extension of up to three years, granted at the discretion of Perupetro. A potential retention period for a maximum of five years (ten years for natural gas) is also available if certain factors recognized by law delay the economic viability of a discovery, such as a lack of transportation facilities or a lack of a market. The exploration phase is generally divided into several periods and each period includes a minimum work program. The term of the exploration phase may last longer than the prescribed seven years, or ten years if the three-year extension was granted, as the time elapsed for the approval of the respective environmental permits is not taken into consideration as part of the respective exploration period. However, the term of the license agreement stays the same. The fulfillment of the minimum work program must be supported by an irrevocable bank guarantee, which amount is determined taking into consideration the estimated value of the minimum work program. - 26 - Upon a declared discovery, and at the Contractor's request, the exploitation phase commences with a 30 year term (40 years for natural gas), which term includes the 7-year exploration period, extendable under certain circumstances. If a discovery is made but, for reasons relating to transportation, it is non- commercial, the Contractor may request a retention period of up to five years (ten years for natural gas) in order to make transportation feasible. All discoveries must be reported to Perupetro. At the end of the exploration phase, the contractor must declare commerciality or return the block. Contractors are obligated to submit monthly reports to Perupetro. Contractors must also submit a monthly economic report to the Central Reserve Bank of Peru. These reports are generally combined and delivered together with other operating reports required to be submitted to Perupetro. The Company has two license agreements. As of the date hereof, the Company believes it is in compliance with all of the material requirements of each contract. The Company has executed certain letters of guarantee in favor of Perupetro to insure performance under the license agreements. Should the Company fail to fulfill its minimum work program obligations under any of the license agreements without technical justification or other good cause, Perupetro could seek recourse to the letters of credit posted as a guarantee for the performance of the license agreements, the parent company guarantees and terminate the license agreement. Peruvian Fiscal Regime Peru's fiscal regime determines the government's entitlement from petroleum activities. This regime is subject to change, which could negatively impact the Company's business. However, the Hydrocarbon Law and the regulations thereunder governing the tax stability guarantee and other tax rules provide that the tax regime in force on the date of signing a contract will remain unchanged during the term of the contract. Therefore, any change to the tax regime, which results in either an increase or decrease in the tax burden, will not affect the Contractor. During the exploration phase, Contractors are exempt from import duties and other forms of taxation applicable to goods intended for exploration activities. Exemptions are withdrawn at the production phase, but exceptions are made in certain instances, and the operator may be entitled to temporarily import goods tax-free for a two-year period ("Temporary Import"). A Temporary Import may be extended for additional one year periods for up to two years upon: (a) the Contractor's request; (b) approval of the Ministry; and (c) authorization of the Superintendencia Nacional de Aduanas y de Administracion Tributaria (Peruvian Customs Agency). Taxable income is determined by deducting allowable operating and administrative expenses, including royalty payments. Income tax is levied on the income of the Contractor based upon the legal corporate tax rate in effect at the date the license agreement was signed. As of the date hereof, the statutory tax rate applicable to corporate income in Peru is 29.5%, plus an additional 2% rate for Hydrocarbon activities. Tax losses can be carried forward for five years or, at a company's election, indefinitely with a restriction that they can be used to offset only up to 50% of taxable income in any given year. The Organic Law for Hydrocarbons and the related tax regulations ensure that the tax regime in effect at the signing date of each license will not change during the life of that license. Taxpayers in Peru are required to make estimated monthly tax payments which can be refunded at the end of the fiscal year if they exceed the actual income tax assessed. Contractors engaged in the exploration and production of crude oil, natural gas and condensates must determine their taxable income separately for each license agreement under which they operate. Where a Contractor carries out these activities under different individual license agreements, it may offset its earnings before income tax under one license agreement with losses under another license agreement, for purposes of determining the corporate income tax, provided that the individual license agreements are held by the same entity, as Peruvian tax law does not permit filing a consolidated tax return for related companies. However, under no circumstances can the investment in the producing property be amortized for tax purposes unless the Contractor is under the commercial stage of production. - 27 - Peruvian Labor and Safety Legislation Oil and gas operations in Peru are subject to the Productivity and Labor Competitiveness Law (the "Labor Law"), which governs the labor force in the petroleum sector. In addition to the Labor Law, the Hydrocarbon Law and related safety regulations for the petroleum industry also regulate the safety and health of workers involved in the development of hydrocarbon activities. All entities engaged in the performance of activities related to the petroleum industry must provide the General Hydrocarbons Bureau with the list of their personnel on a semi-annual basis, indicating their nationality, specialty and position. These entities must also train their workers on the application of safety measures in the operations and control of disasters and emergencies. The regulations also contain provisions on accident prevention and personnel health and safety, which in turn include rules on living conditions, sanitary facilities, water quality at workplaces, medical assistance and first-aid services. Provisions specifically related to oil and gas exploration also contained in the regulations and include safety measures related to camps, medical assistance, food conditions, and handling of explosives. Additional safety regulations may become applicable as the Company expands and develops its operations. The Labor Law and the regulations thereunder define the employer/employee relationship. Employers may only terminate the employment relationship for just cause as established in the Labor Law. If an employee is terminated for any reason other than those listed in the Labor Law, the employee would be entitled to claim the payment of a severance for arbitrary dismissal (equal to 1.5 times the monthly salary for every year of services), or to request the reinstatement of his or her position. The Constitution of Peru and Legislative Decree Nos. 677 and 892 give employees of private companies engaged in activities generating income, as defined by the Income Tax Law, the right to share in a company's profits. This profit sharing is carried out through the distribution by the company of a percentage of the annual income before tax. According to Article 3 of the United Nations International Standard Industrial Classification, the Company's tax category is classified under the "mining companies" section, which sets the rate at 8%. However, in Peru, the Hydrocarbon Law states, and the Supreme Court ruled, that hydrocarbons are not related to mining activities. Hydrocarbons are included under "Companies Performing Other Activities," and as a result, oil and gas companies pay profit sharing at a rate of 5%. The profit sharing benefit granted by the law to employees is calculated on the basis of the "net income subject to taxation" and not on the net business or accounting income of companies. "Taxable income" is obtained after deducting from total revenues subject to income tax, the expenses required to produce them or maintain the source thereof. Any party engaging in hydrocarbon activities must file an "Oil Spill and Emergency Contingency Plan" with the General Directorate of Hydrocarbons, a department of the Ministry. Such plans must be updated annually and must contain information regarding the measures to be taken in the event of emergencies such as spills, explosions, fires, accidents and evacuations. Peruvian Environmental Legislation and Regulation The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Peru has enacted specific environmental regulations applicable to the hydrocarbon industry. The General Environmental Law establishes a framework within which all specific laws and regulations applicable to each sector of the economy are to be developed. Peru has enacted amendments to its environmental laws, imposing restrictions on the use of natural resources, interference with the natural environment, location of facilities, development of activities in natural protected areas, handling and storage of hydrocarbons, use of radioactive material, disposal of waste, emission of noise and other activities. Additionally, the laws require monitoring and reporting obligations in the event of any spillage or unregulated discharge of hydrocarbons. These laws and regulations are designed to ensure a continual balance of environmental and petroleum interests, and are subject to change. The regulations stipulate certain environmental standards expected from contractors. They also specify appropriate sanctions to be enforced if a contractor fails to maintain such standards. The OEFA is the agency within the Ministry of the Environment that is responsible for - 28 - evaluating and ensuring compliance with applicable environmental laws and regulations covering hydrocarbon activities, and for sanctioning non-compliant companies. The Environmental Regulations for Hydrocarbon Activities provide that companies participating in the implementation of projects, performance of work and operation of facilities related to hydrocarbon activities are responsible for the emission, discharge and disposal of wastes into the environment. Such companies must file an annual report describing the company's compliance with the current environmental legislation. For each proposed project, a company involved in hydrocarbon activities must prepare and file an Environmental Impact Assessment ("EIA") (which content and level of detail could vary depending on the impacts of the specific project) with the SENACE, an agency of the Ministry of Environment, in order for a company to demonstrate that its activities will not adversely affect the environment and to show compliance with the maximum permissible emission limits set forth by the Ministry. Such proposals must be approved by the SENACE prior to the development of the activities included in such instrument. The Company has prepared an EIA and expects to obtain environmental approvals for its operations in early May 2019. Any failure to comply with environmental protection laws and regulations, the import of contaminated products, or the failure to keep a monitoring register or send reports in a timely fashion could subject the responsible company to fines. In addition to certain pollution coverage related to our surface facilities, the Company maintains insurance coverage for seepage and pollution, cleanup and contamination from its wells. However, no such coverage can insure the Company fully against all risks, including environmental risks. Climate Change Regulation Peru is a signatory to the United Nations Framework Convention on Climate Change (the "UNFCCC"), which was entered into in order work towards stabilizing atmospheric concentrations of greenhouse gas ("GHG") emissions at a level to prevent "dangerous anthropogenic interference with the climate system". The UNFCCC came into force on March 21, 1994. Subsequent international negotiations led to the Kyoto Protocol, an international treaty which extends the UNFCCC and commits its signatories to reduce GHG emissions. The Kyoto Protocol was adopted in December 1997 and came into force on February 16, 2005. On December 12, 2015, the UNFCCC adopted the Paris Agreement, which Peru ratified on July 25, 2016. Under the Paris Agreement, countries have also committed to an ambitious goal of holding the increase in global average temperature to well below 2 degrees Celsius above pre-industrial levels, while they pursue efforts to limit the temperature increase to 1.5 degrees Celsius above pre-industrial levels. As of March 12, 2020, 189 of the 197 parties to the convention have ratified the Paris Agreement. In December 2019, the United Nations annual Conference of the Parties took place in Madrid, Spain. The Conference concluded with the attendees delaying decisions about prospective carbon market and emissions cuts until the next climate conference to be held in Glasgow in 2020. However, the European Union reached an agreement about "The European Green New Deal" that aims to lower emissions to zero by 2050. In September 2015, Peru submitted its Intended Nationally Determined Contribution to the UNFCCC Secretariat, pledging a 30% reduction from 2010 levels – compared to a business as usual baseline scenario – by 2030. GHG emissions legislation is emerging and is subject to change. For example, on an international level, almost 200 nations agreed on December 12, 2015, to an international climate change agreement in Paris, France, that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact the business of the Company, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas produced by the Company. - 29 - The Company anticipates that future legislation may require the reduction of GHG emissions at the Company's operations and facilities. The Company will be committed to meeting its responsibilities under any legislation involving GHG reduction requirements in the future, which may require the Company to increase capital and/or operating expenses. In addition, failure to comply with current or proposed regulations can have a material adverse effect on the Company's operations, operating expenses, compliance costs and/or may lead to the modification or cancellation of operating licenses and permits, penalties and other corrective actions. Environmental Regulation The oil and natural gas industry is subject to environmental regulations in Peru, all of which is subject to governmental review and revision from time to time. Such legislation relates to environmental impact studies, the discharge of pollutants into air and water, management of hazardous waste, including its transportation, storage, and disposal, permitting for the construction of facilities, recycling requirements and reclamation standards, and the protection of natural areas, certain plants and animal species, archaeological remains, among others, and provides for restrictions and prohibitions on the release or emitting of various substances produced in association with certain oil and gas industry operations, such as sulphur dioxide and nitrous oxide. In addition, such legislation sets out the requirements for the satisfactory abandonment and reclamation of well and facility sites. Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties. Availability of Services The availability of the services necessary to drill and complete the types of oil wells that form a substantial portion of the Company's planned exploration and development activities may be constrained due to demand and competition for such services. The oil and gas industry in South America is not as developed as the oil and gas industry in North America. As a result, the Company's exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. RISK FACTORS Investors should carefully consider the risk factors set out below and consider all other information contained herein and in the Company's other public filings before making an investment decision. The risks set out below are not an exhaustive list, and should not be taken as a complete summary or description of all the risks associated with the Company's business and the oil and natural gas business generally. Overview The Company's business consists of the exploration for, and the development and production of crude oil projects, with properties primarily in Peru. There are a number of inherent risks associated with the exploration and production of oil reserves. There are also numerous additional risks associated with operating in a developing country such as Peru. Many of these risks are beyond the control of the Company. Nature of Business An investment in the Company should be considered highly speculative due to the nature of the Company's involvement in the exploration for, and the acquisition, production and marketing of, oil reserves in a developing country and its current stage of development. Oil and gas operations involve many risks which even a combination of experience, knowledge and careful evaluation may not be able to overcome. There is no assurance that further commercial quantities of oil will be discovered or acquired by the Company, or that the Company will be able to successfully exploit its current reserves. - 30 - Commodity Price Volatility The Company's results of operations and financial condition are dependent on the prevailing prices of crude oil and natural gas. Crude oil and natural gas prices have fluctuated widely in the recent past and are subject to fluctuations in response to relatively minor changes in supply, demand, market uncertainty and other factors that are beyond the Company's control. Crude oil and natural gas prices are impacted by a number of factors including, but not limited to: the global supply of and demand for crude oil and natural gas; global economic conditions; the actions of the Organization of Petroleum Exporting Countries ("OPEC"); government regulation; political stability and geopolitical factors; the ability to transport crude to markets; developments related to the market for liquefied natural gas; the availability and prices of alternate fuel sources; and weather conditions. All of these factors are beyond the Company's control and can result in a high degree of price volatility. Market events and conditions, including global excess oil and natural gas supply, recent actions taken by OPEC, Russia's recent withdrawal from OPEC, sanctions against Iran and Venezuela, slowing growth in China and emerging economies, weakening global relationships, conflict between China and Iran, isolationist and punitive trade policies, shale production in the United States, sovereign debt levels and political upheavals in various countries including growing anti-hydrocarbon sentiment, the outbreak of COVID-19 and talk of supply increases from Saudi Arabia and Russia, have caused significant volatility in commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks, including attacks on oil infrastructure in oil producing nations, in the United States or other countries could adversely affect the economies of Peru, the United States and other countries. These events and conditions have caused a significant reduction in the valuation of oil and natural gas companies and a decrease in confidence in the oil and natural gas industry. Fluctuations in currency exchange rates further compound this volatility when the commodity prices, which are generally set in United States dollars, are stated in Canadian dollars or Peruvian soles. The Company's financial performance also depends on revenues from the sale of commodities which differ in quality and location from underlying commodity prices quoted on financial exchanges. Of particular importance are the price differentials between the Company's light/medium oil and heavy oil (in particular the light/heavy differential) and quoted market prices. Not only are these discounts influenced by regional supply and demand factors, they are also influenced by other factors such as transportation costs, capacity and interruptions; refining demand; the availability and cost of diluent used to blend and transport product; and the quality of the oil produced, all of which are beyond the Company's control. See also "Variations in Foreign Exchange Rates and Interest Rates". Fluctuations in the price of commodities and associated price differentials may impact the value of the Company's assets and the ability to maintain its business and to fund growth projects. Prolonged periods of commodity price depression and volatility may also negatively impact the Company's ability to meet guidance targets and meet all of its financial obligations as they come due. Any substantial and extended decline in the price of oil would have an adverse effect on the Company's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows from operations and may have a material adverse effect on the Company's business, financial condition, results of operations, prospects and the level of expenditures for the development of oil reserves, including delay or cancellation of existing or future drilling or development programs or curtailment in production. Crude oil and natural gas prices are expected to remain volatile for the near future as a result of market uncertainties over the supply and the demand of these commodities due to the current state of the world economies and OPEC actions. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. In addition, future bank borrowings available to the Company may, in part, be determined by the Company's borrowing base. - 31 - The Company conducts regular assessments of the carrying value of its assets in accordance with IFRS. If crude oil prices decline significantly and remain at low levels for an extended period of time, the carrying value of the Company's assets may be subject to impairment. Public Health Crisis The Company's business, operations and financial condition could be materially adversely affected by the outbreak of epidemics or pandemics or other health crisis. In December 2019, COVID-19 was reported to have surfaced in Wuhan, China; on January 30, 2020, the World Health Organization ("WHO") declared the outbreak a global health emergency; and on March 11, 2020 the WHO declared the outbreak of COVID- 19 a global pandemic. In China, reactions to the spread of COVID-19 have led to, among other things, significant restrictions on travel within China, temporary business closures, quarantines and a general reduction in consumer activity. The outbreak has spread throughout Europe and the Middle East with cases of COVID-19 increasing in Canada and the United States. The spread of COVID-19 has led companies and various international jurisdictions to impose restrictions such as quarantines, business closures and travel restrictions. While these effects are expected to be temporary, the duration of the business disruptions internationally and related financial impact cannot be reasonably estimated at this time. Similarly, the Company cannot estimate whether or to what extent this pandemic and the potential financial impact may extend to countries outside of those currently impacted. Such public health crises can result in volatility and disruptions in the supply and demand for oil and natural gas, global supply chains and financial markets, as well as declining trade and market sentiment and reduced mobility of people, all of which could affect commodity prices, interest rates, credit ratings, credit risk and inflation. In particular, crude oil prices have significantly weakened in response to the outbreak of COVID-19. The risks to the Company of such public health crises also include risks to employee health and safety and a slowdown or temporary suspension of operations in geographic locations impacted by an outbreak. At this point, the extent to which COVID-19 may impact the Company is uncertain; however, it is possible that COVID-19 may have a material adverse effect on the Company's business, results of operations and financial condition. Trade Relations To the extent that certain political actions taken in North America, Europe and elsewhere in the world result in a marked decrease in free trade, access to personnel and freedom of movement, it could have an adverse effect on PetroTal's ability to market products internationally, increase costs for goods and services required for operations, reduce access to skilled labour and negatively affect business, operations, financial conditions and the market value of the Common Shares. Major developments in tax policy or trade relations, such as the replacement of the North American Free Trade Agreement with the United States-Canada-Mexico Agreement effective as of March 13, 2020, or the imposition of tariffs, could have a material adverse effect on the Company. Further, unlegislated proposals from the government of the United States have contemplated prohibitive actions against foreign businesses competing in the United States economy. It is uncertain whether the government of the United States will proceed with any proposed or contemplated actions, or the effects those actions may have on the Company. Peru and ten other countries have agreed on the text of the Comprehensive and Progressive Agreement for Trans-Pacific Partnership (the "CPTPP"), which is intended to allow for preferential market access among the countries that are parties to the CPTPP. The CPTPP is in force among the first seven countries to ratify the agreement, including Canada, Australia, Japan, Mexico, New Zealand, Vietnam and Singapore. The agreement remains subject to ratification by the governments of the remaining three countries. While it is uncertain what effect CPTPP or any other trade agreements will have on the oil and gas industry in Peru, the lack of available infrastructure for the offshore export of oil and gas may limit the ability of Peruvian oil and gas producers to benefit from such trade agreements. - 32 - Capital Lending Markets As a result of recent economic uncertainties in the oil and gas industry and, in particular, the lack of risk capital available to the junior resource sector, particularly those in emerging market jurisdictions, the Company, along with other junior resource entities, may have reduced access to bank debt and to equity. As future capital expenditures will be financed out of funds generated from operations, bank borrowings, if available, and possible issuances of debt or equity securities, the Company's ability to fund future capital expenditures is dependent on, among other factors, the overall state of lending and capital markets and investor and lender appetite for investments in the energy industry, generally, and the Company's securities in particular. To the extent that external sources of capital become limited, unavailable or available only on onerous terms, the Company's ability to invest and to maintain existing assets or implement the exploration or development plan, or complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, may be impaired, and its assets, liabilities, business, financial condition and results of operations may be materially and adversely affected as a result. Local Legal, Political and Economic Factors The Company operates its business in Peru and may eventually expand to other countries. Exploration and production operations in foreign countries are subject to legal, political and economic uncertainties, including terrorism, military repression, social unrest, strikes by local or national labor groups, interference with private contract rights (such as nationalization), vexatious litigation, extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls. South America has a history of political and economic instability. This instability could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including the imposition of additional taxes. In an extreme case, such a change could result in renegotiation or termination of existing concessions and contract rights and expropriation of foreign-owned assets without fair compensation. Any changes in oil and gas or investment regulations and policies or a shift in political attitudes in Peru or other countries in which the Company may operate are beyond its control and may significantly hamper its ability to expand its operations or operate its business at a profit. Changes in laws in the jurisdiction in which the Company operates or expands into with the effect of favoring local enterprises, and changes in political views regarding the exploitation and protection of natural resources and economic pressures, may make it more difficult for the Company to negotiate agreements on favorable terms, obtain required licenses, comply with regulations or effectively adapt to adverse economic changes, such as increased taxes, higher costs, inflationary pressure and currency fluctuations. In certain jurisdictions, the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licenses and agreements for business. These licenses and agreements may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. Peru has experienced fluctuating inflation rates since 2002. There can be no assurance that any governmental action will be taken to control inflationary or deflationary situations or that any such action will be effective. Future governmental action may trigger inflationary or deflationary cycles or otherwise contribute to economic uncertainty. Additionally, changes in inflation or deflation rates and governmental actions taken in response to such changes may affect currency values. Any such events or changes could have a material adverse effect on the Company's operations and financial condition. - 33 - Geographic Concentration The geographic concentration of the Company's properties in Peru subjects the Company to an incremental risk of loss of revenue or curtailment of production from factors affecting that region specifically. Should that region experience abnormal weather events (such as El Niño, which may cause excessive rainfall and flooding in Peru), delays from or decreases in production, the availability of equipment, facilities or services, capacity to gather, process or transport production or a political or regulatory adverse change, all of the Company's properties could be impacted, amplifying the impact relative to other competitors operating over a wider geographic area. Political Developments in Peru Peru's history since the mid-1980s has been one of political and economic instability under both democratically elected and dictatorial governments. These governments have frequently intervened in the national economy and social structure, including periodically imposing various controls the effects of which have been to restrict the ability of both domestic and foreign companies to freely operate. Peru's recent political and fiscal regimes were generally favourable to the oil and gas industry and have been relatively stable. However, there is a risk that this will change. Current or future political regimes may adopt new policies, laws and regulations that are more hostile toward foreign investment which may result in the imposition of additional taxes, the adoption of regulations that limit price increases, termination of contract rights, or the expropriation of foreign-owned assets. Such actions by the elected political regime could limit the amount of the Company's future revenue in that country and affect its operations. The Company's interests and operations may be affected by government regulations with respect to restrictions on property access, permitting, price controls, export controls, foreign exchange controls, income taxes, foreign investment, expropriation of property and environmental legislation. There is also a risk of other adverse developments, such as labour unrest, widespread civil unrest or rebellion, which may adversely affect the Company. Labour in Peru is customarily unionized and there are risks that labour unrest or wage agreements may adversely impact the Company's operations. Guerrilla and Indigenous Activity Peru has a publicized history of security problems. The Shining Path, a guerrilla rebel organization, has been active in Peru since the early 1980's and, at one point, was active throughout the country. Recently, the group's activity has been confined to small areas of Peru; its operations have been hampered by the capture of many high profile leaders; and membership has fallen dramatically. The Company's operations in Peru are in a different region, with no known activity by the group. However, other groups may be active in other areas of the country and possibly the Company's operational areas. In addition to The Shining Path, blockades by indigenous groups have also caused disruptions to oil and gas activities in Peru. Under Peruvian law, the government is required to undertake a prior consultation process with indigenous groups that may be affected by national or regional projects in order to ensure appropriate consideration is given to their interest in the land. Any disagreements between an indigenous group and the terms of an agreement that was entered into as a result of the prior consultation process must be resolved directly between the Peruvian government and the affected indigenous group. The Company may seek to enter into cooperation agreements with affected indigenous groups with the aim of protecting, respecting and strengthening traditional practices and preserving cultural heritage. NGO Activity Against Peruvian Oil and Gas Operators - 34 - Under Peruvian law, prospective operators must evaluate whether potential projects will be located within, or adjacent to, lands occupied by an indigenous community. Furthermore, indigenous communities retain the right to be consulted in the process to ensure appropriate consideration is given to their interest in the law. Any disagreements between an indigenous group and the terms of an agreement that was entered as a result of the prior consultation process must be resolved directly between the Peruvian government and the affected indigenous group. Such disputes arising from issues relating to indigenous land rights remain contentious, especially in the Amazon region. The grievances typically relate to oil and gas companies infringing on the indigenous communities' land ownership rights and exposing isolated communities to diseases to which they are not immune. Although Peruvian authorities have now implemented measures to reduce tensions with indigenous communities, a certain level of tension does still exist. Environmental activist activity is also prevalent in Peru, with significant overlap between indigenous land rights and environmental activism. Environmental activists also hold grievances with oil and gas companies, specifically oil spills from pipelines and the contamination of drinking water. Indigenous and NGO activism can manifest itself in violent civil unrest, including erecting road and river blockages, occupation of key infrastructure, such as refineries and airports, and kidnapping of oil workers. To date, the Company has experienced no material issues with indigenous and NGO activism on its current asset base. In the event this situation changes for the negative, the Company may seek to enter into cooperation agreements with affected indigenous groups with the aim of protecting, respecting and strengthening traditional practices and preserving cultural heritage, and ultimately avoiding a disruption to operations. Markets and Marketing The marketability and price of crude oil and natural gas that may be acquired or discovered by the Company is, and will continue to be, affected by numerous factors beyond its control. The Company's ability to market its crude oil may depend upon its ability to acquire space on pipelines such as the ONP or other means of transport to bring such crude oil to commercial markets. The Company may also be affected by deliverability uncertainties related to the proximity of its reserves to pipelines and processing and storage facilities and operational problems affecting such pipelines and facilities as well as extensive government regulation relating to price, taxes, royalties, land tenure, allowable production, the export of oil and many other aspects of the oil and gas business. During 2018, the Company entered into agreements and began shipping crude oil to market via barge to a nearby refinery and by barge and truck to a refinery in Lima. The Company has established routes to market the oil it produces. The Company will continue to develop access to markets to assure oil sales and cash flow. Exploration and Production Risks Oil and natural gas exploration involves a high degree of risk and there is no assurance that expenditures made on exploration by the Company will result in new discoveries of oil or natural gas in commercial quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions such as over pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. The long term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil resources or reserves. No assurance can be given that the Company will be able to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, the Company may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic. - 35 - Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, insufficient storage or transportation capacity or other geological and mechanical conditions. While close well supervision and effective maintenance operations can contribute to maximizing production rates over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect revenue and cash flow levels to varying degrees. In addition, oil and gas operations are subject to the risks of exploration, development and production of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow outs, cratering, sour gas releases, fires, spills or leaks. These risks could result in personal injury, loss of life, and environmental or property damage. Losses resulting from the occurrence of any of these risks could have a materially adverse effect on future results of operations, liquidity and financial conditions. Weakness in the Oil and Gas Industry Recent market events and conditions, including global excess oil and natural gas supply, actions taken by OPEC, slowing growth in emerging economies, market volatility, sovereign debt levels and political upheavals in various countries have caused significant weakness and volatility in commodity prices. These events and conditions have caused a significant decrease in the valuation of oil and gas companies and a decrease in confidence in the oil and gas industry. Lower commodity prices may also affect the volume and value of the Company's reserves, rendering certain reserves uneconomic. In addition, lower commodity prices have restricted, and may continue to restrict, the Company's cash flow resulting in a reduced capital expenditure budget. Consequently, the Company may not be able to replace its production with additional reserves and both the Company's production and reserves could be reduced on a year over year basis. Fiscal and Royalty Regimes Peru has legislation and regulations which govern land tenure, drilling and construction permits, royalties, production rates, environmental protection and other matters. The royalty regime is a significant factor in the profitability of oil and natural gas production. The determination of the royalties is made according to the production of hydrocarbons in the area of such agreement. The payment of the royalty depends on the valorization methodology established in each license agreement. See "Industry Conditions". Laws and Regulations Oil and natural gas operations (exploration, production, pricing, marketing and transportation) are subject to extensive controls and regulations imposed by various levels of government in Peru and internationally that may be amended from time to time. The Company is subject to laws and regulations that can adversely affect the cost, manner and feasibility of its operations. Because the oil and gas industry in Peru is less developed than elsewhere, changes in laws and interpretations of laws are more likely to occur than in countries with a more developed oil and gas industry. Future laws or regulations, as well as any adverse change in the interpretation of existing laws or our failure to comply with existing legal requirements may harm the Company's results of operations and financial condition. In order to comply with laws and regulations, the Company may be required to make unanticipated expenditures relating, among other things, to: (a) work program guarantees and other financial responsibility requirements; (b) taxation; (c) royalty requirements; (d) customer requirements; (e) employee - 36 - compensation and benefit costs; (f) operational reporting; (g) environmental and safety requirements; and (h) unitization requirements. Health and Safety The Company is subject to labor and health and safety laws and regulations, at a national, state and local level in Peru, that govern, among other things, the relationship between the Company and its employees and the health and safety of the Company's employees. For example, the Company is required to adopt certain measures to safeguard the health and safety of its employees, as well as third parties, in its facilities. In the event that compliance by the Company with such requirements is reviewed by the applicable authorities and a decision that the Company violated any labor laws, results from such review, the Company may be exposed to penalties and sanctions, including the payment of fines and, depending on the level of severity of the infraction, exposed to the closure of its facilities and/or stoppage of its operations and the cancellation or suspension of governmental registrations, authorizations and licenses, any one of which may result in interruption or discontinuity of activities in the Company's facilities, and materially and adversely affect the Company. Insurance The Company's involvement in the exploration for and development of oil and gas properties may result in the Company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards. Although the Company has obtained insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks or additional risks may not, in all circumstances be insurable or, in certain circumstances, the Company may elect not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance or for other reasons. The payment of such uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Company's financial position, results of operations or prospects. Project Risks The Company manages and participates in a variety of small and large projects in the conduct of its business. Project delays may delay expected revenues from operations. Project cost estimates may not be accurate due to a lack of history of comparable projects. Furthermore, significant project cost over-runs could make a project uneconomic. The Company's ability to execute projects and market oil will depend upon numerous factors beyond the Company's control, including: the availability of processing capacity; the availability and proximity of pipeline capacity; the availability of storage capacity; the supply of and demand for oil and natural gas; the availability of alternative fuel sources; the effects of inclement weather; the availability of drilling and related equipment; unexpected cost increases; accidental events; currency fluctuations; changes in regulations; the availability and productivity of skilled labour; and the regulation of the oil and natural gas industry by various levels of government and governmental agencies. Because of these factors, the Company could be unable to execute projects on time, on budget or at all, and may not be able to effectively market the oil that it produces. Infrastructure, Availability of Drilling Equipment and Access Restrictions Crude oil and natural gas exploration, development and production activities depend, to one degree or another, on adequate infrastructure and the availability of drilling and related equipment in the particular areas where such activities will be conducted. Reliable roads, bridges, power sources, water supply and disposal facilities are important determinants, which affect capital and operating costs. Unusual or infrequent weather phenomena, sabotage, government or other interference in the maintenance or - 37 - provision of such infrastructure could adversely affect the operations, financial condition and results of operations of the Company. The oil and gas industry in South America is not as developed as the oil and gas industry in North America. As a result, the Company's exploration and development activities may take longer to complete and may be more expensive than similar operations in North America. The availability of technical expertise, specific equipment and supplies may be more limited than in North America. If the Company is unable to obtain, or unable to obtain without undue cost, drilling rigs, equipment, supplies or personnel, its exploration and production operations could be delayed or adversely affected. Furthermore, once oil and natural gas production is recovered, there are fewer ways to transport it to market for sale. Pipeline and trucking operations are subject to uncertainty and lack of availability. Oil and natural gas pipelines and truck transport travel through miles of territory and are subject to the risk of diversion, destruction or delay. Such factors may subject the Company's international operations to economic and operating risks that may not be experienced in North American operations. Further, the Company operates in remote areas and may rely on helicopter, boats or other transportation methods. Some of these transport methods may result in increased levels of risk and could lead to operational delays which could affect the Company's ability to add to its resource base and produce oil and could have a significant impact on its reputation or cash flow. Additionally, some required equipment may be difficult to obtain in the Company's areas of operations, which could hamper or delay operations, and could increase the cost of those operations. Strategic and Business Relationships The ability of the Company to successfully bid on and acquire additional properties, to discover resources or reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements will depend on developing and maintaining effective working relationships with industry participants and on the Company's ability to select and evaluate suitable partners and to consummate transactions in a highly competitive environment. These relationships are subject to change and may impair the Company's ability to grow. To develop the Company's business, it may enter into strategic and business relationships, which may take the form of joint ventures with other parties or with local government bodies, or contractual arrangements with other oil and gas companies, including those that supply equipment and other resources that the Company may use in its business. The Company may not be able to establish these business relationships or, if established, it may not be able to maintain them. In addition, the dynamics of the Company's relationships with strategic partners may require the Company to incur expenses or undertake activities it would not otherwise be inclined to take to fulfill its obligations to these partners or maintain its relationships. If the Company fails to make the cash calls required by its joint venture partners in the joint ventures it does not operate, the Company may be required to forfeit its interests in joint ventures. If the Company's strategic relationships are not established or maintained, its business prospects may be limited, which could diminish its ability to conduct its operations. Substantial Capital Requirements and Liquidity The Company anticipates that it will make substantial capital expenditures for the acquisition, exploration, development and production of oil and natural gas resources or reserves in the future, including in relation to its assets. If the Company's future revenues or resources decline, the Company may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that debt or equity financing, or cash flow from operations will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. Moreover, future activities may require the Company to alter its capitalization significantly. The inability of the Company to access sufficient capital for its operations could have material adverse effect on the Company's financial condition, results of operations or prospects. - 38 - Dividends The declaration and payment of future dividends (and the amount thereof) is subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time, including fluctuations in commodity prices, the financial condition of the Company, production levels, results of operations, capital expenditure requirements, working capital requirements, debt service requirements, operating costs, foreign exchange rates, interest rates, contractual restrictions, the Company's hedging activities or programs, available investment opportunities, the Company's business plan, strategies and objectives, the satisfaction of the solvency and liquidity tests imposed by the ABCA for the declaration and payment of dividends and other factors that the Board may deem relevant. Depending on these and various other factors, many of which are beyond the control of the Company, the dividend policy of the Company may vary from time to time and, as a result, future cash dividends could be reduced or suspended entirely. Pursuant to the ABCA, the Company may not declare or pay a dividend if there are reasonable grounds for believing that: (i) the Company is, or would after the payment be, unable to pay its liabilities as they become due; or (ii) the realizable value of its assets would thereby be less than the aggregate of its liabilities and stated capital of its outstanding shares. Dividends may be reduced or suspended during periods of lower cash flow from operations. The timing and amount of the Company's capital expenditures, and the ability of the Company to repay or refinance debt as it becomes due, directly affects the amount of cash dividends that may be declared by the Board. Future acquisitions, expansions of the Company's assets, and other capital expenditures and the repayment or refinancing of debt as it becomes due may be financed from sources such as cash flow from operations, the issuance of additional shares or other securities of the Company, and borrowings. Dividends may be reduced, or even eliminated, at times when significant capital or other expenditures are made. There can be no assurance that sufficient capital will be available on terms acceptable to the Company, or at all, to make additional investments, fund future expansions or make other required capital expenditures. To the extent that external sources of capital, including the issuance of additional shares or other securities or the availability of credit facilities, become limited or unavailable on favourable terms or at all due to credit market conditions or otherwise, the ability of the Company to make the necessary capital investments to maintain or expand its operations, to repay debt and to invest in assets, as the case may be, may be impaired. To the extent the Company is required to use cash flow from operations to finance capital expenditures or acquisitions or to repay debt as it becomes due, the cash available for dividends may be reduced and the level of dividends declared may be reduced or suspended entirely. Over time, the Company's capital and other cash needs may change significantly from its current needs, which could affect whether the Company pays dividends and the amounts of dividends, if any, it may pay in the future. If the Company continues to pay dividends at the current levels, it may not retain a sufficient amount of cash to finance external growth opportunities, meet any large unanticipated liquidity requirements or fund its activities in the event of a significant business downturn. The market value of the Company's securities may deteriorate if dividends are reduced or suspended. Furthermore, the future treatment of dividends for tax purposes will be subject to the nature and composition of dividends paid by the Company and potential legislative and regulatory changes. Competition The oil and gas industry is highly competitive. The Company will actively compete for acquisitions, exploration leases, licences and concessions, skilled industry personnel and capital to finance such activities with a substantial number of other oil and gas companies, many of which have significantly greater financial, technical and personnel resources than the Company. The Company's competitors will include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators. Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial, technical or personnel resources permit. The Company's size and financial status may impair its ability to compete for oil and natural gas properties and prospects. - 39 - Changes in Peruvian government regulation have enabled multinational and regional companies to enter the Peruvian energy market. Competition in oil and gas business activities has increased and may increase further, as existing and new participants expand their activities. If several companies are interested in an area, Perupetro may choose to call for bids, either through international competitive biddings or through private bidding processes by invitation, and award the contract to the highest bidder. The greater resources of competitors may be particularly important in reviewing prospects and purchasing properties in the course of such bids. Competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects than the Company is able or willing to pay. The Company's ability to acquire additional prospects and to find and develop reserves in the future will depend on its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If the Company is unable to compete successfully in these areas in the future, its future revenues and growth may be diminished or restricted. The availability of properties for acquisition depends largely on the business practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors the Company cannot control or influence. Cost of New Technologies The oil industry is characterized by rapid and significant technological advancements and introductions of new products and services utilizing new technologies. Other oil companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before the Company. There can be no assurance that the Company will be able to respond to such competitive pressures and implement such technologies on a timely basis or at an acceptable cost. One or more of the technologies currently utilized by the Company or implemented in the future may become obsolete. In such case, the Company's business, financial condition and results of operations could be materially adversely affected. If the Company is unable to utilize the most advanced commercially available technology, its business, financial condition and results of operations could be materially adversely affected. Environmental Risks All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of international conventions and national, state and local laws and regulations. As an owner, licensee and/or operator of oil and gas properties in Peru, the Company is subject to various national, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. For example, the Company is required to obtain environmental permits or approvals from the Peruvian government prior to conducting seismic operations or drilling wells in Peruvian territory. Environmental laws and regulations in Peru impose substantial restrictions on, among other things, the use of natural resources, interference with the natural environment, the location of facilities, the handling and storage of hazardous materials such as hydrocarbons, the use of radioactive material, the disposal of waste, and the emission of noise and other activities. These laws and regulations may, among other things: (a) impose liability on the owner or lessee under an oil and gas lease for the cost of property damage, oil spills, discharge of hazardous materials, remediation and clean-up resulting from operations; (b) subject the owner or lessee to liability for pollution damages and other environmental or natural resource damages; and (c) require suspension or cessation of operations in affected areas. Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require the Company to incur costs to remedy such discharge. No assurance can be given that the application of environmental laws to the business and operations of the Company will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect the Company's financial condition, results of operations or prospects. - 40 - Reserve and Resource Estimates There are numerous uncertainties inherent in estimating quantities of oil, natural gas and natural gas liquids resources, reserves and cash flows to be derived therefrom, including many factors beyond the Company's control. In estimating reserves, the chance of commerciality is effectively 100%. For prospective resources, the chance of commerciality will be the product of the chance that a project will result in a discovery of petroleum or natural gas and the chance that an accumulation will be commercially developed. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. The reserve and associated cash flow information and estimates represent estimates only. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary from actual results. For those reasons, estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom prepared by different engineers, or by the same engineers at different times, may vary. The Company's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. Further, the evaluations are based in part on the assumed success of exploitation activities intended to be undertaken in future years. The reserves and estimated cash flows to be derived therefrom contained in such evaluations will be reduced to the extent that such exploitation activities do not achieve the level of success assumed in the evaluation. Estimates of proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history and production practices will result in variations in the estimated reserves and such variations could be material. Actual future net revenue from the Company's assets will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. Actual production and revenues derived therefrom will vary from the estimates, and such variations could be material. There are numerous uncertainties inherent in estimating quantities of resources, including many factors beyond the Company's control, and no assurance can be given that the indicated level of resources will be realized. In general, estimates of recoverable resources are based upon a number of factors and assumptions made as of the date on which the resource estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of resources are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable natural gas and the classification of such resources based on risk of recovery prepared by different engineers or by the same engineers at different times may vary substantially. Estimates with respect to resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of resources, rather than upon actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same resources based upon production history will result in variations, which may be material, in the estimated resources. - 41 - Resources estimates may require revision based on actual production experience. Market price fluctuations of natural gas prices may render uneconomic the recovery of the resources. Climate Change The Company's exploration and production facilities and other operations and activities emit greenhouse gases and the Company may be required to comply with greenhouse gas emissions legislation in Peru or other countries in which the Company may operate in the future. Climate change policy is evolving at regional, national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place. Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, it is not possible to predict the impact on the Company and its operations and financial condition. See "Industry Conditions – Climate Change Regulation". Acute Climate Change Climate change has been linked to extreme weather conditions. Extreme hot weather, heavy rainfall and wildfires may restrict the Company's ability to access the Company's properties, cause operational difficulties, including damage to machinery and facilities. Extreme weather may also increase the risk of personnel injury as a result of dangerous working conditions. Certain of the Company's assets are located in locations that are proximate to forests and grasslands, and a wildfire may lead to significant downtime and/or damage to such assets. Moreover, extreme weather conditions may disrupt the Company's ability to transport produced crude oil as well as goods and services along the supply chain. Reserve Replacement The Company's future oil and natural gas reserves, production, and cash flows to be derived therefrom are highly dependent on the Company successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in the Company's reserves will depend not only on the Company's ability to develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. There can be no assurance that the Company's future exploration and development efforts will result in the discovery and development of additional commercial accumulations of oil and natural gas. Failure to Realize Anticipated Benefits of Acquisitions and Dispositions The Company makes acquisitions and dispositions of businesses and assets that occur in the ordinary course of business. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as realizing the anticipated growth opportunities and synergies from combining the acquired businesses and operations with those of the Company. The integration of acquired businesses may require substantial management effort, time and resources and may divert management's focus from other strategic opportunities and operational matters. Management assesses the value and contribution of individual properties and other assets. Finding, Developing and Acquiring Petroleum and Natural Gas Reserves on an Economic Basis Petroleum and natural gas reserves naturally deplete as they are produced over time. The success of the Company's business is highly dependent on its ability to acquire and/or discover new reserves in a cost efficient manner. Substantially all of the Company's cash flow is derived from the sale of the petroleum and natural gas reserves it accumulates and develops. In order to remain financially viable, the Company must be able to replace reserves over time at a lesser cost on a per unit basis than its cash flow on a per unit basis. The reserves and costs used in this determination are estimated each year based on numerous assumptions and these estimates and costs may vary materially from the actual reserves produced or from - 42 - the costs required to produce those reserves. The Company mitigates this risk by employing a qualified and experienced team of petroleum and natural gas professionals, operating in geological areas in which prospects are well understood by management and by closely monitoring the capital expenditures made for the purposes of increasing its petroleum and natural gas reserves. Operational Dependence Currently the Company owns a 100% working interest in all three of its licence agreements. In the event that the Company enters into any farm-in agreement, other companies may operate some of the assets in which the Company will have or has an interest. In such cases, the Company will have diminished ability to exercise influence over the operation of those assets or their associated costs, which could adversely affect the Company's financial performance. The Company's return on assets operated by others may therefore depend upon a number of factors that may be outside of the Company's control, including the timing and amount of capital expenditures, the operator's expertise and financial resources, the approval of other participants, the selection of technology and risk management practices. Reliance on Key Personnel The Company's continued success depends in large measure on certain key personnel. The loss of the services of such key personnel may have a material adverse effect on the Company's business, financial condition, results of operations and prospects. The Company may not have any key person insurance in effect. The contributions of the management team to the Company's immediate and near term operations are likely to be of central importance. In addition, the competition for qualified personnel in the oil and natural gas industry is intense, particularly in Peru, and there can be no assurance that the Company will be able to attract and retain all personnel necessary for the development and operation of its business. Management of Growth The Company may be subject to growth-related risks including capacity constraints and pressure on its internal systems and controls. The ability of the Company to manage growth effectively will require it to continue to implement and improve its operational and financial systems and to expand, train and manage its employee base. The inability of the Company to deal with this growth could have a material adverse impact on its business, operations and prospects. Permits and Licences The operations of the Company require licences and permits from various governmental authorities. There can be no assurance that the Company will be able to obtain all necessary licences and permits that are required to carry out exploration and development at its properties. The permitting process in Peru takes significant time, meaning that exploration and development projects have a longer cycle time to completion than they might elsewhere. Regulations and policies relating to licences and permits may change, be implemented in a way that the Company does not currently anticipate or take significantly greater time to obtain. These licences and permits are subject to numerous requirements, including compliance with the environmental regulations of the local governments. Revocation or suspension of the Company's environmental and operating permits could have a material adverse effect on its business, financial condition and results of operations. Expiration or Termination of Licences The Company's properties are currently held, and any future properties are expected to be held, in the form of licences and working interests in licences. If the Company or the holder of the licence fails to meet the specific requirement of a licence, the licence may terminate or expire. There can be no assurance that any of the obligations required to maintain each licence will be met. The termination or expiration of the - 43 - Company's licences or the working interests relating to a licence may have a material adverse effect on the Company's results of operations and business. The terms of Peruvian oil and gas licence agreements require licensees to perform certain minimum work programmes in each period under the seven year exploration phase of such agreements. The calculation of each period is halted when the government reviews related environmental applications, meaning the seven year exploration phase may last several years more. However, the term of the licence contract remains the same, so the holder still has 23 years to develop and produce the discovered crude oil reserves or 33 years in the case of natural gas reserves. The work programmes can include seismic acquisition, processing and interpretations and the drilling of required wells in accordance with those contracts and agreements. Licensees are also required to conduct environmental impact studies and/or environmental impact assessments and to establish their ability to comply with environmental regulations. Additional Funding Requirements The Company's cash flow from its reserves may not be sufficient to fund its ongoing activities at all times. From time to time, the Company may require additional financing in order to carry out its oil and gas acquisition, exploration and development activities. Failure to obtain such financing on a timely basis could cause the Company to forfeit its interest in certain properties, miss certain acquisition opportunities and reduce or terminate its operations. If the Company's revenues from its reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect the Company's ability to expend the necessary capital to replace its reserves or to maintain its production. If the Company's cash flow from operations and current cash balance is not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements or available on favorable terms. Variations in Foreign Exchange Rates and Interest Rates World oil and gas prices are quoted in United States dollars and the price received by Canadian and Peruvian producers is therefore affected by the Canadian/United States and Peruvian/United States dollar exchange rates, which will fluctuate over time. Future Canadian/United States and Peruvian/United States exchange rates could accordingly impact the future value of the Company's reserves as determined by independent evaluators. Furthermore, an increase in interest rates could result in a significant increase in the amount the Company pays to service debt. Issuance of Debt From time to time, the Company may enter into transactions to acquire assets or the securities of other business entities. These transactions may be financed partially or wholly with debt which may increase the Company's debt levels above industry standards. The level of the Company's indebtedness from time to time could impair the Company's ability to obtain additional financing in the future on a timely basis to take advantage of business opportunities that may arise. Currently the Company has no short or long term debt. Hedging From time to time, the Company may enter into agreements to receive fixed prices on its oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, the Company will not benefit from such increases. Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian to United States dollars or Peruvian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar or the Peruvian sol increases in value compared to the United States dollar; however, if the Canadian dollar or the Peruvian sol declines in value compared to the United States dollar, the Company will not benefit from its fluctuating exchange rate. - 44 - Information Technology Systems and Cyber-Security The Company depends on digital technology, among other things, to: process and record financial and operating data; communicate with its employees and business partners; analyze seismic and drilling information; and estimate quantities of oil and gas resources and reserves. Accordingly, the Company is susceptible to cyber incidents (both deliberate and unintentional). The unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information could disrupt the Company's business plans and negatively impact its operations in a number of ways, including: (a) negatively impact the Company's competitive position in developing its oil and gas reserves; (b) dry hole cost or drilling incidents; (c) loss of production or accidental discharge; (d) supply chain disruptions; and (e) expensive remediation efforts, distraction of management, damage to the Company's reputation, or a negative impact on the price of the common shares of the Company. As cyber threats continue to evolve, the Company may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any information security vulnerabilities. Weather Since the Company's properties are geographically concentrated in Peru's eastern region, they are influenced by factors affecting that region such as natural disasters (including earthquakes and forest fires) and severe weather conditions (including excessive rainfall and flooding). Such conditions could have a material adverse impact on the Company's business, operations and prospects. Because all the Company's properties could experience the same conditions at the same time, these conditions could have a relatively greater impact on the Company's operations than they might have on other operators who have properties over a wider geographic area. Litigation In the normal course of the Company's operations, it may become involved in, named as a party to, or be the subject of, various legal proceedings, including regulatory proceedings, tax proceedings and legal actions, related to personal injuries, property damage, property tax, land rights, the environment and contract disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty and may be determined adversely to the Company and as a result, could have a material adverse effect on the Company's assets, liabilities, business, financial condition and results of operations. Community Relationships The operations of the Company may have a significant effect on the areas in which it operates. Maintaining good community relationships is an essential aspect of operating in the oil and gas industry. Communities have demonstrated an ability and willingness to halt operations or delay approvals. To enjoy the support and trust of local populations and governments, the Company will need to demonstrate a commitment to: (a) local employment, training and business opportunities; (b) environmental stewardship; (c) open and transparent communication; and (d) community development investments that are carefully selected, not unduly costly and bring lasting social and economic benefits to the community and the area. Improper management of these relationships could lead to a delay in operations, loss of license or major impact to the Company's reputation in these communities, which could adversely affect its business. Breach of Confidentiality While discussing potential business relationships or other transactions with third parties, the Company may disclose confidential information relating to its business, operations or affairs. Although confidentiality agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put the Company at competitive risk and may cause significant damage to its business. The harm to the - 45 - Company's business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, the Company will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may cause. Conflicts of Interest Directors and officers of the Company may also be directors and officers of other oil and gas companies involved in oil and gas exploration and development, and conflicts of interest may arise between their duties as officers and directors of the Company and as officers and directors of such other companies. Such conflicts must be disclosed in accordance with, and are subject to such other procedures and remedies as apply under the ABCA. Control Persons and Other Significant Shareholders of the Company Based, in part, on public filings of Shareholders, GTRL owns, directly or indirectly, or controls approximately 37% of the Common Shares, and is considered a control person of the Company, and Meridian Capital International Fund owns or controls approximately 12% of the Common Shares. In addition, management and the Board of the Company own or control approximately 1% of the Common Shares. Collectively these shareholders own or control approximately 50% of the Common Shares and, if acting together, would be able to significantly influence all matters requiring shareholder approval, including without limitation, the election of directors. However, pursuant to an investor rights agreement among the Company, GTEIHL and GTRL dated December 18, 2017, GTEIHL and GTRL agreed that they would not exercise any voting rights associated with any Common Shares which exceed 30% of the Common Shares outstanding from time to time, notwithstanding the fact that they may own or exercise control over additional Common Shares. Dilution The Company may issue additional Common Shares in the future, which may dilute a Shareholder's holdings in the Company. The Company's articles permit the issuance of an unlimited number of Common Shares and Shareholders will have no pre-emptive rights in connection with such further issuances. Also, additional Common Shares may be issued by the Company on the exercise of Common Share purchase warrants, or on the exercise of options, performance share units and restricted share units under the Company's stock option plan and performance and restricted share unit plan. Third Party Credit Risk The Company may be exposed to third party credit risk through its contractual arrangements with its future joint venture partners, marketers of its petroleum and natural gas production and other parties. In the event such entities fail to meet their contractual obligations to the Company, such failures could have a material adverse effect on the Company and its cash flow from operations. In addition, poor credit conditions in the industry and of joint venture partners may impact a joint venture partner's willingness to participate in the Company's ongoing capital program, potentially delaying the program and the results of such program until the Company finds a suitable alternative partner. Alternatives to and Changing Demand for Petroleum Products Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, and technological advances in fuel economy and energy generation devices could reduce the demand for crude oil and other liquid hydrocarbons. Although fuel consumption continues to grow, the Company cannot predict the impact of changing demand for oil and natural gas products, and any major changes may have a material adverse effect on the Company's business, financial condition, results of operations and cash flows. - 46 - Reputational Risk Associated with Operations Any environmental damage, loss of life, injury or damage to property caused by the Company's operations could damage its reputation in the areas in which the Company operates. Negative sentiment towards the Company could result in a lack of willingness of municipal authorities being willing to grant the necessary licenses or permits for the Company to operate its business and in residents in the areas where the Company is doing business opposing the Company's further operations in the area. If the Company develops a reputation of having an unsafe work site it may impact the Company's ability to attract and retain the necessary skilled employees and consultants to operate its business. Further, the Company's reputation could be affected by actions and activities of other Company’s operating in the oil and gas industry, over which the Company has no control. In addition, environmental damage, loss of life, injury or damage to property caused by the Company's operations could result in negative investor sentiment towards the Company, which may result in limiting the Company's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares. Changing Investor Sentiment A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, concerns of the impact of oil and gas operations on the environment, concerns of environmental damage relating to spills of petroleum products during transportation and concerns of indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Company's Board, management and employees. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in the Company or not investing in the Company at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, the Company, may result in limiting the Company's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares. Expansion into New Activities In the future, the Company may acquire or move into new industry related activities or new geographical areas, may acquire different energy related assets, and as a result may face unexpected risks or alternatively, significantly increase the Company's exposure to one or more existing risk factors, which may in turn result in the Company's future operational and financial conditions being adversely affected. Corruption The Company is subject to the Foreign Corrupt Practices Act (the "FCPA") and the Corruption of Foreign Public Officials Act ("CFPOA"), and its failure to comply with the laws and regulations thereunder could result in material adverse effect on the Company's business, results of operations and financial condition. The FCPA prohibits companies and their intermediaries from making improper payments to foreign officials to secure any improper advantage for the purpose of obtaining or keeping business and/or other benefits. Similarly, the CFPOA prohibits persons form, directly or indirectly, giving, offering to give or agreeing to give a loan, reward, advantage or benefit of any kind to a foreign public official or to any person for the benefit of a foreign public official. Any violation of these laws could result in monetary penalties against the Company or its subsidiaries and could damage its reputation and, therefore, its ability to do business. - 47 - Forward-Looking Information May Prove to be Inaccurate Investors are cautioned not to place undue reliance on forward-looking information. By its nature, forward-looking information involves numerous assumptions, known and unknown risks and uncertainties, of both a general and specific nature, that could cause actual results to differ materially from those suggested by the forward-looking information or contribute to the possibility that predictions, forecasts or projections will prove to be materially inaccurate. Additional information on the risks, assumptions and uncertainties are found in this AIF under the heading "Forward-Looking Statements" above. DIVIDENDS The Company historically had a policy of retaining earnings in order to finance growth and development of the Company's business. However, on May 31, 2019, the Company implemented a dividend policy whereby the Company would pay: (i) a total dividend in respect of the half year period from July 1, 2019 to December 31, 2019 equivalent to an annualized yield of 4% (based on a price of £0.15 per share), followed thereafter by (ii) semi-annual dividends declared at the discretion of the Board, subject to prevailing market conditions and corporate performance. The Company's new dividend policy is intended to optimise Shareholder wealth while balancing such returns to Shareholders with continued reinvestment in the Peruvian Business to support future growth and development. This, in turn, is expected to provide a stronger base of cash flow leading to consistent dividend payment in the future. The amount of dividends to be paid on Common Shares, if any, is subject to the discretion of the Board and may vary depending on a variety of factors including, but not limited to, current and expected future levels of distributable cash flow, capital expenditures, borrowings and debt repayments, changes in working capital requirements, prevailing market conditions and anticipated earnings. The Company intends to undertake regular review of the policy taking into account factors such as current and future commodity prices, foreign exchange rates, current operations and available investment opportunities. The Company does not have a dividend reinvestment plan or stock dividend program. Dividend History The Company did not declare any cash dividends or distributions on Common Shares in years ended 2017 and 2018. On December 12, 2019, the Company declared an interim dividend of CAD$0.0017 (£0.001) cash for each Common Share to be paid to Shareholders on January 20, 2020, representing in aggregate a total dividend payment of approximately CAD$1.14 million (£0.66 million) The declaration and payment of dividends is subject to the discretion of the Board and may vary depending on a variety of factors and conditions existing from time to time. The payment of dividends to Shareholders is not assured or guaranteed and dividends may be reduced or suspended entirely. In addition to the foregoing, the Company's ability to pay dividends now or in the future and the actual amount distributed will depend on numerous factors and conditions existing from time to time, including fluctuations in commodity prices, production levels, capital expenditure requirements, debt service requirements, operating costs, foreign exchange rates and the satisfaction of solvency tests imposed by the ABCA for the declaration and payment of dividends, applicable law and other factors beyond the Company's control. See "Risk Factors – Dividends". - 48 - DESCRIPTION OF SHARE CAPITAL The Company is authorized to issue an unlimited number of Common Shares without nominal or par value. Each Common Share entitles the holder to receive notice of and to attend all meetings of the shareholders of the Company, to vote at such meetings, to receive such dividends as may be declared by the Board of Directors, and to share ratable with other shareholders in the residual property of the Company in the event of liquidation, dissolution or winding-up of the Company. As at the date hereof, there are 673,351,810 Common Shares issued and outstanding. MARKET FOR SECURITIES AND TRADING HISTORY The Common Shares are listed and posted for trading on the facilities of the TSXV under the symbol "TAL" and, since December 24, 2018, on AIM under the symbol "PTAL". The following table sets out the price range for, and the trading volume of, the Common Shares of the Company as reported by the TSXV for 2019: 2019 January February March April May June July August September October November December High (CDN$) Low (CDN$) 0.29 0.26 0.26 0.28 0.28 0.33 0.38 0.31 0.28 0.35 0.44 0.52 0.21 0.23 0.22 0.21 0.24 0.26 0.30 0.21 0.24 0.25 0.32 0.41 Volume 607,500 482,800 549,000 2,662,400 1,037,800 6,199,200 8,989,100 15,049,500 9,951,900 25,703,000 21,829,100 9,848,800 PRIOR SALES The following table sets forth, for each class of securities of the Company that is outstanding but not listed or quoted on a marketplace, the price at which securities of the class have been issued during the financial year ended December 31, 2019 and the number of securities of the class issued at that price and the date on which the securities were issued. Date of Issuance Class of Securities Number of Securities Issued Exercise Price December 13, 2019 Performance Share Units(1) 8,441,659 N/A Note: (1) Granted to certain officers of the Company in accordance with the provisions of the Company's amended performance and restricted share unit plan. The performance share units vest three years from grant date and each performance share unit entitles the holder thereof to acquire between zero and two Common Shares, subject to the achievement of various performance conditions relating to total shareholder return, net asset value and certain production and operational milestones. ESCROWED SECURITIES To the best of the Company's knowledge, the following securities of the Company are currently held in escrow as of December 31, 2019: - 49 - Designation of Class Common Shares Common Shares Performance Warrants Number of Securities held in Escrow Percentage of Class 6,555,679(1) 18,725,000 (2) 12,101,700(3) 1% 2% 45% Notes: (1) (2) (3) In connection with Arrangement, certain Common Shares held by directors, officers and certain principal securityholders of the Company were placed in escrow, pursuant to the policies of TSXV. Such Common Shares are currently subject to escrow pursuant to the release schedule applicable under a Tier 2 Value Security Escrow Agreement (as defined in the policies of the TSXV). In connection with the completion of the Acquisition and the issuance of Common Shares to GTEIHL, such Common Shares are held in escrow, pursuant to the release schedule applicable under a Tier 2 Value Security Escrow Agreement (as defined in the policies of the TSXV). Represents the number of Performance Warrants after giving effect to the Arrangement. The Performance Warrants were placed in escrow, pursuant to the release schedule applicable under a Tier 2 Value Security Escrow Agreement (as defined in the policies of the TSXV). As of the date hereof, the Performance Warrants have fully vested. DIRECTORS AND OFFICERS The following table sets forth the names and municipalities of residence of the directors and executive officers of the Company as at the date hereof, their respective positions and offices with the Company and date first elected as a director and their principal occupation(s) within the past five years. Position Presently Held Director Since Principal Occupation for Previous Five Years Name and Municipality of Residence Manuel Pablo Zúñiga- Pflücker(3) Texas, USA December 18, 2017 Director, President, Chief Executive Officer and Corporate Secretary President, Chief Executive Officer and Director of the Company since December 18, 2017. Prior thereto, President and Chairman of the Managers of PetroTal LLC since January 2016. Mr. Zúñiga- Pflücker founded and led BPZ Resources, Inc. ("BPZ") from 2001 to 2015. Petroleum engineer with more than 30 years' experience. Executive Vice President and Chief Financial Officer of the Company since November 4, 2019. Prior thereto, Executive Vice President, Finance and Chief Financial Officer of Bankers Petroleum Ltd. from February 2008 to 2018. Vice President, Operations of the Company since December 18, 2017. Prior thereto, Vice President of Exploration and Production for BPZ. Douglas C. Urch Alberta, Canada and Texas, USA Estuardo Alvarez- Calderon Texas, USA and Peru Executive Vice President and Chief Financial Officer Vice President, Operations - - - 50 - Name and Municipality of Residence Position Presently Held Director Since Principal Occupation for Previous Five Years Mark McComiskey(1)(2) Connecticut, USA Chairman of the Board July 5, 2016 Gary S. Guidry(3)(4) Alberta, Canada Director December 18, 2017 Ryan Ellson(1)(2) Alberta, Canada Director December 18, 2017 Gavin Wilson(2)(3)(4) Switzerland Director June 11, 2013 Eleanor J. Barker(1) Ontario, Canada Director December 19, 2019 Roger M. Tucker(3)(4) London, England Director December 19, 2019 Partner at AVAIO Capital, a firm that focuses on value-added infrastructure investment and that spun-out of AECOM in 2019. Prior thereto, a partner at Prostar Capital's energy business and its successor firm, Vanwall Capital, LLC. Prior to Prostar, Co-Head of Private equity at First Reserve, a private equity firm focused on the energy industry. President and Chief Executive Officer of Gran Tierra Energy Inc. since May 2015. Prior thereto, Mr. Guidry was President and Chief Executive Officer of Caracal Energy from 2011 to 2014. Chief Financial Officer of GTE since May 2015. Prior thereto, Mr. Ellson was Chief Financial Officer of Onza Energy Inc. Prior thereto, Mr. Ellson was Head of Finance for Glencore E&P (Canada) and, before that, he served as Vice President, Finance at Caracal Energy. Advisor to Meridian Group of Companies, an investment company. Prior thereto, Mr. Wilson was the Founder and Manager of RAB Energy and RAB Octane listed Investment Funds from 2004 until 2011. President of Barker Oil Strategies Inc. and a director of Serinus Energy plc. Prior thereto, a director of Sterling Resources Ltd. from 2010 to 2014. Director of Pale Rider Limited. Prior thereto, Mr. Tucker was a director of Van Damme North Sea Oil and Gas Limited from 2015 to 2017 and, before that, he served as a director of Vesta Petroleum Investments Limited. Notes: (1) (2) (3) (4) Member of the Audit Committee. Member of the Corporate Governance and Compensation Committee. Member of the Reserves Committee. Member of the Health, Safety, Environment and Corporate Social Responsibility Committee. As at the date hereof, the directors and officers of the Company, and their associates and affiliates, as a group, whether beneficial, direct or indirect, own 6,409,059 Common Shares, representing approximately 1% of the currently issued and outstanding Common Shares. The directors listed above will hold office until the next annual meeting of the Company or until their successors are elected or appointed. - 51 - Cease Trade Orders and Bankruptcies Except as set forth below, no director or executive officer of the Company is, or within ten years prior to the date of this AIF has been, a director, a chief executive officer or a chief financial officer of any company (including the Company), that: a) b) was subject to: (i) a cease trade order; (ii) an order similar to a cease trade order; or (iii) an order that denied the relevant company access to any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days (collectively, an "Order"), that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or was subject to an Order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer. Mr. Urch was a director of Underground Energy Corporation ("Underground Canada") when, as a result of Underground Canada's failure to file its year-end and interim financial statements and related management's discussion and analysis, the British Columbia Securities Commission issued a cease trade order on all of the securities of Underground Canada on July 4, 2013 and the TSXV suspended trading of Underground Canada's shares. The cease trade order and trading suspension remain in effect. Except as set forth below, no director, executive officer or, to the best of the Company's knowledge, any shareholder holding a sufficient number of securities of the Company to affect materially control of the Company, is, or within ten years prior to the date of this AIF has been, a director or executive officer of any company (including the Company) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets. Mr. Zúñiga-Pflücker was an officer of BPZ, a Company engaged in exploration, development and production of oil and gas in Peru. BPZ filed a voluntary petition for reorganization relief under Chapter 11 of the United States Bankruptcy Code on March 9, 2015. Mr. Urch was a director of Underground Energy, Inc. ("Underground USA"), a wholly-owned US subsidiary of Underground Canada, when Underground USA voluntarily filed for Chapter 11 creditor protection in US Federal Court on March 4, 2013. The case was filed in the United States Bankruptcy Court for the Central District of California - Northern Division, Santa Barbara. On January 5, 2015, Underground USA successfully emerged from the protection of Chapter 11 of the U.S. Bankruptcy Code and restructured without having to declare bankruptcy, and Mr. Urch resigned as a director. Mr. Wilson was a director of Buccaneer Energy Ltd. ("Buccaneer"), a corporation engaged in exploration, development and production of oil and gas in the United States. Buccaneer filed a voluntary petition for reorganization relief under Chapter 11 of the United States Bankruptcy Code on May 31, 2014. Personal Bankruptcies No director or executive officer of the Company or a shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company, has, within the past ten years prior to the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or was subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of such person. - 52 - Penalties and Sanctions No director or executive officer of the Company of the Company, or a shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company, has been subject to: (i) any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or (ii) any other penalties or sanctions imposed by a court or regulatory body that would be likely to be considered important to a reasonable investor in making an investment decision. Conflicts of Interest Certain of the directors and officers of the Company are also directors, officers and/or promoters of other reporting and non-reporting issuers, which may give rise to conflicts of interest. In accordance with corporate laws, directors who have an interest in a contract or a proposed contract with the Company are required, subject to certain exceptions, to disclose that interest and generally abstain from voting on any resolution to approve the contract. In addition, the directors are required to act honestly and in good faith with a view to the best interests of the Company. Some of the directors of the Company have other employment or other business or time restrictions placed on them and accordingly, these directors of the Company will only be able to devote part of their time to the affairs of the Company. In particular, certain of the directors and officers are involved in managerial and/or director positions with other oil and gas companies whose operations may, from time to time, provide financing to, or make equity investments in, competitors of the Company. Conflicts, if any, will be subject to the procedures and remedies available under the ABCA. The ABCA provides that in the event that a director has an interest in a contract or proposed contract or agreement, the director shall disclose his interest in such contract or agreement and shall refrain from voting on any matter in respect of such contract or agreement unless otherwise provided by the ABCA. As of the date hereof, the Company is not aware of any existing or potential material conflicts of interest between the Company and any director or officer of the Company. LEGAL PROCEEDINGS AND REGULATORY ACTIONS There are no legal proceedings material to the Company to which the Company is a party or of which any of its property is the subject matter, and there are no such proceedings known to the Company to be contemplated. There are no penalties or sanctions imposed against the Company by a court relating to securities legislation or by a securities regulatory authority during the most recently completed financial year, there are no other penalties or sanctions imposed by a court or regulatory body against the Company that would likely be considered important to a reasonable investor in making an investment decisions, and there are no settlement agreements the Company entered into before a court relating to securities legislation or with a securities regulatory authority during the most recently completed financial year. INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS Except as disclosed herein, to the best of the Company’s' knowledge, there are no material interests, direct or indirect, of directors or executive officers of the Company, any shareholder who beneficially owns, or controls or directs, directly or indirectly, more than 10% of the outstanding Common Shares, or any known associate or affiliate of such persons, in any transaction within the three most recently completed financial years of the Company or during the current financial year which has materially affected, or is reasonably expected to materially affect, the Company. Gary S. Guidry and Ryan Ellson, directors of the Company, are also executives of GTE. The Company is 37% owned, directly or indirectly, or controlled by GTE and therefore the interests of the two entities are not divergent. Applicable securities laws provide that directors need not refrain from voting in respect of contracts and transactions between "affiliates" (for greater clarity, the Company and GTE would be considered "affiliates" of each other). - 53 - Gavin Wilson, a director of the Company, is an advisor to Meridian Group of Companies. The Company is 12% owned, directly or indirectly, or controlled by Meridian Group of Companies. TRANSFER AGENT AND REGISTRAR The Company's transfer agent and registrar is Computershare Trust Company of Canada at its principal office in Calgary, Alberta. MATERIAL CONTRACTS Except as disclosed herein and other than contracts entered into in the ordinary course of business, there have been no material contracts entered into by the Company within the most recently completed financial year, or before the most recently completed financial year that are still in effect. PROMOTERS Manuel Pablo Zúñiga-Pflücker may be considered to be a promoter of the Company pursuant to applicable securities laws. As at the date hereof, Mr. Zúñiga-Pflucker beneficially owns, directly or indirectly, 2,816,848 Common Shares representing approximately 0.4% of the issued and outstanding Common Shares. INTERESTS OF EXPERTS There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a statement, report or valuation described or included in a filing, or referred to in a filing, made under NI 51-102 by the Company during, or related to, the year ended December 31, 2019 other than NSAI, the Company's independent reserves evaluators and Deloitte LLP, the Company's auditors. None of the principals of NSAI had any registered or beneficial interests, direct or indirect, in any securities or other property of the Company or of the Company's associates or affiliates either at the time they prepared the statement, report or valuation prepared by it, at any time thereafter or to be received by them. Deloitte LLP, the Company's auditors, are independent within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulation. In addition, none of the aforementioned persons or companies, nor any director, officer or employee of any of the aforementioned persons or companies, is or is expected to be elected, appointed or employed as a director, officer or employee of the Company or any associate or affiliate of the Company. ADDITIONAL INFORMATION Additional information relating to the Company can be found on SEDAR at www.sedar.com. Additional information, including directors' and officers' remuneration and indebtedness, principal holders of the Company's securities and securities authorized for issuance under equity compensation plans is contained in the Company's information circular for the Company's most recent shareholders meeting that involved the election of directors. Additional financial information is contained in the Company's financial statements and the related management's discussion and analysis for the year ended December 31, 2019. Additional copies of this AIF and the materials listed in the preceding paragraph are available on the foregoing basis and upon request by contacting the Company at its offices at Suite 500, 11451 Katy Freeway, Houston, Texas 77079. EXHIBIT 1 FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATORS Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning herein. To the board of directors of PetroTal Corp. (the "Company"): 1. 2. 3. 4. 5. We have evaluated of the Company's reserves data for certain oil properties which are located in the Bretaña field, Block 95 of onshore Peru as at December 31, 2019. The reserves data are estimates of proved, probable and possible reserves and related future net revenue as at December 31, 2019, estimated using forecast prices and costs. The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter). Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable plus possible reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2019, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management: Independent Qualified Reserves Evaluator or Auditor Netherland, Sewell & Associates, Inc. Total Effective Date of Evaluation Report December 31, 2019 Location of Reserves (Country) Peru Net Present Value of Future Net Revenue (Before Income Taxes, 10% Discount Rate) Audited (M$) - Evaluated (M$) 1,097,766.4 Reviewed (M$) - Total (M$) 1,097,766.4 Nil 1,097,766.4 Nil 1,097,766.4 6. 7. 8. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are presented in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate. We have no responsibility to update the report referred to in paragraph 5 for events and circumstances occurring after the effective date of our report. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. Executed as to our report referred to above: Netherland, Sewell & Associates, Inc. Texas Registered Engineering Firm F-2699 Dallas, Texas, USA March 3, 2020 EXHIBIT 2 FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE Terms to which a meaning is ascribed in National Instrument 51-101 have the same meaning herein. Management of PetroTal Corp. (the "Company") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data. Independent qualified reserves evaluators have evaluated and reviewed the Company's reserves data. The report of the independent qualified reserves evaluators is presented in the Annual Information Form of the Company for the year ended December 31, 2019. The Reserves Committee of the Board of Directors of the Company has: (a) (b) (c) reviewed the Company's procedures for providing information to the independent qualified reserves evaluators; met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and reviewed the reserves data with management and the independent qualified reserves evaluators. The Reserves Committee of the Board of Directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Reserves Committee, approved: (a) (b) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information; the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluator on the reserves data; and (c) the content and filing of this report. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. (signed) "Manuel Pablo Zúñiga-Pflücker" Manuel Pablo Zúñiga-Pflücker President, Chief Executive Officer and a Director (signed) "Douglas C. Urch" Douglas C. Urch Executive Vice President and Chief Financial Officer (signed) "Roger Tucker" Roger Tucker Director Dated June 15, 2020 (signed) "Gary S. Guidry" Gary S. Guidry Director 

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