PetroTal
Annual Report 2023

Plain-text annual report

Q4 2023 REPORTING PACKAGE MARCH 21, 2024 TSX: TAL AIM: PTAL OTCQX: PTALF PetroTal Announces Q4 and 2023 Financial and Operating Results Q4 2023 average sales and production of 15,033 bopd and 14,865 bopd, respectively 2023 average year on year production growth of 17% to 14,248 bopd Generated 2023 free funds flow of $91 million Returned over $61 million through dividends and share buybacks in 2023 2023 Return on Capital Employed of 30% Calgary, AB and Houston, TX – March 21, 2024—PetroTal Corp. (“PetroTal” or the “Company”) (TSX: TAL, AIM: PTAL and OTCQX: PTALF) is pleased to report its operating and audited financial results for the three (“Q4”) and twelve months ended December 31, 2023 (“2023”). Selected financial and operational information is outlined below and should be read in conjunction with the Company’s audited consolidated financial statements and management’s discussion and analysis (“MD&A”) for the three and twelve months ended December 31, 2023, which are available on SEDAR+ at www.sedarplus.ca and on the Company’s website at www.PetroTal‐Corp.com. All amounts herein are in United States dollars unless otherwise stated. Selected Q4 and 2023 Highlights • Average Q4 sales and production of 15,033 and 14,865 barrels (“bbls”) of oil per day (“bopd”), respectively, impacted by a severe dry season and consequent low river levels that limited barge transport and tanker unloading capacity at Manaus; • Average 2023 sales and production of 14,421 bbls and 14,248 bopd, respectively, within guidance range for the year and generating a production growth rate of 17% over 2022; • • 2023 return on capital employed of 30% compared to 49% in 2022;(1) Exited 2023 in a strong cash position with $111 million in total cash ($91 million unrestricted), after repaying $80 million of bonds in early 2023 and returning over $61 million in dividends and share buybacks in 2023; • Capital expenditures (“capex”) totaled $32.2 million in Q4 and were focused on drilling well 16H, bringing 2023 total capex spend to just over $108 million, lower than guidance of approximately $120 million; • Successfully drilled three new oil wells and one water disposal well in 2023. During 2023, the three new oil wells produced nearly 1 million bbls of oil and generated approximately $45 million in net operating income representing nearly a full payout of their cost to drill by December 31, 2023; 2• PetroTal successfully executed workover operations on wells 1XD and 2XD in May and June 2023, with both wells producing between 500 and 700 bopd since July 2023 and accumulating over 180,000 bbls of oil in the second half of 2023 thereby recovering their workover cost approximately 2.5 times by the end 2023; • Generated Q4 EBITDA2 and free funds flow2 of $50.8 million ($36.71/bbl) and $8.1 million ($5.87/bbl), respectively, and 2023 EBITDA and free funds flow of $210.8 million ($40.06/bbl) and $90.7 million ($17.23/bbl) respectively and in line with cash flow guidance for 2023; • Delivered Q4 net income of $21.5 million ($0.02/share) and over $110.5 million for 2023 ($0.12/share); and, • Paid total dividends of $0.06/share and repurchased 11.3 million common shares in 2023, representing approximately $61 million of total capital returned to shareholders (approximately 11% of December 31, 2023, market capitalization). (1) Return on capital employed = earnings before interest and tax (“EBIT”) / (Total Assets – Current Liabilities) (2) Non-GAAP (defined below) measure that does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures presented by other entities. See “Selected Financial Measures” section. Manuel Pablo Zuniga-Pflucker, President and Chief Executive Officer, commented: “PetroTal’s operational and financial targets were achieved in 2023, increasing average production 17% over 2022, repaying $80 million in debt and returning over $61 million to shareholders in the form of dividends and share buybacks. The Company managed through a challenging dry season, to achieve market guidance and exit December 2023 with production of approximately 20,000 bopd. 2024 is off to a record start having maintained nearly 19,000 bopd over the first two months in an eighty- dollar oil price environment, enabling us to maintain a robust cash position through the first quarter. With continued advancements on the OCP oil export pilot through Ecuador, the Company will continue to prioritize derisking oil sales so PetroTal can embark on new production growth projects. With its strong, debt free, balance sheet, PetroTal will continue to evaluate accretive growth opportunities. I would like to thank shareholders for their continued support, as well as PetroTal’s board of directors and the rest of the PetroTal team for their continued valuable contributions to our success.” 3Selected Financial Highlights The table below summarizes PetroTal’s comparative financial position. Q4-2023 $/bbl Three Months Ended Q3-2023 $/bbl $ 000 $82.21 $81.05 ($20.28) $60.77 $60.77 $7.00 $7.24 $1.46 $0.60 $0.10 $1.45 $3.61 $42.92 $6.21 $36.71 $29.13 $15.57 14,865 15,033 1,383,061 $84,046 $9,676 $10,010 $2,020 $828 $142 $2,001 $4,991 $59,369 $8,588 $50,781 $40,284 $21,529 912,314 $556,512 $0.02 $32,157 $84.65 $84.31 ($19.25) $65.05 $65.05 $5.49 $8.45 $1.72 $0.80 $0.13 $1.99 $4.64 $46.47 $6.92 $39.55 $50.76 $23.86 Year Ended December 31 $ 000 10,909 11,553 1,062,851 $69,142 $5,835 $8,982 $1,829 $845 $141 $2,114 $4,929 $49,396 $7,355 $42,041 $53,953 $25,359 916,700 $522,519 $0.03 $17,011 2023 $/bbl $81.53 $80.54 ($20.33) $60.21 $60.21 $5.82 $6.16 $1.30 $0.66 $0.10 $0.78 $2.84 $45.39 $5.33 $40.06 $37.83 $20.99 $ 000 14,248 14,421 5,263,485 $316,911 $30,648 $32,446 $6,857 $3,475 $516 $4,115 $14,963 $238,854 $28,049 $210,805 $199,127 $110,505 912,314 $556,512 $0.12 $108,453 2022 $/bbl $98.92 $96.67 ($21.96) $74.71 $74.71 $6.66 $6.86 $1.96 $1.34 $0.23 $0.76 $4.29 $56.90 $4.14 $52.77 $53.28 $39.22 $ 000 12,200 13,168 4,806,431 $359,106 $31,991 $32,954 $9,440 $6,431 $1,083 $3,668 $20,622 $273,539 $19,891 $253,648 $256,070 $188,527 862,209 $431,104 $0.219 $94,203 $5.87 $8,127 $34.76 $36,944 $17.23 $90,674 $33.68 $161,868 1.5% $111,299 $57,298 7.1% $112,827 $86,545 16.3% $111,299 $57,298 37.5% $119,969 $74,224 Average Production (bopd) Average sales (bopd) Total sales (bbls)(1) Average Brent price Contracted sales price, gross Tariffs, fees and differentials Realized sales price, net Oil revenue(1) Royalties(2) Operating expense Direct Transportation: Diluent Barging Diesel Storage Total Transportation Net Operating Income(3,4) G&A EBITDA(3) Adjusted EBITDA(3,5) Net Income Basic Shares Outstanding (000) Market Capitalization(6) Net Income/Share ($/share) Capex Free Funds Flow(3) (7) % of Market Capitalization(6) Total Cash(8) Net Surplus (Debt) (3) (9) 1. Approximately 85% of Q4 2023 sales were through the Brazilian route vs 82% in Q3 2023. 2. Royalties at year to date December 31, 2023 and December 31, 2022 include the impact of the 2.5% community social trust. 3. Non-GAAP (defined below) measure that does not have any standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures presented by other entities. See “Selected Financial Measures” section. 4. Net operating income represents revenues less royalties, operating expenses, and direct transportation. 5. Adjusted EBITDA is net operating income less general and administrative (“G&A”) and plus/minus realized derivative impacts. 6. Market capitalization for Q4, 2023, Q3 2023, and Q4 2022 assume share prices of $0.61 $0.57, and $0.50 respectively. 7. Free funds flow is defined as adjusted EBITDA less capital expenditures. See “Selected Financial Measures” section. 8. Includes restricted cash balances. 9. Net Surplus (Debt) = Total cash + all trade and net VAT receivables + short and long term net derivative balances – total current liabilities – long term debt – non current lease liabilities – net deferred tax – other long term obligations. 4Q4 2023 Financial Variance Summary US$/bbl Variance Summary Oil Sales (bopd) Contracted Brent Price Realized Sales Price Royalties Three Months Ended Q3 2023 Q4 2023 Variance Year Ended December 31 2022 2023 Variance 15,033 11,553 3,480 14,421 13,168 1,253 $81.05 $84.31 ($3.26) $80.54 $96.67 ($16.13) $60.77 $65.05 ($4.28) $60.21 $74.71 ($14.50) Total Opex and Transportation $10.85 $13.09 ($2.24) $7.00 $5.49 $1.51 $5.82 $9.00 $6.66 ($0.84) $11.15 ($2.15) Net Operating Income(1,2) $42.92 $46.47 ($3.55) $45.39 $56.90 ($11.51) G&A EBITDA Net Income Free Funds Flow(1,3) $6.21 $6.92 ($0.71) $5.33 $4.14 $1.19 $36.71 $39.55 ($2.84) $40.05 $52.77 ($12.72) $15.57 $5.87 $23.86 $34.76 ($8.29) ($28.89) $20.99 $17.23 $39.22 $33.68 ($18.23) ($16.45) Q4 2023 Financial Variance Commentary • Weaker contracted Brent price of $81.05/bbl compared to the preceding quarter of $84.31/bbl, • resulting in a 7% lower realized price of $60.77/bbl. Lower operating expenses per bbl resulting from higher sales volumes in Q4 2023 compared to Q3 2023. Q4 2023 operating expenses included additional floating storage costs caused by longer than usual barge travel times during the final months of the dry season. • Capital spending in the quarter was $32 million compared to $17 million in Q3 2023 driven by the drilling commencement of well 16H and continued investment in water handling facilities. This resulting in a decrease in Q4 2023 free funds flow(1,3) dollar figure to approximately $8.1 million compared to $37 million in Q3 2023. Liquidity was flat in Q4 2023 compared to Q3 2023, with total cash decreasing by $1.5 million to $111 million driven by favorable working capital timing. Strong balance sheet position in Q4 2023 with no debt and a net surplus (1,4) of $57 million now inclusive of a $42 million net deferred tax liability. • • 1. See “Selected Financial Measures” 2. Net operating income represents revenues less royalties, operating expenses, and direct transportation. 3. Free funds flow is defined as adjusted EBITDA less capital expenditures. 4. Net Surplus (Debt) = Total cash + all trade and net VAT receivables + short and long term net derivative balances – total current liabilities – long term debt – non current lease liabilities – net deferred tax – other long term obligations. 5Financial and Operating Updates Subsequent to December 31, 2023 Robust oil production. Production continues to trend ahead of 2024 guidance with the Company producing 20,453 bopd in January and 17,411 bopd in February 2024. March production to date has averaged 15,600 bopd with the Company’s most recently drilled well (16H) producing around 2,500 bopd and nearing full investment payout. The field was shut down from March 6, 2024 until March 8, 2024 as a safety precaution after an independently operated barging incident caused a small release of oil into the Puniuaha river approximately 2km away from the field. No injuries were reported and the cleanup has been substantially completed. The field downtime did not materially impact Q1 2024 production and the Company is still expected to meet Q1 2024 production guidance of 18,500 bopd. Well 17H update. The Company has completed drilling well 17H on time, materially on its $14 million budget, and commenced production on March 1, 2024. The well has a total depth of approximately 4,960 meters with a lateral section of 1,245 meters. Production since start up has averaged 3,300 bopd under natural flow conditions allowing the well continuing to clean out drilling fluids and reach maximum initial production. Well 18H drilling commencement. The Company commenced drilling well 18H on March 5, 2024 with an estimated cost of $14 million. The well is expected to take approximately 60 days to drill and complete with initial production estimated to occur by mid May 2024. OCP pilot project. PetroTal is pleased to announce continued advancement on the OCP pilot oil shipment with the signing of three key approvals. In early February 2024, the Company received approval letters from the Ecuadorian Ministry of Environment and Ecuadorian Navy along with the successful signing of a use of port agreement with Petroecuador. The Company is awaiting on a final letter from the Port Subsecretariate to start the 100,000 bbl pilot. Pending success of the first pilot, the Company anticipates an additional pilot in the second half of 2024 with recurring sales expected in Q4 2024. 2024 Budget guidance. On January 22, 2024, the Company released its 2024 guidance, forecasting an average 2024 production and sales target of 17,000 bopd, delivering an estimated 20% growth rate over 2023 average production. If this forecast is acheived, PetroTal will generate approximately $200 million in EBITDA underpinned by a total 2024 capex spend of $134 million and allowing for a stable return of capital program. Should production and/or Brent price outperform the Company’s base case budget assumptions (Brent oil at $77/bbl), liquidity sweep for shareholder return upside is possible. At March 15, 2024, the Company estimates it is trending in line with budget expectations. 2023 year ended reserves. On February 12, 2024, PetroTal announced its updated reserves profile ending December 31, 2023. The Company was able grow its 2P after tax per share reserves value to $1.80/share with a $1.64 billion after tax net present value of reserves, discounted at 10% (“NPV10”) and associated 2P reserves of 100 million bbls. The Company’s 2023 year ended 2P reserve replacement ratio is at 167%, with an associated 2P reserve life index of 19 years. For the full text of this announcement, please refer to PetroTal's press release dated February 12, 2024, filed on SEDAR+ (www.sedarplus.ca) and posted on PetroTal's website (www.petrotalcorp.com). In addition to the summary information disclosed in this press 6release, more detailed information will be included in the annual information form for the year ended December 31, 2023, to be filed on SEDAR+ (www.sedarplus.ca) and posted on PetroTal's website (www.petrotalcorp.com) on March 28, 2024. Corporate presentation update. The Company has updated its Corporate Presentation, which is available for download or viewing at www.petrotal-corp.com. Q4 and 2023 full year webcast link for March 21, 2024 PetroTal will host a webcast for its Q4 2023 and 2023 full year results on March 21, 2024 at 9am CT (Houston). Please see the link below to register. https://stream.brrmedia.co.uk/broadcast/65d6373035af67d51a41b45b ABOUT PETROTAL PetroTal is a publicly traded, tri‐quoted (TSX: TAL, AIM: PTAL and OTCQX: PTALF) oil and gas development and production Company domiciled in Calgary, Alberta, focused on the development of oil assets in Peru. PetroTal's flagship asset is its 100% working interest in Bretana oil field in Peru's Block 95 where oil production was initiated in June 2018. In early 2022, PetroTal became the largest crude oil producer in Peru. The Company's management team has significant experience in developing and exploring for oil in Peru and is led by a Board of Directors that is focused on safely and cost effectively developing the Bretana oil field. It is actively building new initiatives to champion community sensitive energy production, benefiting all stakeholders. For further information, please see the Company's website at www.petrotal-corp.com, the Company's filed documents at www.sedarplus.ca, or below: Douglas Urch Executive Vice President and Chief Financial Officer Durch@PetroTal-Corp.com T: (713) 609-9101 Manolo Zuniga President and Chief Executive Officer Mzuniga@PetroTal-Corp.com T: (713) 609-9101 PetroTal Investor Relations InvestorRelations@PetroTal-Corp.com Celicourt Communications Mark Antelme / Jimmy Lea petrotal@celicourt.uk 7T : 44 (0) 20 7770 6424 Strand Hanson Limited (Nominated & Financial Adviser) Ritchie Balmer / James Spinney / Robert Collins T: 44 (0) 207 409 3494 Stifel Nicolaus Europe Limited (Joint Broker) Callum Stewart / Simon Mensley / Ashton Clanfield T: +44 (0) 20 7710 7600 Peel Hunt LLP (Joint Broker) Richard Crichton / David McKeown / Georgia Langoulant T: +44 (0) 20 7418 8900 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, oil production levels and guidance. 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", "believe", "expect", "plan", "estimate", "potential", "will", "should", "continue", "may", "objective" and similar expressions. Without limitation, this press release contains forward-looking statements pertaining to: PetroTal's drilling, completions, workovers and other activities; the Company's plans and expectations with respect to the OCP pilot oil shipment and its continued advancement; anticipated future production and revenue; drilling plans including the timing of drilling, commissioning, and startup; PetroTal’s 2024 guidance, including in respect of its production and sales target of 17,000 bopd and estimate that it will deliver a 20% growth rate over 2023 production and anticipated benefits thereof (i.e., that PetroTal will generate approximately $200 million in EBITDA as a result, underpinned by a total 2024 capex spend of $134 million and allowing for a stable return of capital program and shareholder return upside); expectations with respect to well 17H production; 2024 budget guidance; plans with respect to well 18H including in respect of anticipated costs, completion and timing thereof including the Company’s plans to begin production at well 18H in May of 2024; the Company’s expectation to meet Q1 2024 production guidance of 18,500 bopd; expectation that the Company will continue to prioritize derisking oil sales so it can embark on new production growth projects; average 2024 production; intentions with respect to return of capital and the 19 year 2P reserve life index. In addition, statements relating to expected production, reserves, recovery, replacement, 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. 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, the ability to obtain and maintain necessary permits and licenses, the ability of government groups to effectively achieve objectives in respect of reducing social conflict and collaborating towards continued investment in the energy sector, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices and the actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labour, royalty regimes and exchange rates, the impact of inflation on costs, 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, future river water levels, the Company's growth strategy, general economic conditions and availability of required equipment and 8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; changes in the financial landscape both domestically and abroad, including volatility in the stock market and financial system; and wars (including Russia's war in Ukraine and the Israeli- Hamas conflict). Please refer to the risk factors identified in the Company's most recent annual information form and MD&A which are available on SEDAR+ at www.sedarplus.ca. 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. OIL REFERENCES: All references to "oil" or "crude oil" production, revenue or sales in this press release mean "heavy crude oil" as defined in NI 51-101. All references to Brent indicate Intercontinental Exchange ("ICE") Brent. Recovery factor percentages include historical production. RESERVES DISCLOSURE: All reserves values, future net revenue and ancillary information contained in this press release are derived from from an independent reserves report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”) effective December 31, 2023 unless otherwise noted. Estimates of reserves and future net revenue for individual properties may not reflect the same level of confidence as estimates of reserves and future net revenue for all properties, due to the effect of aggregation. There is no assurance that the forecast price and cost assumptions applied by NSAI in evaluating PetroTal's reserves will be attained and variances could be material. It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. The recovery and reserve estimates of PetroTal's oil reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual oil reserves may be greater than or less than the estimates provided herein. There are numerous uncertainties inherent in estimating quantities of crude oil, reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth herein are estimates only. 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. Proved 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. Possible reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., 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 category (proved, probable, possible) to which they are assigned. Certain terms used in this press release but not defined are defined in NI 51-101, CSA Staff Notice 51-324 - Revised Glossary to NI 51-101, Revised Glossary to NI 51-101, Standards of Disclosure for Oil and Gas Activities ("CSA Staff Notice 51-324") and/or the 9COGEH and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101, CSA Staff Notice 51-324 and the COGEH, as the case may be. SHORT TERM RESULTS: References in this press release to peak rates, production rates since inception, current production rates, initial seven day production rates and other short-term production rates are useful in confirming the presence of hydrocarbons, however such rates are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long-term performance or of ultimate recovery. While encouraging, readers are cautioned not to place reliance on such rates in calculating the aggregate production of PetroTal. The Company cautions that such results should be considered to be preliminary. SPECIFIED FINANCIAL MEASURES: This press release includes various specified financial measures, including non-GAAP financial measures, non-GAAP financial ratios and capital management measures as further described herein. These measures do not have a standardized meaning prescribed by generally accepted accounting principles (“GAAP”) and, therefore, may not be comparable with the calculation of similar measures 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. “Adjusted EBITDA” (non-GAAP financial measure) is calculated as consolidated net income (loss) before interest and financing expenses, income taxes, depletion, depreciation and amortization and adjusted for G&A impacts and certain non-cash, extraordinary and non-recurring items primarily relating to unrealized gains and losses on financial instruments and impairment losses, including derivative true-up settlements. PetroTal utilizes adjusted EBITDA as a measure of operational performance and cash flow generating capability. Adjusted EBITDA impacts the level and extent of funding for capital projects investments. Reference to EBITDA is calculated as net operating income less G&A. “Net Operating Income” (non-GAAP financial measure) is calculated as revenues less royalties, operating expenses, and direct transportation. The Company considers Net Operating Income measure as they demonstrate Company’s profitability relative to current commodity prices. "Net surplus (debt)" (non-GAAP financial measure) is calculated by adding together total cash, trade and VAT receivables, and short and long-term net derivative balances less total current liabilities, long-term debt, non-current lease liabilities, deferred tax, and other long-term obligations. Net surplus (debt) is used by management to provide a more complete understanding of the Company's capital structure and provides a key measure to assess the Company's liquidity. “Free funds flow” (non-GAAP financial measure) is calculated as net operating income less G&A less exploration and development capital expenditures less realized derivative gains/losses and is calculated prior to all debt service, taxes, lease payments, hedge costs, factoring, and lease payments. Management uses free funds flow to determine the amount of funds available to the Company for future capital allocation decisions. Please refer to the MD&A for additional information relating to specified financial measures. “Free cash flow” (non-GAAP financial measure) is calculated as EBITDA less G&A less Capex prior to the realization of any derivative impacts. OIL AND GAS MEASURES: This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "reserves life index", “reserves replacement” and “per share reserves value”. These terms 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. "Reserve life index" is calculated as total Company interest reserves divided by annual production. “Reserves replacement” is calculated as reserves in the referenced category divided by estimated referenced production. “Reserves per share” or “per share reserves value” is calculated as reserves in the referenced category divided by the number of shares of PetroTal’s common stock issued and outstanding. 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. Readers are cautioned that the information 10provided by these metrics, or that can be derived from the metrics presented in this press release, should not be relied upon for investment or other purposes. FOFI DISCLOSURE: This press release contains future-oriented financial information and financial outlook information (collectively, "FOFI") about PetroTal’s prospective results of operations and production results, free funds flow, cost estimates, NPV10, tax rates, budget, EBITDA, 2024 capex, 2024 average production and production and sales targets, balance sheet strength, shareholder returns 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 and its management believe that FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments, and represent, to the best of management’s knowledge and opinion, the Company’s expected course of action. However, because this information is highly subjective, it should not be relied on as necessarily indicative of future results. PetroTal disclaims any intention or obligation to update or revise any FOFI contained in this press release, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law. Readers are cautioned that the FOFI contained in this press release should not be used for purposes other than for which it is disclosed herein. All FOFI contained in this press release complies with the requirements of Canadian securities legislation, including NI 51-101. Changes in forecast commodity prices, differences in the timing of capital expenditures, and variances in average production estimates can have a significant impact on the key performance measures included in PetroTal's guidance. The Company's actual results may differ materially from these estimates. 11MANAGEMENT'S DISCUSSION AND ANALYSIS For the years ended December 31, 2023 and 2022 TSX:TAL AIM: PTAL OTCQX: PTALF TABLE OF CONTENTS 14 1. Corporate overview ……………………………………………………………………………………………………….………. 15 2. Overview and selected information...……………………………………………………………...…………………….. 15 3. 2023 Highlights…………………………………………………………………………………………………………………....... 16 4. Outlook and growth strategy ..…………………...………………..……………………………………………………….. 18 5. Selected financial information………………………………………………………………………………………………... 29 6. 2023 Reserve Report ..…….........................…………………………………..……..………............................ 31 7. Significant judgements and estimates ..…….........................…………………………………..……..……….. 33 8. Disclosure pronouncements not yet adopted.......................…………………………………..…….……….. 9. Related party transactions ..…….........................…………………………………..……..………................... 33 33 10. Taxes ..…….........................…………………………………..……..……….................................................... 35 11. Contractual obligations and commitments……………………………………………………………………………… 35 12. Forward-looking statements and business risks ……………………………………………………………………… 13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, 2023 and 2022, is dated March 19, 2024, and should be read in conjunction with the Company’s unaudited Condensed Interim Consolidated Financial Statements (“Financial Statements”) for the years ended December 31, 2023 and 2022. The Financial Statements were prepared by management in accordance with International Accounting Standards (“IAS”) 34-Interim Financial Reporting as 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 Corp. is a publicly-traded (TSX: TAL, AIM: PTAL, and OTCQX: PTALF) international oil and gas company incorporated and domiciled in Canada, with management based in Houston, Texas and Lima, Peru. Through its two subsidiaries in Peru, the Company is currently engaged in the ongoing development of hydrocarbons in Block 95 with a focus on the development of, and production from the Bretana oil field. In addition to further leads in Block 95, the Company has exploration prospects and leads in Block 107. The Bretana oil field is located in the Maranon Basin of northern Peru. To date, this basin has produced more than one billion barrels of oil. Approximately 70% of the oil in the Maranon Basin has been produced from the Vivian formation and approximately 30% from the Chonta formation. The Vivian formation is known as a quality oil reservoir with high permeabilities and strong aquifer support. Generally, this type of reservoir achieves the highest oil recoveries. The Chonta formation is immediately below the Vivian and typically produces medium to light oil; the Company is focused on the Vivian formation. The Company has a 100% working interest in the Bretana oil field. 142. OVERVIEW AND SELECTED INFORMATION The following table summarizes key financial and operating highlights associated with the Company’s performance for the years ended December 31, 2023 and December 31, 2022, along with 2023 quarters. RESULTS AT A GLANCE Financial Oil revenue Royalties Net operating income (1) Commodity price derivatives (gain) loss Net income Basic earnings per share ($/share) Capital expenditures Operating Average production (bopd) Average sales (bopd) Average Brent price ($/bbl) Contracted sales price ($/bbl) Netback ($/bbl) (1) Funds flow provided by operations (2) Balance Sheet Cash and restricted cash Working capital Total assets Current liabilities Equity Year Ended Three Months Ended December 31, 2023 December 31, 2022 December 31, 2023 September 30, 2023 June 30, 2023 March 31, 2023 $316,911 ($30,648) $238,854 $12,479 $110,505 $0.12 $108,453 14,248 14,421 81.53 80.54 45.39 $359,106 ($31,991) $273,539 ($8,231) $188,527 $0.22 $94,203 12,200 13,168 98.92 96.67 56.90 $84,046 ($9,676) $59,369 $11,662 $21,529 $0.02 $32,157 14,865 15,033 82.21 81.05 42.92 $69,142 ($5,835) $49,396 ($12,701) $25,359 $0.03 $17,010 10,909 11,553 84.65 84.31 46.47 $95,229 ($8,899) $76,573 $6,272 $46,635 $0.05 $26,367 19,031 18,483 77.29 77.88 45.53 $68,494 ($6,238) $53,515 $7,247 $16,979 $0.02 $32,919 12,193 12,618 82.51 80.32 47.12 $239,457 $172,020 $53,767 $86,124 $58,154 $41,412 $111,299 $121,649 $658,286 $81,533 $463,942 $119,969 $139,771 $602,880 $123,362 $399,331 $111,299 $121,649 $658,286 $81,533 $463,942 $112,827 $162,958 $618,200 $61,584 $462,557 $92,552 $155,990 $620,045 $81,959 $462,113 $71,635 $125,765 $565,891 $82,793 $421,229 (1) (2) Net operating income ("NOI") and Netback represent revenues less royalties, operating expenses and direct transportation. Funds flow provided by operations does not have standardized meaning prescribed by GAAP and therefore may not be comparable with the calculation of similar measures for other entities. See “Non-GAAP Measures” section. 3. 2023 HIGHLIGHTS The Company reached several key operational and financial achievements as described below: Q4 2023 Operational Highlights - Oil production of 1.4 million barrels ("mmbbls"), an average of 14,865 barrels of oil per day ("bopd"), an increase of 36% from 10,909 bopd in Q3 2023, and a 43% increase from 10,374 bopd in Q4 2022. At December 31, 2023, the Company has 15 producing wells, 1 well awaiting completion and 3 water disposal wells; Oil sales allocations were 85% as export through Brazil and 15% to the Iquitos refinery; - - With installation of the new L2 West Platform completed, the Company successfully drilled its first horizontal well 16H ("16H") on the new platform in December 2023. Well 16H was subsequently completed and started production in January 2024; and, - Meetings continue between the communities, Perupetro, and the Puinahua District Municipality outlining executive committee roles and controls towards finalizing the 2.5% community social trust fund's bylaws. 15  2023 Operational Highlights - - - - Oil production of 5.2 mmbbls in 2023, representing an average of 14,248 bopd, an increase of 17% from 12,200 bopd (4.5 mmbbls realized) in 2022; Oil sales allocations were 87% as export through Brazil and 13% sales to Iquitos refinery; Annual independent reserve assessment, as prepared by Netherland Sewell and Associates, Inc. ("NSAI") shows increases in all reserve categories: • • • Proved ("1P") reserves increased by 5% to 48.0 mmbbls. Net present value discounted at 10% ("NPV-10") after tax is $888 million ($18.40/bbl, CAD $24.50/bbl); Proved plus Probable ("2P") reserves increased by 4% to 100.2 mmbbls with NPV-10 after tax of $1.6 billion ($16.32/ bbl, CAD$21.73/bbl); Proved plus Probable and Possible ("3P") reserves increased by 19% to 199.6 mmbbls with NPV-10 after tax of $2.5 billion ($12.54/bbl, CAD$16.70/bbl); and, Original oil in place ("OOIP") remained consistent from 2022 levels. Currently at 326, 442 and 595 mmbbls respectively, for the 1P, 2P and 3P cases. 2023 Financial Highlights - - - - - - - The Company generated revenue of $316.9 million (5.2 mmbbls sold, 14,421 bopd, $60.21/bbl) compared to $359.1 million (4.8 mmbbls sold, 13,168 bopd, $74.71/bbl) in 2022; Royalties paid to the Peruvian government were $23.4 million ($4.44/bbl, 7.4% of revenues) compared to $25.7 million ($5.35/bbl, 7.1% of revenues) in 2022. Contributions for the 2.5% community social trust fund, represented $7.3 million in 2023, as compared to $6.3 million in 2022; Generated funds flow from operations of $239.5 million compared to $172.0 million in 2022; Net operating income was $238.9 million ($45.39/bbl) compared to $273.5 million ($56.90/bbl) in 2022; PetroTal repaid all $80 million of bond principal in Q1 2023, a year earlier than required; The Company had cash and restricted cash of $111.3 million at year-end, compared to $119.9 million at year-end 2022; and, PetroTal commenced its shareholder capital return policy in 2023 and paid dividends totaling $56 million, and repurchased 11,326,806 shares ($6.5 million). December 31, 2023 Subsequent Events - Well 16H produced at above expected level rates with a 26 day production average of approximately 4,850 bopd as at - - February 11, 2024 with an estimated investment payback in Q2 2024; PetroTal commenced drilling a new horizontal well (17H), with production by the end of Q1 2024; and, On February 14, 2024, the Company declared a cash dividend of $0.02 per common share with a record date of February 29, 2024. The dividend was paid March 15, 2024. 4. OUTLOOK AND GROWTH STRATEGY Strategy Outlook The capital program prioritizes management's strategy to maintain a strong balance sheet during the period of oil price volatility, optimizing drilling activity to fit within cash flow. The Company's activity will focus on managing existing production and drilling new wells during 2024. 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 includes optimization of existing facilities, wells and some improvements aimed at lowering operating costs; Drilling new wells focused on continuing development in the core area of Bretana oilfield; and, Continued investment in environmental remediation and social initiatives as part of a sustained long-term effort to improve the physical environment and to provide training programs and other community initiatives for the residents near the Company’s operations. The 2024 capital budget is based on an estimated average annual Brent oil price forecast of $77/bbl. 16 Growth Strategy PetroTal’s strategy is focused on petroleum assets that have long-life reserves with production growth potential. Employing its knowledge base and technical expertise, the Company is working to optimize its existing assets primarily 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 ("NAV"). PetroTal’s strategic priorities are to: Increase reserves and production; - - Maintain a strong balance sheet by controlling and managing capital expenditures; - - - - 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; and, Explore undeveloped acreage to identify and create development opportunities. Throughout the period, PetroTal focused on achieving its priorities and implementing its capital programs in Peru. The Company will fund its capital development program using funds generated from operations and existing cash. Strategic allocation of the work program and budget is designated to provide additional recoverable reserves at the Peruvian oilfields and achieve production growth. Environmental and Social Governance (“ESG”) Strategy PetroTal believes in creating long-term value for our shareholders, employees, suppliers, communities, customers, and the government, as well as ensuring economic value, safety for people and the environment, and creating a better future for all. Therefore, our sustainability strategy towards year 2030 rests on our shoulders. PetroTal's ESG vision is: “To create value and generate more opportunities for the benefit of all”. The steps to measure our success are: - - - Develop measurable goals for 2025 and 2030 that will be built and reviewed with the participation of each department throughout the Company; Initiatives will be continually updated to achieve our goals; The Sustainable Development Goals (“SDGs”) will be included, to which PetroTal contributes through its Sustainability Plan to 2030; - We are committed to reducing our carbon and water footprints, which means reducing emissions, waste, preventing oil spills as much as possible, efficiently managing our use of water, focusing on the protection and conservation of biodiversity, managing our impact positively, innovating where possible and doing all of the above safely; - We are implementing an effective due diligence process to prevent possible human rights violations; - To materialize the aforementioned initiatives, we develop and promote talent in PetroTal, the community, and within our suppliers; and, - We maintain a constant and respectful dialogue with our stakeholders to inform and prevent conflicts. Exploratory Block 107 – Osheki-Kametza PetroTal has a 100% working interest in this 623,280 acre block. There are several prospective features, the largest being the Osheki- Kametza prospect. Osheki-Kametza has the potential to contain in place volumes of 970.7 million barrels of oil equivalent ("mmboe") according to the Company's independent reservoir engineers, NSAI. Resource estimates are based on maps generated from modern seismic acquired in 2007 and 2014 and partially de-risked with a new 3D geologic model supporting Cretaceous age reservoirs with high quality Permian source rocks. Additional reprocessing of existing seismic data and acquisition of new seismic data may be required to enhance the structural configuration. The Company continues to work on the necessary permits and complete further technical work for the Osheki-Kametza prospect which will allow PetroTal to consider progressing towards a drilling recommendation. On January 6, 2023, Perupetro extended the Company's Block 107 exploratory license to April 2026. 175. SELECTED FINANCIAL INFORMATION 5.1 FINANCIAL SUMMARY ($ thousands) $/bbl $/bbl $/bbl $/bbl $/bbl 2023 Q4-2023 Q3-2023 Q2-2023 Q1-2023 PRODUCTION: Average Production (bopd) SALES: Average sales (bopd) Total sales (bbls) Average Brent price $81.53 Weighted contracted sales price, gross $80.54 LESS: Tariffs, fees and differentials ($20.33) Realized sales price, net $60.21 14,248 14,421 5,263,485 14,865 15,033 10,909 11,553 19,031 18,483 12,193 12,618 1,383,061 1,062,851 1,681,962 1,135,611 $82.21 $81.05 ($20.28) $60.77 $84.65 $84.31 ($19.25) $65.05 $77.29 $77.88 ($21.26) $56.61 $82.51 $80.32 ($20.01) $60.31 REVENUES: LESS: Oil revenue (1) Royalties (2) Operating expense Direct Transportation: Diluent Barging Diesel Storage Total Transportation $60.21 $316,911 $60.77 $84,046 $65.05 $69,142 $56.61 $95,229 $60.31 $68,494 $5.82 $6.16 $1.30 $0.66 $0.10 $0.78 $2.84 $30,648 $7.00 $9,676 $5.49 $5,835 $5.29 $8,899 $5.49 $32,446 $7.24 $10,010 $8.45 $8,982 $4.22 $7,100 $5.60 $6,238 $6,354 $6,857 $1.46 $2,020 $1.72 $1,829 $0.98 $1,641 $1.20 $1,368 $3,475 $0.60 $828 $0.80 $845 $0.53 $896 $0.80 $516 $0.10 $142 $0.13 $141 $0.07 $120 $0.10 $4,115 $1.45 $2,001 $1.99 $2,114 $— $— $— $906 $113 $— $14,963 $3.61 $4,991 $4.64 $4,929 $1.58 $2,657 $2.10 $2,387 NET OPERATING INCOME $45.39 $238,854 $42.92 $59,369 $46.47 $49,396 $45.53 $76,573 $47.12 $53,515 Netback as % of Revenue 75.4% 70.6% 71.4% 80.4% General and administrative expense Commodity price derivative loss (gain) Financial expense Income tax expense Depletion, depreciation and amortization $5.33 $2.37 $2.91 $6.27 $7.56 $28,049 $6.21 $8,588 $6.92 $7,355 $3.89 $6,548 $4.90 $12,479 $8.43 $11,662 ($11.95) ($12,701) $3.73 $6,272 $6.38 $15,341 $2.28 $3,150 $1.12 $1,187 $1.22 $2,046 $7.89 $33,002 $2.95 $4,076 $18.30 $19,445 $1.64 $2,751 $5.93 $39,801 $8.33 $11,527 $7.49 $7,962 $7.23 $12,154 $7.18 Foreign exchange loss (gain) ($0.06) ($323) ($0.84) ($1,163) $0.74 $789 $0.10 $167 ($0.10) NET INCOME FUNDS FLOW PROVIDED BY OPERATIONS $110,505 $239,457 $21,529 $53,767 $25,359 $86,124 $46,635 $58,154 78.1% $5,559 $7,247 $8,958 $6,730 $8,158 ($116) $16,979 $41,412 (1) Tariff and marketing fees are expenses usually recorded by reducing revenues in the financial statements. (2) Royalties include 2.5% community social trust initiative. 18 ($ thousands) $/bbl $/bbl $/bbl $/bbl $/bbl 2022 Q4-2022 Q3-2022 Q2-2022 Q1-2022 PRODUCTION: Average Production (bopd) SALES: Average sales (bopd) Total sales (bbls) Average Brent price $98.92 Weighted contracted sales price, gross $96.67 LESS: Tariffs, fees and differentials ($21.96) Realized sales price, net $74.71 12,200 13,168 4,806,431 10,374 10,420 958,624 12,229 12,186 14,467 14,616 11,746 15,518 1,121,132 1,330,026 1,396,648 $88.61 $88.22 ($21.71) $66.51 $97.89 $97.21 ($22.14) $75.07 $111.80 $111.39 ($22.35) $89.04 $97.49 $88.02 ($21.61) $66.41 REVENUES: LESS: Oil revenue (1) Royalties Operating expense Direct Transportation: Diluent Barging Diesel Storage Total Transportation $74.71 $359,106 $66.51 $63,755 $75.07 $84,164 $89.04 $118,435 $66.41 $92,752 $6.66 $6.86 $1.96 $1.34 $0.23 $0.76 $4.29 $31,991 $6.08 $5,824 $10.43 $11,689 $6.09 $8,104 $4.56 $6,373 $32,954 $7.42 $7,115 $6.62 $7,423 $6.28 $8,355 $7.20 $10,061 $9,440 $1.33 $1,274 $1.23 $1,374 $1.45 $1,931 $3.48 $6,431 $0.86 $824 $1.05 $1,172 $0.71 $943 $2.50 $1,083 $0.15 $144 $0.10 $110 $0.05 $71 $0.54 $4,862 $3,493 $758 $3,668 $0.16 $152 $0.06 $63 $0.33 $442 $2.16 $3,011 $20,622 $2.50 $2,394 $2.44 $2,719 $2.54 $3,387 $8.68 $12,124 NET OPERATING INCOME $56.90 $273,539 $50.51 $48,422 $55.60 $62,333 $74.13 $98,589 $45.97 $64,194 Netback as % of Revenue 76.2% 76.0% 74.1% 83.2% General and administrative expense $4.14 $19,891 $5.57 $5,339 $4.18 $4,689 $3.87 $5,143 $3.38 69.2% $4,718 Commodity price derivative loss (gain) ($1.71) ($8,231) ($13.95) ($13,373) $29.15 $32,686 ($4.91) ($6,533) ($15.05) ($21,014) Financial expense Income tax expense (recovery) Depletion, depreciation and amortization Other expenses Foreign exchange loss NET INCOME FUNDS FLOW PROVIDED BY OPERATIONS $4.20 $3.62 $6.98 $0.20 $0.26 $20,169 $2.49 $2,387 $5.17 $5,792 $4.60 $6,113 $4.21 $17,390 $9.36 $8,975 $7.49 $8,392 $0.04 $53 ($0.02) $33,568 $7.42 $7,116 $7.06 $7,920 $6.90 $9,179 $6.70 $978 $1.02 $978 $— $— $— $— $— $1,247 ($0.18) ($176) $0.23 $260 $0.29 $385 $0.56 $188,527 $172,022 $37,176 $59,383 $2,594 $46,207 $84,249 $60,688 $5,878 ($29) $9,353 $— $777 $64,511 $5,743 Tariff and marketing fees are expenses usually recorded by reducing revenues in the financial statements. Royalties in Q3 2022 include the value since January 1, 2022 inception for the 2.5% community social trust initiative. Subsequent social trust contributions are (1) (2) recorded in the corresponding quarter incurred. 19 EARNINGS STATEMENT INFORMATION Revenue Oil sales in 2023 increased by 10% to 5,263,485 barrels 14,421 bopd), compared to 4,806,431 barrels (13,168 bopd) in 2022. Sales were 1,383,061 barrels (15,033 bopd) in Q4 2023 compared to 958,624 barrels (10,420 bopd) in Q4 2022. The Company sells oil at three sales points: the local Iquitos refinery, exports through Brazil, and the Northern Peruvian Pipeline ("ONP"). In 2023, 87% of oil sales were through the Brazil export route and 13% to the Iquitos refinery. Sales to the ONP have been curtailed since February 2022, pursuant to Petroperu's ability to fulfill terms of the sales agreement. Sales to the Iquitos refinery are priced at the prevailing Brent oil price less a quality differential discount and barge transportation charges. Oil sales exported through Brazil are on a freight on board ("FOB") Bretana basis, at the forecasted Brent oil price in three months, less a fixed amount to cover all transportation and sales costs, including the quality differential. Sales to Petroperu at the Saramuro pump station for transportation through the ONP and onward to the Bayovar port, are priced based on the forecasted Brent oil price in eight months, less a quality differential, and is net of all pipeline and marketing fees. When the oil is ultimately sold by Petroperu at Bayovar, PetroTal is subject to a valuation adjustment based on the actual price achieved by Petroperu, whether higher or lower than the original forecasted price. Royalties decreased to $30.6 million ($5.82/bbl) in 2023 from $32.0 million ($6.66/bbl) in 2022 and in Q4 2023 increased to $9.7 million ($7.00/bbl) from $5.8 million ($6.08/bbl) in Q4 2022. Beginning in Q3 2022, the 2.5% community social trust initiative is included in royalties. Royalties for the Bretana oilfield are calculated on production, less transportation costs, starting at 5% based on production of 5,000 bopd or less and 20% when production reaches 100,000 bopd or more, increasing on a straight-line basis. Royalty determination in Peru is negotiated on an individual block basis, based either on production scales or on economic results. Operating expenses in 2023 were $32.4 million ($6.16/bbl), as compared to $33.0 million ($6.86/bbl) in 2022 and in Q4 2023 were $10.0 million ($7.24/bbl) versus $7.1 million ($7.42/bbl) in Q4 2022 . Higher oil production in Q4 2023 resulted in lower operating costs per barrel due to fixed operating cost allocations. 20 Direct Transportation expenses in 2023 totaled $15.0 million ($2.84/bbl), representing barging and diluent blending costs, as compared to $20.6 million ($4.29/bbl) in 2022 and in Q4 2023 totaled $5.0 million ($3.61/bbl) versus $2.4 million ($2.50/bbl) in Q4 2022. Direct transportation costs include $4.1 million ($0.78/bbl) in 2023 and $3.7 million ($0.76/bbl) in 2022 for storage and dry season freight due to low river levels. Diluent costs fluctuate as a result of blending requirements for oil delivered to the Iquitos refinery. Diluent Barging Diesel Dry season freight and storage Total Direct Transportation Year Ended December 31 2023 December 31 2022 6,857 3,475 516 4,115 14,963 9,440 6,431 1,083 3,668 20,622 General and administrative ("G&A") expenses in 2023 were $28.0 million ($5.33/bbl), as compared to $19.9 million ($4.14/bbl) in 2022 and $8.6 million ($6.21/bbl) in Q4 2023 versus $5.3 million ($5.57/bbl) in Q4 2022. As production increases, per barrel G&A costs will decrease. Salaries and benefits Legal, audit and consulting fees Community support Office rent and administrative Share-based compensation plans Costs directly attributable to PP&E and operating expenses Total Year Ended December 31 2023 December 31 2022 14,065 9,459 3,100 4,350 4,364 (7,289) 28,049 10,994 4,830 2,372 2,870 4,089 (5,264) 19,891 Included in G&A are expenditures related to various community project initiatives for Bretana and neighboring communities. PetroTal recognizes the importance of community alignment and support over the areas in which it operates. The Company allocated $7.3 million of G&A in 2023 to capital projects and operating expenses, compared to $5.3 million in 2022. Depletion, Depreciation and Amortization (“DD&A”) for 2023 was $39.8 million ($7.56/bbl) as compared to $33.6 million ($6.98/ bbl) in 2022 and in Q4 2023 totaled $11.5 million ($8.33/bbl) versus $7.1 million ($7.42/bbl) in Q4 2022. DD&A is determined using the annual reserve report information prepared by NSAI at December 31, 2023. DD&A is calculated based on capital invested, future capital, abandonment provision, production and 2P reserves. Commodity price derivative loss of $12.5 million in 2023 is the net fair value change of outstanding embedded derivatives, compared to $8.2 million derivative gain in 2022. The oil sales agreement with Petroperu for sales into the ONP are subject to oil price variations when sold by Petroperu upon arrival at the Bayovar port. Foreign exchange gain in 2023 was $323 thousand compared to a $1.2 million loss in 2022, and a $1.2 million gain in Q4 2023 compared to $176 thousand gain in Q4 2022 , due to fluctuations in relative currency positions and transactions. Income tax expense of $33.0 million was recorded in 2023 compared to $17.4 million in 2022. Financial expense was $15.3 million in 2023, mainly related to bond interest, and financial expense and accretion of decommissioning obligation expense, as compared to $20.2 million in 2022. 21BALANCE SHEET INFORMATION 5.2 BALANCE SHEET - SUMMARIZED December 31, 2023 September 30, 2023 June 30, 2023 March 31, 2023 December 31, 2022 ($ thousands) Current Assets Cash Restricted cash VAT receivable Trade and other receivables Inventory Prepaid expenses Derivative assets Total Current Assets Restricted cash Trade Receivable long-term VAT receivables and taxes PPE and E&E, net Derivative assets Total Non-current Assets Total Assets Current Liabilities Trade and other payables Lease liabilities Short-term debt Total Current Liabilities Leases and other long-term Deferred income tax liabilities Long-term debt Long-term derivative liabilities Decommissioning liabilities Total Non-current Liabilities Total Equity Total Liabilities and Equity $90,568 $14,731 $9,709 $58,602 $12,792 $7,462 $9,318 $203,182 $6,000 $20,370 $15,271 $408,537 $4,926 $455,104 $658,286 $79,328 $2,205 $— $81,533 $28,723 $55,109 $— $6,832 $22,147 $112,811 $463,942 $658,286 $94,109 $12,718 $9,634 $65,591 $16,028 $6,445 $20,017 $224,542 $6,000 $— $8,436 $373,251 $5,971 $393,658 $618,200 $58,696 $2,888 $— $61,584 $15,884 $51,548 $— $6,914 $19,713 $94,059 $462,557 $618,200 $75,256 $11,296 $19,830 $100,806 $13,215 $7,036 $10,510 $237,949 $6,000 $— $12,200 $361,230 $2,666 $382,096 $620,045 $59,302 $2,398 $20,259 $81,959 $16,459 $35,820 $— $6,803 $16,891 $75,973 $462,113 $620,045 $56,390 $9,245 $14,953 $93,886 $11,397 $6,823 $15,864 $208,558 $6,000 $— $3,213 $345,644 $2,476 $357,333 $565,891 $60,331 $2,328 $20,134 $82,793 $17,472 $24,222 $— $5,217 $14,958 $61,869 $421,229 $565,891 $104,340 $9,629 $10,555 $107,275 $13,773 $5,475 $12,086 $263,133 $6,000 $— $3,032 $319,252 $11,463 $339,747 $602,880 $67,195 $2,567 $53,600 $123,362 $18,384 $17,386 $27,845 $3,179 $13,393 $80,187 $399,331 $602,880 22Cash and liquidity At December 31, 2023, the Company held cash of $90.6 million and restricted cash of $20.7 million, totaling $111.3 million, a $8.7 million decrease from $120.0 million at December 31, 2022. Working capital was $121.6 million at December 31, 2023 as compared to $139.8 million at December 31, 2022. VAT receivable VAT receivable - current VAT receivable - non-current Total VAT receivables December 31, 2023 December 31, 2022 10,555 1,934 12,489 9,709 2,226 11,935 Valued Added Tax (“VAT”) in Peru is levied on the purchase of goods and services and is recoverable on contracted oil sales. As a result of capital activity and oil sales during the period, the Company recovered $26.9 million during 2023 and expects to recover $9.7 million in the short-term. Trade and other receivables Trade receivables Other receivables Total trade and other receivables Represented as: Current receivables Non-current receivables December 31, 2023 December 31, 2022 105,647 1,628 107,275 76,163 2,809 78,972 58,602 20,370 107,275 — At December 31, 2023, trade receivables represent revenue related to the sale of oil. The balance is comprised of $26 million due from Petroperu ($6 million is short term and $20 million is long term) and $50 million from export sales through Brazil (all of which has been subsequently collected). No credit losses on the Company’s trade receivables have been incurred. Capital expenditures Drilling Program Field Infrastructure Fluid Handling Facilities (CPF) Erosion Control Abandonment Block 95 Block 107 Other Total Year Ended December 31, 2023 December 31, 2022 61,354 5,027 13,214 5,517 4,917 1,472 1,324 1,378 67,271 27,483 6,247 3,205 — 1,185 1,547 1,515 108,453 94,203 The Company’s primary focus is to increase oil production from existing wells, build on the success of drilling new wells and ensure sufficient production facilities. The Company invested $108.5 million in capital programs in 2023, compared to $94.2 million in 2022. The Company continues to invest in a variety of community, social and regulatory (“CSR”) initiatives. A strong emphasis on ESG is prevalent throughout all areas of our operations. At December 31, 2023, the Company has $9.0 million of exploration and evaluation assets related to Block 95 and Block 107. 23Inventory Oil inventory Materials, parts and supplies Total inventory December 31, 2023 813 11,979 12,792 December 31, 2022 2,389 11,384 13,773 Oil inventory consists of stored oil barrels, which are valued at the lower of cost or net realizable value. Costs include operating expenses, royalties, transportation, and depletion associated with production. Costs capitalized as inventory will be expensed when the inventory is sold. At December 31, 2023, the oil inventory balance of $0.8 million consists of 35,320 barrels of oil valued at $23.01/bbl (December 31, 2022: $2.4 million, based on 106,621 barrels of oil at $22.40/bbl). Materials, parts, and supplies, including diluent, are expected to be consumed in the short-term. Oil inventory at January 1, 2023 Production Diluent added Internal use (power generation) and other Sales Oil inventory at December 31, 2023 Trade and other payables Trade payables Accrued payables and other obligations Total trade and other payables Barrels 106,621 5,200,424 55,004 (63,244) (5,263,485) 35,320 December 31, 2023 December 31, 2022 32,177 35,018 67,195 25,037 54,291 79,328 At December 31, 2023 and December 31, 2022, trade payables and other payables are primarily related to the drilling and completion of wells and construction of production processing facilities. The other obligations are mainly related to the 2.5% social fund for the benefit of local communities, which totaled to $12.2 million at December 31, 2023 ($5.1 million at December 31, 2022). Commodity Price Derivatives The derivative asset is classified as a Level 2 fair value measurement. The ONP Saramuro agreement, signed with Petroperu during 2021, includes a clause for the purchase price adjustment. The initial sales price is based on the arithmetic average of the ICE Brent 8-month forward price. The realized price is based on the tender price of the oil that is sold at the Bayovar terminal. The purchase price adjustment represents the realized price less the initial sales price, and if negative, the Company will compensate Petroperu the amount, multiplied by the volume sold or arranged by Petroperu. If the purchase price adjustment is positive, the Company will be compensated by Petroperu in a similar manner. The fair value change of the embedded derivative, considering an average future ICE Brent price marker differential, was recorded as a loss on commodity price derivatives at December 31, 2023. Net derivative asset at beginning of period Cash settlements Cash to be received Realized gain (loss) Unrealized gain (loss) Net derivative asset at end of period Year Ended December 31 2022 2023 20,370 (478) — (2,256) (10,224) 7,412 36,724 3,585 (28,171) 17,488 (9,256) 20,370 24 Sales delivery / Executed month Expected settlement month Volume mbbls Price range $/bbl Hedged range $/bbl Net Derivative Asset Peru Embedded Derivatives (a) Jan-21 to Feb-22 Feb-24 to Jun-26 2,422 a) Embedded derivative related to original Petroperu sales agreement. 55.32 to 85.26 70.85 to 78.39 Net Derivative Asset 7,412 7,412 During the year ended December 31, 2023, no barrels were sold by Petroperu and 2.4 million barrels remain in the pipeline or storage tanks, awaiting final sale by Petroperu. A 1% change to the hedged range price would result in a $1.6 million change to the net derivative asset. Decommissioning liabilities The undiscounted uninflated value of its estimated decommissioning liabilities is $39.0 million ($30.2 million in 2022). The present value of the obligations was calculated using an average risk-free rate of 5.3% (December 31, 2022: 6.6%) 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 estimate was 2.0%. The table below sets out the continuity of decommissioning obligations. Balance at January 1, 2022 Additions Revisions to decommissioning liabilities Expenditures Accretion Balance at December 31, 2022 Additions Revisions to decommissioning liabilities Accretion Balance at December 31, 2023 22,101 1,916 (6,604) (4,917) 897 13,393 5,390 2,370 994 22,147 25Short and long-term debt On February 16, 2023, in accordance with the terms of the bond agreement the company paid $25 million and on March 24, 2023, the Company elected to repay the remaining $55 million bond principal, plus interest and fees of $2.9 million. The original bond maturity was February 2024. On March 2, 2023, the Company finalized a $20 million unsecured revolving loan with an interest rate of 8.97% with Banco de Credito del Peru. The term of the loan is for two months with renewal options. No debt covenants were set forth by the lender in the loan agreement. The funds were used to fund short-term working capital needs. On August 3, 2023, the Company repaid $20 million to Banco de Credito del Peru for its revolving loan plus $0.7 million in accrued interest. At December 31, 2023, the $20 million revolving loan remains fully available. Leases In prior years, PetroTal commenced a seven-year service lease arrangement with a supplier that provides turnkey power generation equipment services. In Q4 2023, the Company signed an addendum to extend the lease to September 30, 2031 and lease additional equipment in 2024, which resulted in a $12.4 million present value increase to lease assets and liabilities on the balance sheet. The Company has the option to buy the equipment on April 30, 2031 for $3.0 million. The incremental borrowing rate used to measure the lease liabilities was 8.5% for the dollar denominated lease. The lease liabilities also include two office leases, one in Houston, Texas and one in Lima, Peru. The Houston lease is for a term of 6.2 years with an incremental borrowing rate of 6.5% and the Lima lease is for 5 years with an incremental borrowing rate of 8.5%. Lease liabilities at January 1, 2022 Additions Revisions Payments Interest on leases Lease liabilities at December 31, 2022 Revisions Payments Interest on leases Lease liabilities at December 31, 2023 Represented as: Current liability Non-current liability As of December 31, 2023, total lease liabilities have the following minimum undiscounted payments per year: Year 2024 2025 Thereafter Total 17,661 7,263 (2,332) (3,974) 1,024 19,642 12,389 (4,465) 1,304 28,870 2,205 26,665 5,014 5,043 26,272 36,329 26 Share capital Authorized share capital consists of an unlimited number of common shares without nominal or par value. The holders of common shares have one vote per share and are entitled to receive dividends as recommended by the Board. During 2023, all remaining warrants were exercised, generating proceeds of $12.3 million. As of March 19, 2024, PetroTal has the following securities outstanding (in thousands): Common shares Performance share units Total Dividends 915,449 20,802 936,251 98% 2% 100% During the years ended December 31, 2023 and 2022, the Company paid dividends to shareholders in the amount of $55.6 million and $0 million, respectively. The Company declared dividends per share in the amount of $0.015, $0.025 and $0.02 per quarter beginning in Q2, respectively. The Company’s dividend policy is to pay dividends based on current liquidity exceeding $60 million. Normal course issuer bid On May 16, 2023, the Company announced that the Toronto Stock Exchange approved a notice of intention to commence a normal course issuer bid ("NCIB"). The NCIB allows the Company to purchase up to 44,230,205 common shares (representing approximately 5% of outstanding common shares as at May 12, 2023) beginning May 18, 2023 and ending no later than May 17, 2024. Common shares purchased under the NCIB will be cancelled. During the years ended December 31, 2023 and 2022, the Company purchased 11,326,806 and zero common shares under the NCIB for total consideration of $6.5 million and $0 million, respectively. The surplus between the total consideration and the carrying value of the shares repurchased was recorded against retained earnings. 5.3 NON-GAAP TERMS This report contains financial terms that are not considered measures under GAAP such as operating netback, operating netback per bbl, revenues and transportation expense adjusted, funds flow provided by operations, funds flow provided by operations per bbl, funds flow netback per bbl, free funds flow and diluted funds flow per share that do not have any standardized meaning under GAAP and may not be comparable to similar measures presented by other companies. Management uses these non-GAAP measures for its own performance measurement and to provide shareholders and investors with additional measurements of the Company’s efficiency and its ability to fund a portion of its future capital expenditures. NON-GAAP FINANCIAL MEASURES Revenue and transportation expense adjustment Revenue and transportation expense adjustment are a non-GAAP measure that includes transportation ONP pipeline tariff, marketing fee, barging and diluent expenses. Tariff and marketing fees are expenses usually recorded by reducing revenues in the financial statements. 27Funds flow information Funds flow provided by operations (“FFO”), is a non-GAAP measure that includes all cash generated from operating activities and changes in non-cash working capital. The Company considers funds flow from operations to be a key measure as it demonstrates Company’s profitability. A reconciliation from cash provided by operating activities to funds flow provided by operations is as follows: Cash flow from operating activities Net income Adjustments for: Depletion, depreciation and amortization Accretion of decommissioning obligation Equity based compensation expense Financial interest expense Deferred income tax expense Commodity price unrealized derivatives loss Funds flow provided by operations before non-cash working capital Settlement of abandonment liabilities Changes in non-cash working capital: Receivables and restricted cash Advances and prepaid expenses Inventory Trade and other payables Commodity price realized derivatives gain Cash paid for income taxes Net cash provided by operating activities Three Months Ended December 31 2023 2022 Year Ended December 31 2023 2022 21,530 37,176 110,505 188,527 12,232 298 1,145 2,561 (3,160) 11,662 46,268 — (15,760) (906) 2,400 21,876 — (111) 53,767 7,116 238 997 3,522 8,520 (13,375) 44,194 (2,868) 8,835 171 (2,120) 16,015 (3,492) (1,352) 59,383 39,801 994 4,340 10,473 25,766 10,223 202,102 — 26,668 (746) 497 9,443 2,734 (1,241) 239,457 33,568 897 3,342 17,419 16,889 9,256 269,898 (4,917) (114,318) (1,204) 6,240 12,676 7,097 (3,453) 172,019 Free funds flow after investing activities is a non-GAAP measure and the Company considers free funds flow or free cash flow to be a key measure as it demonstrates the Company’s ability to fund a return of capital without accessing outside funds and is calculated as follows: Cash flow from investing activities Exploration and evaluation asset additions Property, plant and equipment additions Non-cash changes in working capital Net cash used in investing activities Net cash provided by operating and investing activities Three Months Ended December 31 2023 2022 Year Ended December 31 2023 2022 (359) (31,798) (1,243) (33,400) 20,367 (240) (31,785) 563 (31,462) 27,921 (1,631) (106,822) 2,700 (105,753) 133,704 (1,291) (92,912) (531) (94,734) 77,285 28 CAPITAL MANAGEMENT MEASURES Adjusted EBITDA Adjusted EBITDA means earnings before interest, taxes, depreciation and amortization, and derivatives. Net income Adjustments to reconcile net income: Depletion, depreciation and amortization Financial expense Income tax expense Commodity price derivatives loss (gain) EBITDA (non-GAAP) Realized derivative instruments gain (loss) Adjusted EBITDA (non-GAAP) Capital expenditures Free funds flow Operating netback Three Months Ended December 31 2023 2022 Year Ended December 31 2022 2023 21,530 37,176 110,505 188,527 11,527 3,150 4,076 11,662 51,946 (11,662) 40,284 (32,157) 8,127 7,116 2,387 8,974 (13,372) 42,280 (5,943) 36,338 (32,024) 4,314 39,801 15,341 33,002 12,479 211,128 (12,001) 199,127 (108,453) 90,674 33,568 20,169 17,390 (8,231) 251,423 4,647 256,070 (94,202) 161,868 The Company considers operating netbacks to be a key measure that demonstrates the Company’s profitability relative to current commodity prices. Netback is calculated by dividing net operating income by total revenue. 6. 2023 RESERVE REPORT Block 95 - Bretana oil field Oil production commenced in Bretana in June 2018 via a long-term testing program of the single oil producer. In May 2019, the Company received the approval of the Environmental Impact Assessment (“EIA”) to fully develop the Bretana field in Block 95. This approval provided PetroTal with the necessary permits to execute its development strategy at Bretana. The summary below sets forth PetroTal’s reserves at December 31, 2023, as presented by NSAI, a qualified independent reserves evaluator. The figures in the following tables have been prepared in accordance with the standards contained in the most recent publication of the Canadian Oil and Gas Evaluation Handbook (“COGE”) and the reserve definitions contained in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). More detailed information will be included in PetroTal’s AIF for the year ended December 31, 2023 to be posted on SEDAR (www.sedar.com) and on PetroTal’s website. Summary of Oil Reserves and Net Present Values as of December 31, 2023 Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved & Probable Possible Total Proved & Probable & Possible Company Heavy Oil Reserves (mmbbl) Future Net Revenue After Income Taxes Discounted at (in USD Million) Gross Net 0% 5% 10% 15% 20% 28.5 19.5 48.0 52.2 100.2 99.4 199.6 28.5 19.5 48.0 52.2 100.2 99.4 199.6 $673 $696 $1,369 $1,856 $3,225 $4,101 $7,326 $567 $517 $1,084 $1,151 $2,235 $1,779 $4,014 $487 $401 $888 $751 $1,639 $869 $2,508 $426 $321 $747 $510 $1,257 $471 $1,728 $378 $266 $644 $357 $1,001 $278 $1,279 29Summary of Pricing and Inflation Rate Assumptions - Forecast Prices and Costs (US$/bbl) Year-end Forecast Brent January 1, 2023 Brent January 1, 2024 2024 $82.69 $78.00 2025 $81.03 $79.18 2026 $81.39 $80.36 2027 $82.65 $81.79 2028 $84.29 $83.41 2029 $85.98 $85.09 Year-end Crude Oil Reserves (mmbbl) Category Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved plus Probable Possible Total Proved plus Probable & Possible Year-end Net Present Value at 10% - After Income Tax ($ millions) Category Proved Developed Producing Proved Undeveloped Total Proved Probable Total Proved plus Probable Possible Total Proved plus Probable & Possible 2023 28.5 19.5 48.0 52.2 100.2 99.4 199.6 2023 $487 $401 $888 $751 $1,639 $869 $2,508 2022 24.1 21.4 45.5 51.3 96.8 71.6 168.4 2022 $446 $339 $785 $724 $1,509 $959 $2,468 Change 18% (9%) 5% 2% 4% 39% 19% Change 9% 18% 13% 4% 9% (9%) 2% Year-end Net Asset Value ("NAV") per Share - After Tax Category Proved Proved plus Probable Proved plus Probable & Possible US$/sh $0.97 $1.80 $2.75 CAD$/sh $1.29 $2.39 $3.65 US$/sh $0.90 $1.75 $2.86 CAD$/sh $1.23 $2.29 $3.47 December 31, 2023 December 31, 2022 Reserve Life Index ("RLI") Category Proved Proved plus Probable Proved plus Probable & Possible December 31, 2023 9.2 years 19.3 years 38.4 years 30Future Development Costs 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: Proved $125 million Proved plus Probable $551 million Proved plus Probable & Possible $768 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. Bretana's reserve life index for 1P and 2P reserves is 9.2 years and 19.3 years, respectively. The cumulative capital invested combined with all future development and abandonment costs represents total funding and development costs of $6.40/bbl for 1P reserves, $7.69/bbl for 2P reserves and $4.49/bbl for 3P reserves. Original Oil in Place (“OOIP”) largely flat from 2022 levels. Now at 326, 442, and 595 million bbls (“mmbbls”), respectively, for the 1P, 2P and 3P cases In addition to ongoing development of the Bretana oilfield, there are other prospects within Block 95 and exploration opportunities in Block 107. 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”), leases, derivatives, asset acquisition and joint arrangements. Significant estimates in the Financial Statements include commitments, provision for future decommissioning obligations, recoverable amounts for exploration and evaluation assets and accruals. In addition, the Company uses estimates for numerous variables in the assessment of its assets for impairment purposes, including oil prices, exchange rates, discount rates, cost estimates and production profiles. By their nature, all of these estimates are subject to measurement uncertainty, may be beyond management’s control, and the effect on future Financial Statements from changes in such estimates could be significant. Critical judgments in applying accounting policies that have the most significant effect on the amounts recognized in the Financial Statements are included in the Financial Statements and the accompanying notes as of December 31, 2023 and 2022. Additional information about significant judgements and estimates are included in PetroTal’s audited Financial Statements for the years ended December 31, 2023 and 2022. USES OF CRITICAL ACCOUNTING ASSUMPTIONS, ESTIMATES AND JUDGEMENTS The Company's critical estimates and associated assumptions are based on historical experience and other factors that are considered relevant. Such estimates and assumptions affect the application of accounting policies and the reported amount of assets, liabilities, income and expenses. Actual results may differ from estimates. The critical 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 estimates and judgements 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. 31Exploration and Evaluation Assets The accounting for 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 hydrocarbons, 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 judgement, 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. 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, and 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 the expiration 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 Financial Statements. The actual results ultimately may differ from those estimates as future confirming events occur. The Company has one reportable business segment which did not have any critical accounting estimate changes during the past two financial years. 328. DISCLOSURE PRONOUNCEMENTS NOT YET ADOPTED Issuance of IFRS Sustainability Standards - IFRS S1 "General Requirements for Disclosure of Sustainability-related Financial Information" and IFRS S2 "Climate-related Disclosures" In June 2023 the International Sustainability Standards Board ("ISSB") issued its inaugural standards - IFRS S1 and IFRS S2. The ISSB was formed as a new standard-setting board within the IFRS Foundation to issue standards that deliver a comprehensive global baseline of sustainability-related financial disclosures, operating alongside the International Accounting Standards Board. IFRS S1 and IFRS S2 are effective for annual reporting periods beginning on or after January 1, 2024, with earlier application permitted, as long as both standards are applied. IFRS S1 provides a set of disclosure requirements designed to enable companies to communicate to investors about the sustainability-related risks and opportunities, while IFRS S2 sets out specific climate-related disclosures and is designed to be used in conjunction with IFRS S1. The Company is currently reviewing the impact of the standards on its disclosures. 9. RELATED PARTY TRANSACTIONS The Company had no related party transactions or off-balance sheet arrangements. The Company's key management includes the Directors and Officers. Salaries, incentives and short term benefits Director's fees Share-based compensation Total Year Ended December 31 2022 2023 1,846 1,014 2,430 5,290 1,785 1,050 1,615 4,450 Name Manuel Pablo Zuniga-Pflucker (1) Mark McComiskey (Chair) Gary S. Guidry (2) Ryan Ellson (2) Gavin Wilson Eleanor J. Barker Roger M. Tucker Jon Harris (3) Felipe Arbelaez (6) Emily Morris (4) Luis Carranza (5) Director Compensation Compensation Earned Share-based awards Non-Equity Incentive Plans 2023 Total 2022 Total 450,000 105,000 — — 60,000 82,000 80,000 60,000 29,032 13,226 57,500 936,758 1,100,000 182,733 — — 61,671 61,158 61,158 60,250 29,077 13,234 57,534 1,626,815 337,500 — — — — — — — — — — 337,500 1,887,500 287,733 — — 121,671 143,158 141,158 120,250 58,109 26,460 115,034 2,901,073 2,000,000 285,000 146,492 146,492 120,000 142,000 140,000 35,000 — — 35,000 3,049,984 (1) Mr. Zuniga-Pflucker does not receive compensation fees or share-based awards for his role as a Director. (2) Directors retired from the Board in September 2022. (3) Directors joined the Board in September 2022. (4) Director joined the Board in October 2023. (5) Director retired from the Board in June 2023. (6) Director joined the Board in July 2023. 10. TAXES The Company’s effective tax rate is impacted each quarter by the relative pre-tax income earned by the Company’s operations in Canada, U.S., and Peru. The Company is subject to statutory tax rates of 23% in Canada, 21% in the U.S. and 32% in Peru (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 and local income tax returns in the various jurisdictions. 33 The tax at the effective rate differed from the tax at the statutory rate as follows: Earnings before income taxes Canadian corporate tax rate Expected income tax expense Increase (decrease) in taxes resulting from: Non-deductible expenses and other Tax differential on foreign jurisdictions Change in valuation allowance Provision for income taxes The deferred income tax balances are as follows: Deferred income tax asset: Property, plant, and equipment Trade and other payables Net operating loss carryover Other tax pools Deferred income tax asset Deferred income tax liability: Property, plant, and equipment Derivative assets and liabilities Preoperative expenses Net operating loss carryover Other tax pools Deferred income tax liability December 31, 2023 December 31, 2022 205,917 143,507 23.00 % 33,007 1,408 10,212 (11,625) 33,002 23.00 % 47,361 2,047 19,742 (51,760) 17,390 December 31, 2023 December 31, 2022 7 — 4,119 8,919 13,045 (58,554) (2,372) 2,549 2,156 1,112 (55,109) (11) 254 855 — 1,098 (46,886) (5,643) 3,186 29,985 1,972 (17,386) The Company recognized the net tax amount related to Net Operating Losses (“NOLs”) and deferred tax liabilities in Peru, Canada and the US. As of December 31, 2023, the Company has $7 million in available tax losses in Peru (mainly related to Block 95), $21 million tax losses in Canada and $2 million in the US (December 31, 2022: $112 million, $69 million, and $1.7 million, respectively). The Peruvian non-capital losses are expected to be used in 2024. The Canadian non-capital losses can be carried forward for twenty years and there is generally no carryback period. The carryover period starts with the taxable year following the loss and continues indefinitely. The US non-capital losses can be carried forward indefinitely. The aggregate amount of temporary differences associated with investments in subsidiaries for which deferred tax liabilities have not been recognized as of December 31, 2023 is approximately $29 million (December 31, 2022: $50 million). 34 11. CONTRACTUAL OBLIGATIONS AND COMMITMENTS GUARANTEES As at December 31, 2023, 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 CONTRACTUAL OBLIGATIONS Commitment 1st exploration well, minimum work 5th exploratory period 2nd exploration well, minimum work 5th exploratory period Expiration May 2026 May 2026 Refer to "Short and long-term debt" in section "5.2 Balance Sheet Information" for material changes to the Company's contractual obligations. 12. FORWARD-LOOKING STATEMENTS AND BUSINESS RISKS FOREIGN EXCHANGE RATE RISK The Company’s functional currency is the United States dollar. Foreign exchange gains or losses can occur on translation of working capital denominated in currencies other than the functional currency of the jurisdiction which holds the working capital item. Excluding the impact of changes in the cross-rates, a 1% fluctuation in translation rates would have nil impact on net income or loss, based on foreign currency balances held at December 31, 2023. LIQUIDITY RISK Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. The Company’s approach to managing liquidity risk is to have sufficient cash and/or credit facilities to meet its obligations when due. Liquidity is managed through short and long-term cash, debt and equity management strategies. 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 economic environment and SARS-CoV-2 (“COVID-19”) has and may continue to have a significant impact 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; interruptions in operations as the Company adjusts personnel to the dynamic environment; and, delivery of oil at the Bayovar port and sale swap price risk. 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 drilling expenses incurred in prior years. These credits will be applied to future oil development activities or recovered as per the sales tax recovery legislation currently in effect. The majority of the Company’s trade receivable balance relates to oil sales and purchase price adjustments to two customers, being Petroperu, a state-owned company and Novum, an oil trading company. The Company has a long-term sales agreement for oil exports through Brazil, whereby sales are FOB Bretana. Sales through the ONP pipeline are due and payable 240 days after the final delivery of the oil to the Bayovar terminal. During Q4 2023, 82% of oil sales were to Novum (Brazil export route) and 18% were to Petroperu (Iquitos refinery). The Company has not experienced any material credit losses in the collection of its trade receivables. 35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, 2023, the cash and cash equivalents were held with six different institutions from three countries, mitigating the credit risk of a collapse of one particular bank. WORKFORCE MAY BE EXPOSED TO WIDESPREAD PANDEMIC PetroTal’s 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 the workforce at risk. The 2020/2021 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 the Company’s personnel and ultimately its operations. Additional information regarding risk factors including, but not limited to, risks related to political developments in Peru and environmental risks is available in the Company’s Annual Information Form ("AIF"), a copy of which may be accessed through the SEDAR website (www.sedar.com). Certain statements contained in this MD&A may constitute forward-looking statements. These statements relate to future events or the Company’s future performance, including, but not limited to: PetroTal's business strategy, objectives, strength, focus and outlook, drilling, completions, workovers and other activities including expanding infrastructure and exploring undeveloped acreage and the anticipated costs and results of such activities, environmental remediation and social initiatives, the ability of the Company to achieve drilling success consistent with management's expectations, anticipated future production and revenue, oil production levels, the 2024 capital program and budget, including drilling plans, balance sheet strength, COVID-19 surveillance and control process, hedging program and the terms thereof, and future development and growth prospects. All statements other than statements of historical fact may be forward-looking statements. In addition, statements relating to expected production, reserves, prospective resources, recovery, costs and valuation are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Forward-looking statements are often, but not always, identified by the use of words such as “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “intend”, “could”, “might”, “should”, “believe” and similar expressions. The forward-looking statements are based on certain key expectations and assumptions made by the Company, including, but not limited to, expectations and assumptions concerning the ability of existing infrastructure to deliver production and the anticipated capital expenditures associated therewith, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices and the actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labor, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the accuracy of PetroTal's geological interpretation of its drilling and land opportunities, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance of new wells, the Company's growth strategy, general economic conditions and availability of required equipment and services. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. The Company believes that the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon by investors. These statements speak only as of the date of this MD&A and are expressly qualified, in their entirety, by this cautionary statement. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of reserve estimates, the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price volatility, price differentials and the actual prices received for products, exchange rate fluctuations, legal, political and economic instability in Peru, access to transportation routes and markets for the Company's production, changes in legislation affecting the oil 36and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. In addition, the Company cautions that current global uncertainty with respect to the spread of the COVID-19 virus and its effect on the broader global economy may have a significant negative effect on the Company. While the precise impact of the COVID-19 virus on the Company remains unknown, rapid spread of the COVID-19 virus may continue to have a material adverse effect on global economic activity, and may continue to result in volatility and disruption to global supply chains, operations, mobility of people and the financial markets, which could affect interest rates, credit ratings, credit risk, inflation, business, financial conditions, results of operations and other factors relevant to the Company. Please refer to the risk factors identified in the AIF which is available on SEDAR at www.sedar.com. Although the Company believes that the expectations reflected in the forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. The Company cannot guarantee future results, levels of activity, performance, or achievements. The risks and other factors, some of which are beyond the Company’s control, could cause results to differ materially from those expressed in the forward-looking statements contained in this MD&A. The forward-looking statements contained in this MD&A are expressly qualified by the foregoing cautionary statement. Subject to applicable securities laws, the Company is under no duty to update any of the forward-looking statements after the date hereof or to compare such statements to actual results or changes in the Company’s expectations. Financial outlook information contained in this MD&A about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information should not be used for purposes other than for which it is disclosed herein. Prospective resources are the quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Estimates of prospective resources included in this document relating to the Osheki prospect are based upon an independent assessment completed by NSAI with an effective date of September 30, 2018 and prepared in accordance with Canadian Oil and Gas Evaluation Handbook ("COGE") and the standards established by NI 51-101. For additional information about the Company’s prospective resources, see the Company’s website for the most current press release. 37ADDITIONAL INFORMATION On February 16, 2023, the Company graduated from the TSX Venture Exchange to the Toronto Stock Exchange. The trading symbol remains the same, "TAL". Additional information about PetroTal Corp. and its business activities, including PetroTal’s audited Financial Statements for the years ended December 31, 2022 and 2021 are available on the Company's website at www.petrotal-corp.com, and at www.sedarplus.ca, or below: DIRECTORS Mark McComiskey (1)(4) Chair of the Board Felipe Arbelaez (3)(4) Eleanor Barker (4) Jon Harris (1)(2) Emily Morris Roger Tucker (2)(3) Gavin Wilson (1)(2)(3) Manuel Pablo Zuniga-Pflucker (2) OFFICERS AND SENIOR EXECUTIVES Manuel Pablo Zuniga-Pflucker President and Chief Executive Officer Douglas Urch Executive VP and Chief Financial Officer Jose Contreras Senior VP of Operations Glen Priestley VP Finance and Treasurer Guillermo Florez General Manager Peru CORPORATE HEADQUARTERS PetroTal Corp. 16200 Park Row, Suite 310 Houston, Texas 77084 Office: 713.609.9101 info@petrotal-corp.com www.petrotal-corp.com LEGAL COUNSEL Stikeman Elliott LLP Calgary, Alberta, Canada AUDITORS Deloitte LLP Calgary, Alberta, Canada Lima, Peru REGISTERED OFFICE PetroTal Corp. 4200 Bankers Hall West, 888-3rd Street Calgary, Alberta, Canada NOMINATED & FINANCIAL ADVISER Strand Hanson Limited London, United Kingdom OPERATING OFFICE PetroTal Peru SRL 144 Dionisio Derteano, Suite 1200 San Isidro Lima, Peru JOINT BROKERS Stifel Nicolaus Europe Limited London, United Kingdom Peel Hunt LLP London, United Kingdom STOCK EXCHANGES TSX Exchange Toronto, Ontario, Canada TSX: TAL AIM Stock Exchange London, United Kingdom AIM: PTAL OTCQX Stock Exchange New York, USA OTCQX: PTALF RESERVES EVALUATORS Netherland, Sewell & Associates, Inc. Dallas, Texas, USA TRANSFER AGENT AND REGISTRAR Computershare Trust Company of Canada Calgary, Alberta, Canada London, United Kingdom Massachusetts, USA and New Jersey, USA (1) Member of the Corporate Governance and Compensation Committee. (2) Member of the Reserves Committee. (3) Member of the HSES Committee. (4) Member of the Audit Committee. 38 GLOSSARY / ABBREVIATIONS 1P 2P 3P AIF bbl bopd CGUs COGE COVID-19 CSR DD&A E&E EIA ESG FOB FFO G&A GAAP IFRS ISSB MD&A mmbbls mmboe NAV NCIB Netback NI 51-101 NOI NSAI OCP ONP OOIP PP&E RLI SDGs VAT Proved Proved plus Probable Proved plus Probable and Possible Annual Information Form Barrel Barrels of Oil per Day Cash Generating Units Canadian Oil and Gas Evaluation Handbook SARS-CoV-2 Community, Social and Regulatory Depletion, Depreciation and Amortization Exploration and Evaluation Environmental Impact Assessment Environmental and Social Governance Freight on board Funds Flow Provided by Operations General and Administrative Generally Accepted Accounting Principles International Financial Reporting Standards International Sustainability Standards Board Management's Discussion and Analysis Million Barrels Million Barrels of Oil Equivalent Net Asset Value Normal Course Issuer Bid Benchmark to assess the profitability based on revenues less royalties, operating and transportation costs National Instruments - Standards of Disclosure for Oil and Gas Activities Net Operating Income Netherland Sewell and Associates, Inc. OCP Ecuador Pipeline Northern Peruvian Pipeline Original Oil in Place Property, Plant and Equipment Reserve Life Index Sustainable Development Goals Value Added Tax 39 CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2023, and 2022 TSX: TAL AIM: PTAL OTCQX: PTALF TABLE OF CONTENTS 1. Management’s report ........................................................................................................................................ 2. Independent auditor’s report ............................................................................................................................. 3. Consolidated balance sheets .............................................................................................................................. 4. Consolidated statements of earnings and other comprehensive income ........................................................ 5. Consolidated statements of changes in equity .................................................................................................. 6. Consolidated statements of cash flows ............................................................................................................. 7. Notes to the Consolidated Financial Statements .............................................................................................. 42 43 47 48 49 50 51 41MANAGEMENT’S REPORT The accompanying audited Consolidated Financial Statements and all information in the management’s 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” Signed “Douglas Urch” Manuel Pablo Zuniga-Pflucker Douglas Urch President and Chief Executive Officer Executive VP and Chief Financial Officer March 19, 2024 42Deloitte LLP  850 – 2nd Street SW  Suite 700  Calgary AB  T2P 0R8  Canada  Phone:  403‐267‐1700  Fax:  403‐264‐2871  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, 2023 and 2022, and the consolidated  statements of earnings and other comprehensive income, changes in equity and cash flows for the years  then ended, and notes to the consolidated financial statements, including material accounting policy  information (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, 2023 and 2022, 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.  Key Audit Matters Key audit matters are those matters that, in our professional judgment, were of most significance in our  audit of the consolidated financial statements for the year ended December 31, 2023. These matters  were addressed in the context of our audit of the consolidated financial statements as a whole, and in  forming our opinion thereon, and we do not provide a separate opinion on these matters.   Derivative Assets and Derivate Liabilities (embedded derivative) — Refer to Note 9 to the  financial statements  Key Audit Matter Description  The company has an agreement for the sale of crude oil with Petroleos del Peru (PetroPeru S.A. a state  owned company based in Peru). Under the agreement, the Company has exposure to the volatility of oil  commodity prices until the crude oil is finally sold by PetroPeru to its customers at the Bayovar terminal  (i.e., final settlement date). The exposure to fluctuations of future commodity prices is an embedded  derivative and is measured at fair value at the end of the reporting period. The fair value of the derivative  is calculated using the future strip prices of Brent on the estimated final settlement dates for each  shipment that has not reached Bayovar terminal.  43  Determining the fair value of the embedded derivative required management to make significant  estimates and assumptions regarding future strip prices of Brent on the estimated final settlement dates.  Auditing these estimates and assumptions required a high degree of auditor judgment in applying audit  procedures and in evaluating the results of those procedures.  This resulted in an increased extent of  audit effort.  How the Key Audit Matter Was Addressed in the Audit  Our audit procedures related to the fair value determination of the embedded derivative included the  following, among others:    Evaluated management’s ability to accurately estimate the final settlement dates by:  - Comparing historical sales settlement dates with management’s estimated final settlement dates;  - Obtaining corroborating evidence to support management’s estimate of the settlement date, as  well as assessing whether there was any evidence contradicting management’s estimates;   Evaluated the reasonableness of the prices used in the determination of the fair value of the  embedded derivative by independently assessing the price to future third‐party strip prices of Brent,  considering the estimated final settlement dates; and   Recalculated the fair value of the embedded derivative and compared it to the fair value determined  by management.  Property, Plant and Equipment – Petroleum interests ‐ Refer to Note 11 to the financial  statements  Key Audit Matter Description  The Company’s property, plant and equipment includes petroleum interests. Petroleum interests are  measured by depleting the assets on a unit‐of‐production method (“depletion”) based on total estimated  proved plus probable reserves. The Company engages independent reserve engineers to estimate the  proved plus probable reserves using estimates, assumptions, and engineering data. The development of  the Company’s reserves used to evaluate depletion requires management to make significant estimates  and assumptions related to future crude oil prices, reserves, and future operating and development costs.     Given the significant judgments made by management related to future crude oil prices, reserves, and  future operating and development costs, these estimates and assumptions are subject to a high degree of  estimation uncertainty. Auditing these estimates and assumptions required auditor judgement in applying  audit procedures, including the extent of reliance on management’s expert, and in evaluating the results  of those procedures. This resulted in an increased extent of audit effort.  How the Key Audit Matter Was Addressed in the Audit  Our audit procedures related to future crude oil prices, reserves, and future operating and development  costs used to determine depletion included the following, among others:      Evaluated future crude oil prices by independently developing a reasonable range of forecasts based  on reputable third‐party forecasts and market data and comparing those to the future crude oil  prices selected by management;  Evaluated the Company’s independent reserve engineers by examining reports and assessed their  scope of work and findings; and assessing the competence, capability, and objectivity by evaluating  their relevant professional qualifications and experience;   Evaluated the reasonableness of reserves by testing the source financial information underlying the  reserves and comparing the reserve volumes to historical production volumes;  44 Evaluated the reasonableness of future operating and development costs by testing the source financial information underlying the estimate, comparing future operating and development costs to historical results, and evaluating whether they are consistent with evidence obtained in other areas of the audit. Other Information Management is responsible for the other information. The other information comprises:    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.   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. 45 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.  We also provide those charged with governance with a statement that we have complied with relevant  ethical requirements regarding independence, and to communicate with them all relationships and other  matters that may reasonably be thought to bear on our independence, and where applicable, related  safeguards.  From the matters communicated with those charged with governance, we determine those matters that  were of most significance in the audit of the consolidated financial statements of the current period and  are therefore the key audit matters. We describe these matters in our auditor's report unless law or  regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we  determine that a matter should not be communicated in our report because the adverse consequences  of doing so would reasonably be expected to outweigh the public interest benefits of such  communication.  The engagement partner on the audit resulting in this independent auditor’s report is Christopher Gill.  /s/ to be signed Deloitte LLP  Chartered Professional Accountants  March 19, 2024  46CONSOLIDATED BALANCE SHEETS ($ thousands of US Dollars) ASSETS Current Assets Cash Restricted cash VAT receivable Trade and other receivables Inventory Prepaid expenses Derivative assets Total Current Assets Non-current Assets Restricted cash Trade receivable long-term Exploration and evaluation assets Property, plant and equipment Deferred income tax asset VAT receivable Derivative assets Total Non-current Assets Total Assets LIABILITIES AND EQUITY Current Liabilities Trade and other payables Lease liabilities Short-term debt Total Current Liabilities Non-current Liabilities Long-term debt Long-term derivative liabilities Lease liabilities Decommissioning liabilities Deferred income tax liabilities Other long-term obligations Total Non-current Liabilities Total Liabilities Equity Share capital Contributed surplus Retained earnings Total Equity Total Liabilities and Equity See accompanying notes to the Consolidated Financial Statements Note December 31 2023 December 31 2022 4 4 5 6 7 8 9 4 6 10 11 23 5 9 13 15 12 12 9 15 14 23 16 90,568 14,731 9,709 58,602 12,792 7,462 9,318 203,182 6,000 20,370 8,973 399,564 13,045 2,226 4,926 455,104 658,286 79,328 2,205 — 81,533 — 6,832 26,665 22,147 55,109 2,058 112,811 194,344 140,672 9,853 313,417 463,942 658,286 104,340 9,629 10,555 107,275 13,773 5,475 12,086 263,133 6,000 — 7,342 311,910 1,098 1,934 11,463 339,747 602,880 67,195 2,567 53,600 123,362 27,845 3,179 17,075 13,393 17,386 1,309 80,187 203,549 130,196 6,262 262,873 399,331 602,880 47CONSOLIDATED STATEMENTS OF EARNINGS AND OTHER COMPREHENSIVE INCOME ($ thousands of US Dollars, except per share amounts) For the years ended December 31 REVENUES Oil revenues, net of royalties and social fund Total revenue EXPENSES Operating Direct transportation General and administrative Other expenses Finance expense Commodity price derivatives loss (gain) Depletion, depreciation and amortization Foreign exchange (gain) loss Total expenses Income before income taxes Current income tax expense Deferred income tax expense Net income and comprehensive income Basic earnings per share Diluted earnings per share Weighted average number of common shares outstanding (000's) Basic Diluted See accompanying notes to the Consolidated Financial Statements Note 2023 2022 17 20 18 19 9 23 23 286,263 286,263 32,446 14,963 28,049 — 15,341 12,479 39,801 (323) 142,756 143,507 7,236 25,766 110,505 0.12 0.12 900,075 920,899 327,115 327,115 32,954 20,622 19,891 978 20,169 (8,231) 33,568 1,247 121,198 205,917 501 16,889 188,527 0.22 0.21 845,761 906,710 48CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY ($ thousands of US Dollars) For the years ended December 31 Share capital Balance, beginning of year Repurchase of shares Exercise of warrants Balance, end of period Contributed surplus Balance, beginning of year Share-based compensation plan Balance, end of period Retained earnings Balance, beginning of year Dividends paid Net income and comprehensive income Repurchase of shares Balance, end of period Total Equity See accompanying notes to the Consolidated Financial Statements Note 2023 2022 16 16 16 16 130,196 (1,839) 12,315 140,672 6,262 3,591 9,853 262,873 (55,566) 110,505 (4,395) 313,417 463,942 126,696 — 3,500 130,196 3,215 3,047 6,262 74,346 — 188,527 — 262,873 399,331 49CONSOLIDATED STATEMENTS OF CASH FLOWS ($ thousands of US Dollars) For the years ended December 31 Cash flows from operating activities Net income Adjustments for: Depletion, depreciation and amortization Accretion of decommissioning obligations Share-based compensation plan Commodity price unrealized derivatives loss Finance expenses Deferred income tax expense Settlement of decommissioning liabilities Changes in working capital: - Receivables and taxes - Advances and prepaid expenses - Inventory - Trade and other payables - Commodity price realized derivatives Cash paid for income taxes Net cash provided by operating activities Cash flows from investing activities Property, plant and equipment additions Exploration and evaluation asset additions Non-cash changes in working capital Net cash used in investing activities Cash flows from financing activities Interest and fees paid Net proceeds from exercise of warrants Repayment of debt principal Funds received from credit facility Payments of dividends to shareholders Repurchase of shares Payment of current lease liabilities Net cash used in financing activities Increase (decrease) in cash Cash, beginning of period Restricted cash Cash, end of the period See accompanying notes to the Consolidated Financial Statements Note 2023 2022 110,505 188,527 14 9 14 9 11 10 16 12 12 15 4 39,801 994 4,340 10,223 10,473 25,766 — 26,668 (746) 497 9,445 2,734 (1,241) 239,459 (106,822) (1,631) 2,700 (105,753) (8,426) 12,315 (100,000) 20,000 (55,566) (6,234) (4,465) (142,376) (8,670) 104,340 (5,102) 90,568 33,568 897 3,342 9,256 17,419 16,889 (4,917) (114,318) (1,204) 6,240 12,676 7,097 (3,453) 172,019 (92,912) (1,291) (531) (94,734) (11,300) 3,500 (20,000) — — — (3,974) (31,774) 45,511 44,919 13,910 104,340 50NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2023 and 2022. All amounts are stated in thousands of United States Dollars ($) unless otherwise indicated. 1. CORPORATE INFORMATION PetroTal Corp. (the “Company” or “PetroTal”) is a publicly-traded energy company incorporated and domiciled in Canada. The Company is engaged in the exploration, appraisal and development of 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 and transactions that occurred after the balance sheet date up to the date that the Financial Statements were issued. These Financial Statements were approved for issuance by the Company’s Board of Directors on March 19, 2024, on the recommendation of the Audit Committee. 2. BASIS OF PREPARATION STATEMENT OF COMPLIANCE The Company prepares its annual Financial Statements in accordance with International Financial Reporting Standards (“IFRS”). BASIS OF MEASUREMENT These Financial Statements have been prepared on a historical cost basis except for certain financial instruments that have been measured at fair value. In addition, these Financial Statements have been prepared using the accrual basis of accounting. PRINCIPLES OF CONSOLIDATION The Company’s Financial Statements include the accounts of the Company and its subsidiaries. The Financial Statements of the subsidiaries are prepared for the same reporting period as the parent Company’s, using consistent accounting practices. Inter-company balances and transactions, and any unrealized gains arising from inter-company transactions with the Company’s subsidiaries, 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. USES OF ACCOUNTING ASSUMPTIONS, ESTIMATES AND JUDGEMENTS 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. Estimates and critical judgements 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. 51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 hydrocarbons, 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 judgement, 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. 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, and 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 the expiration 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 Financial Statements. The actual results ultimately may differ from those estimates as future confirming events occur. MATERIAL ACCOUNTING POLICIES a. Cash and Restricted Cash Cash includes deposits held with banks in Canada, the United States and Peru that are available on demand and highly liquid. The Company’s restricted cash is cash reserved for letters of credit guaranteeing the Company’s commitments for the exploration of Block 107, acquisition of qualified hydrocarbon assets, permitted hedging programs, and the 2.5% social development trust fund (“social fund”) for the benefit of local communities. The restricted cash is not available for the Company’s immediate or general business use. 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 and comprehensive income. When commercial production in an area has commenced, petroleum 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 future crude oil prices, 52reserves and future operating and development costs that affect unit-of-production calculations are accounted for on a prospective basis. c. Leases The Company assesses each new contract to determine whether it contains a lease. A specific asset is the subject of a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The Company allocates contract consideration to the lease and non-lease components on the basis of their relative stand- alone prices. The right-of-use asset is initially measured at cost, which includes: (i) the amount of the initial measurement of the lease liability, (ii) any lease payments made at or before the lease commencement date, less any lease incentives received, (iii) any initial direct costs incurred, and (iv) an estimate of restoration costs. The lease liability and initial right-of-use asset are recognized at the lease commencement date measured at the present value of fixed lease payments (including in-substance fixed payments) plus the exercise price of a purchase option if the lessee is reasonably certain to exercise that option, discounted at a rate the Company would be required to borrow over a similar term. Key judgements include whether a contract identifies an asset (or a portion of an asset), whether the lessee obtains substantially all of the economic benefits of the asset over the contract term, whether the lessee has the right to direct the asset’s use, which components are fixed or variable in nature and the discount rate. The Company applied its incremental borrowing rate for leases where the implicit rate cannot be readily determined. Right-of-use assets are presented within property, plant and equipment. After initial recognition, the lease liability is accreted for the passage of time and reduced for lease settlements made during each period. If the lease terms indicate that the Company will exercise a purchase option, the right-of-use asset is depreciated from the lease commencement date to the end of the useful life of the underlying asset. Otherwise, the right- of-use asset is depreciated to the earlier of the end of the useful life of the underlying asset or to the end of the lease term. Additionally, the Company remeasures the lease liability (and makes a corresponding adjustment to the related right-of-use asset) whenever: (a) The lease term has changed or there is a significant event or change in circumstances resulting in a change in the assessment of exercise of a purchase option, in which case the lease liability is remeasured by discounting the revised lease payments using a revised discount rate. (b) The lease payments change due to changes in an index or rate or a change in expected payment under a guaranteed residual value, in which case the lease liability is remeasured by discounting the revised lease payments using an unchanged discount rate (unless the lease payments change is due to a change in a floating interest rate, in which case a revised discount rate is used). (c) A lease contract is modified and the lease modification is not accounted for as a separate lease, in which case the lease liability is remeasured based on the lease term of the modified lease by discounting the revised lease payments using a revised discount rate at the effective date of the modification. d. Impairment Financial assets carried at amortized cost At each reporting date, the Company assesses whether there is objective evidence that a financial asset carried at amortized cost is impaired. If such evidence exists, the Company recognizes an impairment loss in net earnings (loss). Impairment losses are reversed in subsequent periods if the impairment loss decrease can be related objectively to an event occurring after the impairment was recognized. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. 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. 53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 CGU is the greater of its value in use or 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: • • • • Expiry or impending expiry of lease with no expectation of renewal; Lack of budget or plans for substantive expenditures on further E&E; Cessation of E&E activities due to a lack of commercially viable discoveries; and 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. Inventory Inventory consists of crude oil and supplies to be used in the production and exploration activities, and is measured at the lesser of cost and net realizable value. The cost of crude oil 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 On initial recognition, financial instruments are measured at fair value. Measurement in subsequent periods depends on the classification of the financial instrument: e. f. • • • 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; Fair value through other comprehensive income - transaction costs under this classification are expensed as incurred. Financial instruments under this classification include derivative assets and liabilities where hedge accounting is applied; and Amortized cost - subsequently carried at amortized cost using the effective interest rate method. Financial instruments under this classification includes accounts receivable, accounts payable and accrued liabilities and long-term debt. IFRS 9 also includes a simplified hedge accounting model, aligning hedge accounting more closely with risk management. Derivative instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting. As a result, the Company's policy is to classify all financial derivative contracts at fair value through profit or loss and to record them on the Consolidated Balance Sheet at fair value with a corresponding gain or loss in net earnings (loss). Attributable transaction costs are recognized in net earnings (loss) when incurred. 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. The timing of the expected delivery to the final point of sale drives the value of the embedded derivative in the Petroperu contract, as the fair value of the derivative depends on the oil price at the time of the 54expected sale date at the final point of sale. Refer to Note 9 for the classification and measurement of these financial instruments. The Company’s financial instruments consist of cash, trade and other receivables, derivative assets, trade and other payables, derivative liabilities, and short and long-term debt and are included in the Company’s balance sheet. 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 greater of its value in use and its fair value less costs to sell. 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, climate-related matters, 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 statements of earnings and comprehensive income. Actual costs incurred upon settlement of the obligations are charged against the provision to the extent of the liability recorded and the remaining balance of the actual costs is recorded in the consolidated income statement. i. Income Taxes Income tax expense is comprised of current and deferred tax. Current tax and deferred tax are recognized in net income or loss except to the extent that it relates to a business combination or items recognized directly in equity or in other comprehensive income or loss. Current income taxes are recognized for the estimated income taxes payable or receivable on taxable income or loss for the current year and any adjustment to income taxes payable in respect of previous years. Current income taxes are determined using tax rates and tax laws that have been enacted or substantively enacted by the year-end date. Deferred tax assets and liabilities are recognized where the carrying amount of an asset or liability differs from its tax 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. 55j. Revenue Recognition Under IFRS 15, revenue is recognized when a customer obtains control of the goods 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. k. l. 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. 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 consolidated statements of earnings and comprehensive income. 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. 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. m. 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 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. 563. NEW ACCOUNTING POLICIES, STANDARDS AND INTERPRETATIONS NEW ACCOUNTING POLICIES Share Capital Shareholders’ capital represents the recognized amount for common shares issued (net of equity issuance costs) less the weighted- average carrying value of shares repurchased. The price paid to repurchase common shares is compared to the carrying value of the shares and the difference is recorded against retained earnings. NEW ACCOUNTING STANDARDS ISSUED New accounting standards and interpretations were issued and are mandatory for accounting periods after January 1, 2023. Certain of the new accounting standards and interpretations, which did not have a significant impact on the Company’s Financial Statements upon adoption, are as follows: • • • IAS 1 – Disclosure of Accounting Policies – Effective January 1, 2023, the amendments require an entity to disclose its material accounting policies, instead of its significant accounting policies, while providing guidance on how entities can identify material accounting policy information and examples of when accounting policy information is likely to be material. IAS 1 – Presentation of Financial Statements – Effective January 1, 2023, the amendments clarify the requirements for the presentation of liabilities as current or non-current in the balance sheet. IAS 8 – Definition of Accounting Estimates – Effective January 1, 2023, the amendments distinguish how an entity should present and disclose different types of accounting changes in its financial statements and provides updated definitions to changes in accounting estimates to assist issuers in assessing between a change in accounting policy and a change in accounting estimate. NEW ACCOUNTING STANDARDS ISSUED BUT NOT EFFECTIVE New accounting standards and interpretations were issued and are mandatory for accounting periods after January 1, 2024. The new accounting standards and interpretations, which are not expected to have a significant impact on the Company’s Financial Statements adoption, are as follows: Classification of Liabilities as Current or Non-current – Amendments to IAS 1 In January 2020 and October 2022, the IASB issued amendments to paragraphs 69 to 76 of IAS 1 to specify the requirements for classifying liabilities as current or non-current. An Additional requirement has been introduced to require disclosure when a liability arising from a loan agreement is classified as non-current and the entity’s right to defer settlement is contingent on compliance with future covenants within twelve months. The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must be applied retrospectively. Lease Liability in a Sale and Leaseback - Amendments to IFRS 16 In September 2022, the IASB issued amendments to, Leases (“IFRS 16”) to specify the requirements that a seller-lessee uses in measuring the lease liability arising in a sale and leaseback transaction, to ensure the seller-lessee does not recognize any amount of the gain or loss that relates to the right of use it retains. The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must applied retrospectively to sale and leaseback transactions entered into after the date of initial application of IFRS 16. Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7 In May 2023, the IASB issued amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures to clarify the characteristics of supplier finance arrangements and require additional disclosure of such arrangements. The disclosure requirements in the amendments are intended to assist users of financial statements in understanding the effects of 57supplier finance arrangements on an entity’s liabilities, cash flows and exposure to liquidity risk. The amendments will be effective for annual reporting periods beginning on or after January 1, 2024. 4. CASH AND RESTRICTED CASH The following table sets out cash and restricted cash balances held in different currencies: Balances held in: US dollars Peruvian soles English pounds Canadian dollars Total Represented as: Cash Restricted cash current Restricted cash non-current December 31 2023 December 31 2022 100,996 3,296 3,270 3,737 111,299 90,568 14,731 6,000 117,378 113 2,457 21 119,969 104,340 9,629 6,000 Current restricted cash of $14.7 million, is primarily related to the social fund, letters of credit bank guarantees, and hedge deposits. The $6 million of non-current restricted cash is related to permitted hedging programs (see Note 9). The social fund was formally recognized in 2022 where 2.5% of the value of the monthly oil produced in Bretana’s Block 95, less transportation, is set aside for the benefit of local communities. In March 2023, Peru’s President signed the Supreme Decree authorizing Perupetro S.A. (“Perupetro”) to execute the amendment incorporating the 2.5% social trust fund into the Block 95 license contract, effective and retroactive to January 1, 2022. For the years ended December 31, 2023 and 2022, the Company accrued $7.3 million and $6.3 million, respectively, in social fund expense (see Note 17) of which $0 million and $1.2 million was paid to the community, respectively. 5. VAT RECEIVABLES VAT receivable - current VAT receivable - non-current Total VAT receivables December 31 2023 December 31 2022 9,709 2,226 11,935 10,555 1,934 12,489 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 $26.9 million during the year ended December 31, 2023 and expects to recover $9.7 million in the short- term. 6. TRADE AND OTHER RECEIVABLES SHORT AND LONG TERM Trade receivables Other receivables Total trade and other receivables Represented as: Current receivables Non-current receivables December 31 2023 December 31 2022 76,163 2,809 78,972 58,602 20,370 105,647 1,628 107,275 107,275 — 58 At December 31, 2023, trade receivables represent revenue related to the sale of oil. The balance is comprised of $26 million due from Petroperu ($6 million is short term and $20 million is long term) and $50 million from export sales through Brazil (all of which is due short term). No credit losses on the Company’s trade receivables have been incurred and all short-term receivables are current. 7. INVENTORY Oil inventory Materials, parts and supplies Total inventory December 31 2023 December 31 2022 813 11,979 12,792 2,389 11,384 13,773 Oil inventory consists of the Company's oil barrels, which are valued at the lower of cost or net realizable value. Costs include operating expenses, royalties, transportation, and depletion associated with production. Costs capitalized as inventory will be expensed when the inventory is sold. At December 31, 2023, the oil inventory balance of $0.8 million consists of 35,320 barrels of oil valued at $23.01/bbl (December 31, 2022: $2.4 million, based on 106,621 barrels at $22.40/bbl). Materials, parts and supplies, including diluent, are expected to be consumed in the short-term. 8. PREPAID EXPENSES Advances to contractors Prepaid expenses and other Total advances and prepaid expenses December 31 2023 December 31 2022 507 6,955 7,462 — 5,475 5,475 At December 31, 2023, prepaid expenses were comprised of $5.7 million in Peruvian income tax prepaid and $1.3 million in insurance, prepaid services for consultants, and other related services. 9. RISK MANAGEMENT Cash and restricted cash Trade and other receivables Short-term derivative assets Trade receivable long-term Long-term derivative assets Short and long-term debt Trade and other payables Long-term derivative liabilities December 31, 2023 December 31, 2022 Carrying Value Fair Value Carrying Value Fair Value 111,299 58,602 9,318 20,370 4,926 — 79,328 6,832 111,299 58,602 9,318 20,370 4,926 — 79,328 6,832 119,969 107,275 12,086 — 11,463 81,445 67,195 3,179 119,969 107,275 12,086 — 11,463 82,000 67,195 3,179 The table above details the Company’s carrying value and fair value of financial instruments including cash and restricted cash, trade and other receivables, derivatives, short and long-term debt, and trade and other payables, all of which are classified as financial assets and liabilities and reported at amortized cost or fair value. 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 derivative asset is classified as a Level 2 fair value measurement. The Petroperu Saramuro agreement, signed with Petroperu during 2021, includes a clause for the purchase price adjustment. The initial sales price is based on the arithmetic average of the ICE Brent Crude 8-month forward price. The realized price is based on the tender price of the oil that is sold at the Bayovar terminal. 59 The purchase price adjustment is the realized price less the initial sales price. If the purchase price adjustment is negative, the Company will compensate Petroperu for the amount, multiplied by the volume sold or arranged by Petroperu. If the purchase price adjustment is positive, 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 gain (loss) on commodity price derivatives at December 31, 2023 and 2022. Net derivative asset at beginning of period Cash settlements Cash to be received Realized gain (loss) Unrealized gain (loss) Net derivative asset at end of period December 31 2023 December 31 2022 20,370 (478) — (2,256) (10,224) 7,412 36,724 3,585 (28,171) 17,488 (9,256) 20,370 Sales delivery / Executed month Expected settlement month Volume mbbls Price range $/bbl Hedged range $/bbl Net Derivative Asset Peru Embedded Derivatives (a) Jan-21 to Feb-22 Feb-24 to Jun-26 2,422 a) Embedded derivative related to original Petroperu sales agreement. 55.32 to 85.26 70.85 to 78.39 Net Derivative Asset 7,412 7,412 During the year ended December 31, 2023, no oil was sold by Petroperu, and 2.4 million barrels remain in the pipeline or storage tanks, awaiting final sale by Petroperu. A 1% change to the hedged range price would result in a $1.6 million change to the net derivative asset. FOREIGN EXCHANGE RATE RISK The Company’s functional currency is the United States dollar. Foreign exchange gains or losses can occur on translation of working capital denominated in currencies other than the functional currency of the jurisdiction which holds the working capital item. Excluding the impact of changes in the cross-rates, a 1% fluctuation in translation rates would have nil impact on net income or loss, based on foreign currency balances held at December 31, 2023. LIQUIDITY RISK Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with its financial liabilities. 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 economic environment may 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 constrained oil production; inability to access financing sources; increased risk of non-performance by the Company’s customers and suppliers; interruptions in operations as the Company adjusts personnel to the dynamic environment; and, delivery of oil at Bayovar port and sale swap price risk. Estimates and judgements made by management in the preparation of the financial statements are subject to a certain degree of measurement uncertainty during this volatile period. 60 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 drilling expenses incurred in prior years. These credits will be applied to future oil development activities or recovered as per the sales tax recovery legislation currently in effect. The Company’s trade receivable balance relates to oil sales and purchase price adjustments to two customers, being Petroperu, a state-owned company and Novum, an oil trading company. The Company has a long-term sales agreement for oil exports through Brazil, whereby sales are FOB Bretana. Sales through the ONP pipeline are due and payable 240 days after the final delivery of the oil to the Bayovar terminal. During 2023, 87% of oil sales were to Novum (Brazil export route) and 13% were to Petroperu (Iquitos refinery). The Company has not experienced any material credit losses in the collection of its trade receivables. The Company periodically assesses the recoverability of all trade receivables through discussions with its customers, review of credit rating agency reports or review of other third-party information. 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, cash equivalents and restricted cash 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, 2023, the cash, cash equivalents and restricted cash were held with six different institutions from three countries, mitigating the credit risk of a collapse of one particular bank. 6110.EXPLORATION AND EVALUATION ASSETS The following table sets out a continuity of Exploration and Evaluation Assets: Balance at January 1, 2022 Additions Balance at December 31, 2022 Additions Balance at December 31, 2023 6,051 1,291 7,342 1,631 8,973 The Company determined there were no impairment indicators of the exploration and evaluation assets balance at December 31, 2023 and December 31, 2022. 11.PROPERTY, PLANT AND EQUIPMENT Balance at January 1, 2022 Additions Revisions to decommissioning obligations Revisions to right of use asset Depletion, depreciation and amortization Balance at December 31, 2022 Additions Additions and revisions to decommissioning obligations Revisions to right of use asset Depletion, depreciation and amortization Balance at December 31, 2023 Petroleum Interests Right of Use Asset (Power Plant) Other Assets Total 231,009 91,348 (4,688) — (29,390) 288,279 105,151 7,760 — (36,964) 364,226 20,188 5,894 — (4,158) (1,212) 20,712 — — 12,389 (1,328) 31,773 633 2,933 — — (647) 2,919 1,671 — — (1,025) 3,565 251,830 100,175 (4,688) (4,158) (31,249) 311,910 106,822 7,760 12,389 (39,317) 399,564 At December 31, 2023, $0.3 million of the depreciation, depletion and amortization expense was recorded as inventory (December 31, 2022: $0.7 million). The Company determined there were no impairment indicators of the property, plant and equipment balance at December 31, 2023 and December 31, 2022. 12.SHORT AND LONG-TERM DEBT On February 16, 2023, in accordance with the terms of the bond agreement the company paid $25 million and in March 24, 2023, the Company elected to repay the remaining $55 million bond principal, plus interest and fees of $2.9 million. The original bond maturity was February 2024. On March 2, 2023, the Company finalized a $20 million unsecured revolving loan with an interest rate of 8.97% with Banco de Credito del Peru. The term of the loan is for two months with renewal options. No debt covenants were set forth by the lender in the loan agreement. The funds were used to fund short-term working capital needs. On August 3, 2023, the Company repaid $20 million to Banco de Credito del Peru for its revolving loan plus $0.7 million in accrued interest. At December 31, 2023, the $20 million revolving loan remains fully available. 62 13.TRADE AND OTHER PAYABLES Trade payables Accrued payables and other obligations Total trade and other payables December 31 2023 December 31 2022 25,037 54,291 79,328 32,177 35,018 67,195 At December 31, 2023 and December 31, 2022, trade payables and other payables are primarily related to the drilling and completion of wells and construction of production processing facilities. The other obligations are mainly related to the 2.5% social fund for the benefit of local communities, which totaled to $12.2 million at December 31, 2023 ($5.1 million at December 31, 2022). 14.DECOMMISSIONING LIABILITIES Balance at January 1, 2022 Additions Revisions to decommissioning liabilities Expenditures Accretion Balance at December 31, 2022 Additions Revisions to decommissioning liabilities Accretion Balance at December 31, 2023 22,101 1,916 (6,604) (4,917) 897 13,393 5,390 2,370 994 22,147 The undiscounted uninflated value of estimated decommissioning liabilities is $39.0 million ($30.2 million in 2022). The present value of the obligations was calculated using an average risk-free rate of 5.3% (December 31, 2022: 6.6%) 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 estimate was 2.0%. 15.CURRENT AND NON-CURRENT LEASE LIABILITIES In prior years, PetroTal commenced a seven-year service lease arrangement with a supplier that provides turnkey power generation equipment services. In Q4 2023, the Company signed an addendum to extend the lease term to September 30, 2031 and lease additional equipment in 2024, which resulted in a $12.4 million present value increase to lease assets and liabilities on the balance sheet. The Company has the option to buy the equipment on April 30, 2031 for $3.0 million. The incremental borrowing rate used to measure the lease liabilities was 8.5% for the dollar denominated lease. The lease liabilities also includes two office leases, one in Houston, Texas and one in Lima, Peru. The Houston lease is for a term of 6.2 years with an incremental borrowing rate of 6.5% and the Lima lease is for 5 years with an incremental borrowing rate of 8.5%. Lease liabilities at January 1, 2022 Additions Revisions Payments Interest on leases Lease liabilities at December 31, 2022 Revisions Payments Interest on leases Lease liabilities at December 31, 2023 17,661 7,263 (2,332) (3,974) 1,024 19,642 12,389 (4,465) 1,304 28,870 63 Represented as: Current liability Non-current liability At December 31, 2023, total lease liabilities have the following minimum undiscounted annual payments: Year 2024 2025 Thereafter Total 16.SHARE CAPITAL 2,205 26,665 5,014 5,043 26,272 36,329 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. Balance at January 1, 2022 Vesting of performance share units Warrants exercised Balance at December 31, 2022 Vesting of performance share units Repurchase of shares Warrants exercised Balance at December 31, 2023 DIVIDENDS Thousands of Common Shares Share Capital 828,197 8,050 25,962 862,209 1,557 (11,327) 59,875 912,314 126,696 — 3,500 130,196 — (1,839) 12,315 140,672 During the years ended December 31, 2023 and 2022, the Company paid dividends to shareholders in the amount of $55.6 million and $0 million, respectively. The Company declared dividends per share in the amount of $0.015, $0.025 and $0.02 per quarter beginning in Q2, respectively. The Company’s dividend policy is to pay dividends based on current liquidity exceeding $60 million. NORMAL COURSE ISSUER BID On May 16, 2023, the Company announced that Toronto Stock Exchange approved the notice of intention to commence a normal course issuer bid ("NCIB"). The NCIB allows the Company to purchase up to 44,230,205 common shares (representing approximately 5% of outstanding common shares at May 12, 2023) beginning May 18, 2023 and ending no later than May 17, 2024. Common shares purchased under the NCIB will be cancelled. During the years ended December 31, 2023 and 2022, the Company purchased 11,326,806 and 0 common shares under the NCIB for total consideration of $6.5 million and $0 million, respectively. The surplus between the total consideration and the carrying value of the shares repurchased was recorded against retained earnings. 64 PERFORMANCE AND INVESTORS’ WARRANTS The investor warrants were granted in connection with the brokered private placement offering on June 18, 2020. Investors received one common share and one half of one warrant allowing the subscriber to purchase additional shares until June 18, 2023, at 16 pence/share upon presentation of a full warrant. The warrants were fully exercised on June 18, 2023 and $12.3 million in proceeds was received. The following table sets out a continuity of the warrants: Balance at January 1, 2022 Warrants exercised Balance at December 31, 2022 Warrants exercised Balance at December 31, 2023 SHARE-BASED COMPENSATION Performance Warrants Investor Warrants 22,546,350 (22,546,350) — — — 66,749,005 (6,873,318) 59,875,687 (59,875,687) — The Company has granted performance share units (“PSUs”) to employees and deferred share units (“DSUs”) to directors. The grant date fair value of 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 with 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, environmental, safety and operational milestones. The fair value of the PSUs is determined through a combination of Black-Scholes and probability weighted models. The following table details the terms of the PSUs outstanding at December 31, 2023: Vest date 3 years from grant date, exchangeable for up to 2 shares Vests equally over 3 years from grant date, exchangeable for up to 2 shares Vests equally over 3 years from grant date, exchangeable for up to 1-1.5 shares Total units The following assumptions were used for the Black-Scholes valuation of the PSUs granted: Risk-free interest rate Expected Life Annualized volatility 2023 Plan Share Units 2022 Plan Share Units 4,283,897 520,500 1,987,367 6,791,764 3,169,560 457,728 1,422,331 5,049,619 2023 Plan 2022 Plan 3.8 % 1-3 years 50 % 2.0 % 1-3 years 50 % For the year ended December 31, 2023, the Company recognized $4.4 million of share-based compensation expense in general and administrative expense, capital expenditures and operating expense (December 31, 2022: $4.1 million). The Company issued DSUs to directors of the Company, pursuant to the Company’s DSU plan and has 3,792,494 DSUs outstanding at December 31, 2023. The DSUs are fully vested and are redeemable upon a holder ceasing to be a director of PetroTal. No common shares will be issued under the DSU plan, as they are settled in cash at the prevailing market price and valued at the closing share price on the reporting date. For the year ended December 31, 2023, the Company recognized $0.8 million of DSU expense in general and administrative expense and contributed surplus (December 31, 2022: $1.0 million). 65 The following table details the PSU and DSU activity: Performance Share Units Balance at January 1, 2022 Additions Issued Forfeited Exercised/settled Balance at December 31, 2022 Additions Issued Forfeited Exercised/settled Balance at December 31, 2023 Deferred Share Units 2,962,539 1,073,483 — — (1,384,268) 2,651,754 1,292,000 — — (151,260) 3,792,494 23,583,322 5,165,917 (7,594,067) (1,428,004) — 19,727,168 9,038,663 (7,707,440) (256,471) — 20,801,920 17.REVENUE NET OF ROYALTIES AND SOCIAL FUND The Company’s oil revenue is determined pursuant to the terms of various sales agreements. The transaction price for crude is based on the commodity price in the production month, adjusted for quality, allowable deductions and other factors. Commodity prices are based on market indices. Oil revenue Royalty Social fund (see Note 4) Oil Revenue Net of Royalties and Social Fund 18.GENERAL AND ADMINISTRATIVE EXPENSES Salaries and benefits Legal, audit and consulting fees Community support Office rent and administrative Share-based compensation plans Costs directly attributable to PP&E and operating expenses Total Year Ended December 31 2023 December 31 2022 316,911 (23,389) (7,259) 286,263 359,106 (25,713) (6,278) 327,115 Year Ended December 31 2023 December 31 2022 14,065 9,459 3,100 4,350 4,364 (7,289) 28,049 10,994 4,830 2,372 2,870 4,089 (5,264) 19,891 The Company’s general and administrative expenses were $8.2 million higher in 2023 compared to 2022, due to an increase in salaries and headcount, higher professional fees and Environmental, Social, and Governance (“ESG”) consulting expenses and an increase in share-based compensation, partially offset by costs directly attributable to PP&E and operating expenses. 66 19.FINANCE EXPENSE Bond interest and fees amortization and other interest Factoring costs Lease interest Accretion of decommissioning obligations Interest income Total Year Ended December 31 2023 December 31 2022 16,183 403 1,304 994 (3,543) 15,341 17,085 1,417 2,884 897 (2,114) 20,169 The Company’s finance expenses were $4.8 million lower in 2023 compared to 2022. 20.DIRECT TRANSPORTATION EXPENSE Direct transportation is comprised of diluent, barging, diesel and storage expenses. Diluent costs are required for sales to the Iquitos refinery. Diluent Barging Diesel Dry season freight and storage Total Direct Transportation 21.RELATED PARTY TRANSACTIONS Year Ended December 31 2023 December 31 2022 6,857 3,475 516 4,115 14,963 9,440 6,431 1,083 3,668 20,622 The Company had no related party transactions or off-balance sheet arrangements. The Company’s key management includes the Directors and Officers. Salaries, incentives and short term benefits Director's fees Share-based compensation Total Year Ended December 31 2023 December 31 2022 1,846 1,014 2,430 5,290 1,785 1,050 1,615 4,450 67 22.CAPITAL STRUCTURE The Company’s objective when managing capital is to ensure it has sufficient funds to maintain 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, which may include equity and debt, and adjusts it according to the funds available 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: Equity Working capital (current assets less current liabilities) Total 23.TAXES December 31 2023 December 31 2022 463,942 (121,649) 342,293 399,331 (139,771) 259,560 The Company’s effective tax rate is impacted each quarter by the relative pre-tax income earned by the Company’s operations in Canada, U.S., and Peru. The Company is subject to statutory tax rates of 23% in Canada, 21% in the U.S. and 32% in Peru (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 and local income tax returns in the various jurisdictions. The tax at the effective rate differed from the tax at the statutory rate as follows: Earnings before deferred income taxes Canadian corporate tax rate Expected income tax expense Increase (decrease) in taxes resulting from: Non-deductible expenses and other Tax differential on foreign jurisdictions Change in valuation allowance Provision for income taxes The deferred income tax balances are as follows: Deferred income tax asset: Property, plant, and equipment Trade and other payables Net operating loss carryover Other tax pools Deferred income tax asset Deferred income tax liability: Property, plant, and equipment Derivative assets and liabilities Preoperative expenses Net operating loss carryover Other tax pools Deferred income tax liability December 31, 2023 December 31, 2022 205,917 143,507 23.00 % 33,007 1,408 10,212 (11,625) 33,002 23.00 % 47,361 2,047 19,742 (51,760) 17,390 December 31, 2023 December 31, 2022 7 — 4,119 8,919 13,045 (58,554) (2,372) 2,549 2,156 1,112 (55,109) (11) 254 855 — 1,098 (46,886) (5,643) 3,186 29,985 1,972 (17,386) 68 The Company recognized the net tax amount related to Net Operating Losses (“NOLs”) and deferred tax liabilities in Peru, Canada and the US. As of December 31, 2023, the Company has $7 million in available tax losses in Peru (mainly related to Block 95), $21 million tax losses in Canada and $2 million in the US (December 31, 2022: $112 million, $69 million, and $1.7 million, respectively). The Peruvian non-capital losses are expected to be used in 2024. The Canadian non-capital losses can be carried forward for twenty years and there is generally no carryback period. The carryover period starts with the taxable year following the loss and continues indefinitely. The US non-capital losses can be carried forward indefinitely. The aggregate amount of temporary differences associated with investments in subsidiaries for which deferred tax liabilities have not been recognized as of December 31, 2023 is approximately $29 million (December 31, 2022: $50 million). 24.COMMITMENTS At December 31, 2023, the Company holds the following letters of credit guaranteeing its commitments in exploration block 107: Block 107 107 Beneficiary Perupetro S.A. Perupetro S.A. Amount $1,500 $1,500 $3,000 25. SUBSEQUENT EVENTS Commitment 1st exploration well, minimum work 5th exploratory period 2nd exploration well, minimum work 5th exploratory period Expiration May 2026 May 2026 On February 14, 2024, the Company declared a cash dividend of $0.02 per common share with a record date of February 29, 2024. The dividend was paid on March 15, 2024. 69

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