Slides
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See additional details in the appendix All figures in USD millions “m” unless otherwise stated All production in “bopd” or “mmbbls” unless otherwise stated Investor Presentation May 2025 p e t r o t a l c o r p . c o m InvestorRelations@petrotal-corp.com
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Corporate Summary Introduction to PetroTal PetroT al is a publicly-traded oil and gas company focused on the development of oil assets in Peru. Our flagship property is the Bretaña oil field located in the Marañon Basin of northern Peru. As an invested partner, we’re working to help make Peru socially and economically stronger. TSX : TAL AIM : PTAL OTC : PTALF 2 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n
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Production Financial 3 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 21,000 – 23,000 bopd 2025 guidance 23,225 bopd YTD production1 19,142 bopd Q4 2024 (actual) 17,785 bopd FY 2024 (actual) $0.40/share USD Share Price on May 9, 2025 915M Basic shares $366M Market Cap $6M Net Surplus2,3 1.5x EV/2025 Adjusted EBITDA4 2025 Guidance Up to $60M (16% yield) 2025 dividends and buybacks $275M Net operating income $245M Adjusted EBITDA $200M After tax funds flow $140M Capital expenditure budget 1. Average through April 30. 2025 / 2. As of Q1 2025 / 3. See footnotes and disclaimers for financial definitions. / 4. 2025 Adjusted EBITDA guidance of $245 million.
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PetroTal overview PetroTal operating presence 02 1. Calculated as $645 million remaining booked 2P development costs / 114 mmbbls of 2P reserves 7th year of operation $625m Invested since inception through Q1 2025 26 mmbbls Produced from Bretana since inception $645m Remaining 2P investment 114 mmbbls Remaining 2P reserves $5.66/bbl 1 Remaining booked 2P development costs T exas, USA Peru, South America LimaHouston 4 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Introduction to PetroTal
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Experienced leadership Introduction to PetroTal Executive Leadership T eam Manolo Zúñiga Director, President & Chief Executive Officer • Petroleum engineer with over 30 years of experience helping shape and promote oil investments in Peru • Former CEO of BPZ Energy Camilo McAllister Executive Vice President & Chief Financial Officer • Financial executive with over 30 years of experience in international energy companies • Former CFO of Constellation Offshore and Frontera Energy Jose Contreras Executive Vice President & Chief Operating Officer • Chemical engineer, MSc. Petroleum Engineering and project development with over 25 years of experience in senior operational oil and gas roles • Previously with Equinor/Statoil and ConocoPhillips Sudan I. Maccio Chief Legal Counsel and Corporate Secretary • Legal executive with over 30 years of experience in global energy environments encompassing commercial, M&A, governance and risk matters • Previously General Counsel and Corporate Secretary for Ecopetrol USA 5 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n
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Experienced leadership Introduction to PetroTal Corporate Leadership T eam Guillermo Florez Peru Country Manager • Petroleum engineer with 18 years experience in various commercial and project management roles • Formerly with BPZ Energy Glen Priestley Vice President Finance & Treasurer • 25 years corporate finance experience with US-based upstream and midstream companies • Former VP Finance at Energy XXI Emilio Acin Daneri Vice President Business Development • Senior finance executive with extensive commercial background in Latin America • Formerly with Repsol, CNOOC Max Torres Vice President Exploration • 30 years experience leading exploration projects around the world • Formerly with Ecopetrol, Repsol Raul Farfan Vice President Sustainability • 25 years experience managing external affairs for resource companies throughout Latin America • Previously External Relations Director for Newmont Peru 6 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n
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Jon Harris Non-Executive Director Emily Morris Non-Executive Director Denisse Abudinen Butto Non-Executive Director Gavin Wilson Non-Executive Director Manolo Zúñiga Director, President & Chief Executive Officer Mark McComiskey Non-Executive Director and Chairman Felipe Arbelaez Hoyos Non-Executive Director Eleanor Barker Non-Executive Director 7 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Introduction to PetroTal Corporate governance Board of Directors
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Investment thesis Introduction to PetroTal 8 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n PetroT al is Peru’s largest crude oil producer and has demonstrated a commitment to operational and financial excellence since inception. The Bretaña asset is a high-quality conventional oil field with a history of profitable growth from a small environmental footprint. PetroT al has distributed over $130 million in dividends since Q1 2023, while increasing annual average production by more than 20% per year.
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Investor value proposition Introduction to PetroTal 9 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Positioned to grow Track record of Production and reserve growth Strong return of capital policy Debt free Experienced management team Leadership in ESG principles
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GOVERNMENT STRUCTURE • President: Dina Boluarte • Prime Minister: Gustavo Adrianzen • Energy and Mines Minister: Jorge Montero • Economy and Finance Minister: José Salardi P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n POLITICAL STABILITY • Stable Legal Framework: Supreme decree-governed contracts ensure continuity across regime changes. (Oil and gas concessions are contract law) FAVORABLE FISCAL REGIME • Competitive taxation and royalty structures designed to attract and retain foreign investment OFFSHORE EXPLORATION • Multinational companies interested in exploring Peruvian sea: Occidental and Total Energies Introduction to PetroTal 10 Peruvian landscape
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Operations Introduction to PetroTal P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 11 AMAZON BASIN COLOMBIA ECUADOR PERU BRAZIL BOLIVIA Camisea Peru LNG
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 12 Short-term strategy Securing additionalsales routes Executionof 2P to upgrade P3 well locationsDebt-free balance sheet Returning free cash flow to shareholders Mid-term strategy Optimize cost structure and operating synergies Reach and extend Bretaña plateau while developing other assets Returning free cash flow to shareholders Achieve $2 billion in market capitalization via expansion Materially meet or exceed ESG targets in Bretaña Growth Strategy Bretaña: core asset driving growth
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 13 24% annual growth 2025 production guidance / 2024 actual $3.75/bbl Non-recurring erosion control opex 958 4,131 5,675 8,956 12,200 14,248 17,733 22,000 2023 Production (bopd) 2025E20242022202120202018 2019 +331% +37% +58% +56% +36% 14% +24% +24% 4 Development wells at Bretana and Los Angeles Growth Strategy Consistent production growth >$30.00/bbl Estimated adjusted EBITDA netback1 13% Dividend yield PetroT al Annual Average Production (bopd) (1) Assuming $75.00/bbl average Brent oil price 2025 guidance highlights
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 59% increase Strong Y oY growth in high value PDP reserves 10.3 years Estimated 1P reserve life index $1.7 Billion 2P After tax PV10 valuation of $1.89/share 18 22 22 37 45 48 6720 16 33 41 51 52 47 38 48 51 69 72 99 100 2019 2020 2021 2022 2023 2024 3P 2P 1P 2018 +12% +25% +39% +19% +14% 16% 6% $1,639$1,509$1,020$621 (Covid impacted) $746$3262P After Tax NPV10 (millions) Reserves (mmbbls) $1,720 (includes Block 131) Operational Performance Consistent reserves growth 38 55 78 97 38 100 114 76 85 106 147 168 200 213 14
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3-yr Reserve Replacement Costs (PDP Reserves) Over the past three years, PetroT al’s PDP FD&A costs were $8.01/bbl, all-in. The LATAM peer group replaced reserves at an average of ~$20.00/bbl. PetroT al’s trailing 3-year cumulative EBITDA netback was ~$43.00/bbl, better than the peer group average of ~$40.00/bbl. These numbers drive a trailing 3-year recycle ratio of 5.4x, substantially better than the peer group average of 2.1x. Each barrel of oil PetroTal produces provides the capital to develop 5.4 additional barrels of PDP reserves. $37.94 $31.75 $18.72 $14.72 $12.22 $8.01 1.4x 2.4x 2.9x 5.4x 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 $0 $5 $10 $15 $20 $25 $30 $35 $40 0.3x Peer 1 1.6x Peer 2 $23.72 Peer 3 2.4x Peer 4 Peer 5 Peer 6 PetroTal FD&A Cost Recycle Ratio Better Capital Efficiencies Operational Performance Capital Efficiencies: best in class P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n (1) Peer group includes Canacol, Frontera, GeoPark, Gran Tierra, Parex, Vista Key Highlights 15
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Repeatable conventional oil P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Growth Strategy 16 Vivian reservoir – Massive fluvial sands with excellent reservoir quality OOIP increases to 494 mmbbls (2P) at YE24, compared to 329 mmbbls (2C) at YE17 Analogous fields have recovery factors of 22-42% vs Bretaña at 27% 8 and 14 new wells (2P and 3P , respectively) added to the development plan at YE24 2P and 3P reserves case have 40 and 50 producing wells Expanded inventory drives 2P and 3P future development capital of $645 million and $932 million (from $500/$698 million at YE23) 1x
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Development potential P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Growth Strategy VS1 Unit: for the first time at Bretaña, PetroT al used the 20H well to drill a lateral into the upper Vivian VS1 unit, where a brief production test in August 2024 flowed 320 bopd. Independent estimates allocated ~28% of Bretaña of OOIP at YE24 (659 MMBbl1) to the VS1 unit; nominal volumes were included in 3P reserves, pending additional production testing. PetroT al has been using SLB’s new Geosphere HD reservoir mapping-while-drilling technology to identify fluvial channel sands (VS1 and VS2), improve geosteering, aid in completion design, and refine its reservoir model. 17 (1) Bretana booked 2P OOIP as of YE24
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Core asset production profile P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Growth Strategy 18 > 10,000 bopd Full reserve life, in 3P case 40,000 bopd Possible peak production 20,000-25,000 bopd Ability to flatten peak production, into multi-year production profile0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 1P Probable Possible Netherland Sewell (NSAI) Production Profile (bopd) (1) Possible case assumes contract extension to 2051; of the 99 mmbl included in Possible reserves at YE24, approximately 43 mmbbl are produced beyond the expiration of the current license contract in 2041. Contract Expiry: 2041
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 19 Key highlights 6,500 bopd Average max IP flow rate 2,627 bopd Average IP365 flow rate 1.6 mmbbls Produced in first 36 months $14.6 million Average horizontal well cost 3 months Average well payout1 Max daily rate (bopd) 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 0 1,000,000 2,000,000 BN-1 7D 9H13H 12H 14H 15H 16H 17H 20H 19H Scale = 1.0x Payback > 3.0x Payback 1.0x - 3.0x Payback < 1.0x Payback & less than 6 months producing Cumulative oil produced (bbl) Max oil rate vs cumulative oil (inception through March 31, 2025) 6H 1XD 2XD 10H 11H 8H 5H 4H 3D 22H21H 17H Growth Strategy Outstanding returns on investment (1) Based on estimated operating netback at $75.00 Brent oil price 23H 18H
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Long-range well drilling P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Growth Strategy 20 AICD technology Less water intrusion via Automated Inflow Control Devices (AICDs) $11 to $16M Wells costs range, depending on lateral length 40-50 days Time to drill and complete new wells 15,028 acres Field size 18.6 degrees API 25scf/bbl GOR
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 23 Key highlights Expanding capacity Installed oil processing capacity of 32,000 bopd and water disposal of 170,000 bwpd by YE25 Facility optionality Capacity expansions allow for alternate paces of 2P development, improved uptime 21 Oil and Water Capacity Growth (‘000 bopd) 8 16 16 24 24 24 32 0 20 40 60 80 100 120 140 160 180 0 5 10 15 20 25 30 35 40 2018 2019 2020 2021 2022 2023 2024 2025E 24 Water Disposal Capacity Oil Production Capacity Growth Strategy Infrastructure expansion Well cellars PetroT al is seeking regulatory to construct ten new drilling cellars, which will support growth over the next two years
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 23 Manageable cost allocation Total Project Costs Approximately $65-75 million, spread over the 2024-2026 period. Of this total, PetroT al plans to allocate ~60- 65% to operating expense. 2025 Budget PetroT al has budgeted $35-40 million for erosion control in 2025. Of this amount, approximately 75% will be allocated to operating expense. 22 Estimated Erosion Control Project Cost Allocation within Opex and CapexErosion control 2026 & Beyond1 After expensing $10 million of erosion control as opex in Q4 2024, approximately $15-20 millon of project expenditures will carry into 2026, before wrapping up in Q2 2026. 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Q4 2024 Q1 2025 Q2 2025 Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026 Q4 2026 Erosion Opex Recurring Opex 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Q4 2024 Q1 2025 Q2 2025 Q3 2025 Q4 2025 Q1 2026 Q2 2026 Q3 2026 Q4 2026 Erosion Capex Development Capex Infrastructure Investments (1) 2026 budget remains subject to Board approval
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 23 Bretana: Present Infrastructure Investments Erosion control Breakwater 1 Breakwater 2 Breakwater 3 Breakwater 4 Breakwater 5 Erosion Control Impacted Area Bretana: The Solution
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 24 Infrastructure Investments Erosion control Illustrative Construction Activity: La Pastora, Peru (2015)
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Peru’s Marañon Basin has been underexplored for hydrocarbons PetroT al aims to repeat Bretaña success in other Peruvian assets Multiple prospects and leads from existing portfolio Blocks 95, 107 and 131 Growth opportunities P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Growing PetroTal 25
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Block 95 Expansion 26 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Expansion beyond Bretaña at Block 95 Bretaña Field Zapote Iberia Tapiche South Lead E 5% - 20% royalty ~7.5% at 20,000 bopd plus 2.5% social fund Fiscal Terms License contract until 2041 Key highlights Drilling potential PetroT al is considering an accelerated exploration strategy with a view to de-risking one or two of these prospects in 2026 N 120k $10-$12/bbl T otal F&D costs if deemed commercial Existing seismic Four exploration prospects have been identified on legacy 2D seismic $25-$30M in 2026 (possible drilling)
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Block 107 Expansion 27 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Exploration Potential Block 107 is a prospect ready area with road access Exploration commitment to drill two exploration wells extended to February 2027 PetroT al will seek a farmout partner Gran Tierra retains 20% back in option Fiscal Terms Key highlights 534 mmbbls Mean estimate unrisked prospective resource over an area of 262,000 hectares Subsurface Reinterpreted seismic shows two main structural prospects Updated technical De-risked with new 3D Geologic Model supporting Cretaceous reservoirs with oil or gas charge from high quality Permian source rocks Dry hole NPV neutral T ax synergies with Bretaña Osheki Prospect Unrisked mean / best estimate 534 / 275 mmbbls prospective resource
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Block 131 Expansion P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Key highlights Los Angeles Field 28 Acquisition closed in November 2024, for minimal net cash outlay from PetroT al Current production is approximately 700 bopd of 40º API oil Low risk conventional light oil reservoir in the Cushabatay sand Four-way closure composed of fluvial channels of uniform thickness, good porosity / permeability and clear OWC PetroT al plans to spud its first development well at Los Angeles by mid-2025
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Block 131 cont. 29 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Development opportunities 5,500 bopd Current oil handling capacity Bypassed oil Horizontal well locations high on structure Voidage optimization Lower opex with less chemical Blending synergies At the Iquitos refinery Continued growth in Peru Upside potential Deeper potential exists in the Copacabana zone which was previously tested for oil Tax synergies Future tax synergies with Bretaña may become available 23.5% royalty rate Potential to renegotiate License contract until 2037 Fiscal Terms Included infrastructure: • Oil treatment plant • Water treatment plant • Water injection plant Expansion
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Block 131 cont. 30 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Los Angeles field historical production 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 7/1/2014 1/1/2015 7/1/2015 1/1/2016 7/1/2016 7/1/2020 7/1/2021 1/1/2020 1/1/2022 7/1/2019 7/1/2022 1/1/2021 1/1/2023 1/1/2019 7/1/2023 7/1/2018 1/1/2024 1/1/2018 7/1/2024 7/1/2017 1/1/2025 1/1/2017 0 1 1/1/2014 3 4 5 6 7 8 2 Oil Rate (bopd) Cuml. Oil (mmbbl) Expansion
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TEA Blocks XCVII & XCVIII Expansion 31 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Expanding footprint in Ucayali Basin Low-cost land acquisition PetroT al secured TEA’s XCVII and XCVIII for no up front capital commitments. The blocks essentially reconstitute the historical boundaries of present-day Block 131, including acreage that had been relinquished by previous operators. The TEA contracts grant PetroT al a right of first refusal to convert the acreage to a license contract. Key highlights Basic work commitments Work commitments largely include geological and geophysical studies, with total expenditures of approximately $100k. UC-XP-004 UC-XCVII NE SHUY A 1X TAHUAYA 1X S. ALE JANDR O 1 X CHIO 1X A. CALIE NTE 1 X TIRUNTAN 1 X AGUA CALIENTE FIELD AGUAYTIA FIELD UC-XCVIII PROSPECT LEADS FIELD LOS ANGELES FIELD PISQUI 1X Numerous exploration leads identified Both blocks have good legacy seismic coverage, and numerous exploration leads have already been identified on trend with producing oil fields in the area.
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2025 financial and operational performance Performance P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Key highlights ● Drill and complete four new development wells in 2025 ● T arget production growth of 24% on 2024 ● Expansion of oil processing capacity to 32,000 bopd ● Investing $140 million in total Capex ● Advance exploration programs in Blocks 95, 107 and 131 ● Return majority of free cash flow to shareholders through ongoing dividend and share buyback programs
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Summary (USD) Production (bopd) CAPEX (USD) $240 – 250M Adjusted EBITDA Guidance1 $103M Q1 2025 available cash $40M Estimated 2025 cash tax 21,000 – 23,000 2025 guidance 331) Net of approximately $30 million in Erosion Project opex, 2) Includes $8 million capitalized for erosion control P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n $60M Estimated free cash flow, supporting 13% dividend yield and share buybacks 23,280 Q1 2025 (actual) 22,000 Q2 2025 (estimate) 20,000 Q3 2025 (estimate) 24,500 Q4 2025 (estimate) $140M2 2025 guidance $24M Q1 2025 (estimate) $40M Q2 2025 (estimate) $35M Q3 2025 (estimate) $40M Q4 2025 (estimate)
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Production (bopd) Brent ($/bbl) Recurring net operating income Erosion control (opex portion) G&A EBITDA(2) Capex Accrued tax and finance expense(3) After tax free funds flow Cash Dividends Post-Dividend Cash Build/(Draw) 34 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n (1) Includes $11.5 million in mandatory profit sharing for Peru office, and non- cash equity compensation (2) See footnotes and non Gaap definitions (3) Amount reflects estimated accrued taxes. Cash tax is approximately $40 million in 2024 Summary in USD millions 2025 (Jan 2025 guidance) 21,000 – 23,000 $75.00 $305 ($30) ($30)(1) $245 ($140) ($45) $60 ($55) $5 2025 guidance summary
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Dividend overview P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Performance 35 Dividends: $130 million paid ($0.155/share) Returned through June 15, 2025 • Pay a quarterly $0.015/share base dividend with top up optionality • Liquidity is cash available at dividend approval date, adjusted by portions of unused credit capacity and or future capital/working capital needs 130 0 10 20 30 40 50 60 70 80 90 100 110 120 130 0.000 0.005 0.010 0.015 0.020 0.025 Dividend/share (USD) Cuml. dividends ( USDmm) 0.015 Q2 2023 0.010 0.015 Q3 2023 0.005 0.015 Q4 2023 0.005 0.015 Q1 2024 0.015 Q2 2024 0.015 Q3 2024 0.015 Q4 2024 0.015 Q1 2025 0.015 Q2 2025 Cuml. Dividend (USD mm) Top Up ($/share) Base Dividend ($/share)
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Share buyback overview P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Performance 36 Buybacks: $9 million in shares purchased Through March 30, 2025 • Buyback approximately 10% of the Company's public float subject to volume and liquidity constraints • T arget up to $3.0 million in buybacks per quarter 3.08 2.57 0.58 0.36 2.65 2.06 0.65 0.62 0.38 0.53 9.4 0 1 2 3 4 5 6 7 8 9 10 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 5.5 6.0 Shares repurchased (millions) Cuml. buybacks (USD mm) 0.28 0.30 Q2 2023 2.95 Q3 2023 Q4 2023 Q1 2024 Q2 2024 Q3 2024 Q4 2024 0.58 5.60 5.14 5.17 1.23 0.98 0.44 Q1 2025 1.12 2.60 Cuml. Buybacks (USDmm) AIM TSX
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Risk Management: production hedges P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Financial Performance PetroT al has been actively hedging 2025 production when Brent oil prices have topped $80.00/bbl As of the end of Q1 2025, PetroT al has hedged approximately 40% of production volumes through YE25 Hedges have a floor price of $65.00/bbl and a weighted average ceiling of $82.50/bbl (uncapped above $102.50/bbl) As of April 30, 2025, the hedges had a mark-to-market value of ~$9.2 million 44% 38% 34% 56% 62% 66% Q2 2025 Q3 2025 Q4 2025 100% PetroTal Hedged Production Volumes (2025E) % of Quarterly Production Unhedged Hedged 37
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2025 free cash flow profile P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Performance 38 Key assumptions: • Full-year production and pricing assumed • Base G&A: Approximately $30 million annually • Fully burdened with Erosion Control opex and capex of $35-40 million • Cash tax: Estimated at $40 million • Free cash flow numbers are net of working capital adjustments of ~$20-25 million, interest income (~$2 million) and lease expense (~$12 million) • Annual base dividend and buyback funding obligations are ~$55 million and ~$2 million, respectively • Capex flexibility: Up to $30 million can be deferred in certain scenarios Annual free cash flow, prior to dividends and buybacks Production (bopd) vs. Brent oil price ($/Bbl) $85 $80 $75 $70 $65 20,500 $95 $67 $41 $14 ($13) 21,500 $115 $85 $57 $30 $0 22,000 $124 $94 $66 $37 $8 22,500 $134 $103 $74 $44 $15 23,000 $144 $112 $82 $52 $22 21,000 $105 $76 $49 $22 ($6)
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P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 41 Key Objectives Alignment with community Resource sharing mechanism accelerating the process for benefits Fewer operational disruptions, quicker resolutions, and safer work environments Management of the social trust by the trust administration committee 39 ESG overview
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PetroTal created social trust ESG Overview P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 34 2.5% Of fiscalized production ~$24 million Contributions to date1 Trust administration committee (In region, comprised of community members) 1. Inception to March 30, 2025 Promoting savings for a sustainable fund 2.5% 40
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Relevant ESG initiatives ESG Overview P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Commitment through policies, projects and programs that have made PetroTal an ESG leader in the Peruvian energy sector ESG leadership in Perú 41 Solar project aimed at electrifying the Bretaña community with over 3,500 people Training programs for local women to operate and manage an ice plant to ensure cold fish shipping, resulting in a 15% price increase Communitarian enterprise programs that benefit agri/aquaculture and small animal farming Endangered species protection programs for the Taricava (Amazonian Turtle) Forest restoration initiatives that have restored over seven acres in the 7 de Junio community Fishing innovation program benefiting ~350 families and resulting in improved product pricing
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Appendix P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n
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Robust type curve profile Performance P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n Time Normalized Well Performance (Horizontal Well Portfolio + 7D) 44 Notes Actual portfolio average horizontal data would indicate over performance of NSAI 2P type curve. Horizontal portfolio has recycled back its investment 3.7x in ~12 months of normalized production time Technical team to forecast production using near 2P performance with additional risks applied Robust economics and payout ratios at current Brent levels to justify continued development of 2P/3P booked locations 250 20 3515 33510 3405 30 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 5,500 6,000 ~2.4 mmbbls Normalized 3 Year Profile v ~1.7 mmbbls ~68m cuml. NOI
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Horizontal (based on actual data) 4,900 bopd IP 90 P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 45 Estimated 2P Avg (NSAI) Deviated (based on actual data) 3,400 bopd IP 180 2,600 bopd IP 365 $11 - $15M Capex $4,200 Capital intensity (180 days) 60-70 days Payout ($80 Brent) 3,830 bopd IP 90 3,000 bopd IP 180 2,290 bopd IP 365 4.5 mmbbls EUR $14M Capex $4,667 Capital intensity (180 days) 170 days Payout ($80 Brent) >5x Profit to investment ratio 2,019 bopd IP 90 1,652 bopd IP 180 1,300 bopd IP 365 $8 - $10m Capex $5,400 Capital intensity (180 days) 60 - 70 days Payout ($80 Brent)
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Analyst coverage and relative target valuation Performance P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 46 Key Highlights • Trading just over blowdown valuation (PDP valuation NPV10/share) per the Dec 31, 2024 year ended NSAI reserve report • New investors can acquire shares at a significant discount to 1P reserves per share 0.49 0.89 1.24 1.89 3.02 Current Price 1P 2P 3PPDP 1.600 1.270 1.040 TAL valuation and analyst target summary (USD/share) 1.30 Auctus Stifel Peel Hunt US$/Sh
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Peer trading multiples Performance P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 47 Key Highlights Company will deliver: • T op quartile production and cash flow per share growth • A 10% to 15% dividend yield and complimentary share buyback program • Exploration and development upside • Organic and inorganic production and cash flow diversification • Additional oil evacuation routes to reduce dry season volatility and accommodate expansion Relative EV/EBITDA multiples below peer average • Peer group includes: Afentra PLC, Africa Oil, Arrow Exploration, Canacol Energy, Capricorn Energy, Geopark, Gran Tierra Energy, Jadestone Energy, Parex Resources, Tullow Oil, Vaalco Energy, Valeura Energy, Vista Energy • Source: Factset, as of May 9, 2025 Notes 3.6 3.2 2.5 2.4 2.1 1.9 1.9 1.8 1.6 1.6 1.5 1.4 1.1 0.8 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 PetroTal Peer 11 Peer 12 Peer 13 1.9x
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Peer comparables growth + yield Performance P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 48 Key Highlight • PetroT al is one of the few small-cap E&P companies with an ability to deliver consistent production growth and a stable dividend Production per share growth plus dividends Notes 76% 38% 34% 22% 17% 11% 3% 2% 1% 0% -4% -20% -10% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% Peer 1 PetroTal Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9Peer 3 • Peer group includes: Africa Oil, Arrow Exploration, Berry Corp, Canacol Energy, Geopark, International Petroleum, Jadestone Energy, Parex Resources, Ring Energy, Tullow Oil, Vaalco Energy • Source: Factset, as of February 14, 2025 Peer 10 Peer 11 -5%
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Footnotes Appendix cont. P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 49 Slide 3 1. Market capitalization as of February 14, 2025 2. Net Surplus is Q3 2024 actual 3. See disclaimers – Non Gaap financial measures Slide 4 1. NSAI Reserves statement effective date December 31, 2024 2. Amount invested refers to Capex Slide 14 1. Per the NSAI Reserves statement effective date 31 December 2024 2. AICD – Autonomous Inflow Control Devices 3. Analogous fields are other heavy oil fields near Block 95 Slide 16 1. Historical reserve replacement ratios are not guaranteed to continue in the future 2. Recovery factors of 26% and 34% are calculated as EUR / original oil in place. (2P = 131 mmbbls / 494 mmbbls) (3P = 229 mmbbls / 658 mmbbls) Slide 17 1. Per the NSAI Reserves statement effective date 31 December 2024 2. Production profile reflects NSAI’s rollup. Management may elect to develop and or pace the asset differently. The production profile should not be interpreted to be the Company’s yearly budget. Slide 18 1. Based on actual company data 2. Payback on each well uses average netback assumptions Slide 20 1. Water disposal capacities are estimated 2. Construction of additional well cellars is subject to regulatory approval Slide 21 1. Erosion control allocations and estimates are subject to change Slide 25 1. Development plans for Block 131, 95 and 107 are all subject to approval by the board of directors and subject to changes and or other approvals by Perupertro and Petroperu Slides 27 1. Locations and costs are estimated based on internal technical assumptions and are subject to changes Slide 42 1. First 30 months of type curve based on Company actual data. Remaining type curve depicts an estimated 2P well with 4.5 mmbbls of recoverable oil
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Disclaimers P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n
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Disclaimer Reader advisories P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 51 FORWARD -LOOKING STATEMENTS : This presentation contains certain statements that may be deemed to be forward-looking statements. Such statements relate to possible future events. 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 presentation contains forward-looking statements pertaining to: PetroTal’s intention to continue to develop the Bretana asset; the targeted 24% production growth rate from 2024; PetroTal’s forecast 2025 funds flow; future tax synergies between the Bretana asset and Block 131; PetroTal’s intentions to conduct exploration drilling at Block 95 in 2026; PetroTal’s intentions to continue seeking a partner for co- investment for Block 107 and obtain development permits; the positioning of the Company in 2025; PetroTal’s intentions with respect to its return of capital program (including that the program will continue to consist of dividends at $0.015/share and target buybacks up to $1.0 million/quarter in accordance with the Company’s return of capital policy); PetroTal’s plans to commercialize new sales routes through the OCP in Ecuador and through Yurimaguas to Bayovar and the anticipated benefits therefrom (including in respect of production estimates) and the timing thereof; PetroTal's expectations with respect to projects and key initiatives to be financed with contributions from the Social Trust Fund; estimated returns from the Company’s 2025 dividend and buyback plan; drilling plans including with respect to the commencement and completion of drilling wells; estimated payback from wells and the timing thereof; PetroTal’s plans to continue to allocate capital to its long term preventative erosion control program; PetroTal’s 2025 budget for the erosion control project and plans in respect thereof; the 2025 Capex budget; and PetroTal’s expectations regarding 2025 operating costs. 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 management's current belief, based on currently available information, as to the outcome and timing of future events. 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 services. PetroTal cautions that forward-looking statements relating to PetroTal are subject to all of the risks, uncertainties and other factors, which may cause the actual results, performance, capital expenditures or achievements of the Company to differ materially from anticipated future results, performance, capital expenditures or achievement
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Disclaimer Reader advisories P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 52 expressed or implied by such forward-looking statements. Factors that could cause actual results to differ materially from those set forth in the forward-looking statements 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), business performance, legal and legislative developments including changes in tax laws and 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, credit ratings and risks, fluctuations in interest rates and currency values, changes in the financial landscape both domestically and abroad, including volatility in the stock market and financial system, wars (including Russia's war in Ukraine and the Israeli-Hamas conflict), regulatory developments, 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; changes in the financial landscape both domestically and abroad (including volatility in the stock market and financial system) and the occurrence of weather-related and other natural catastrophes. Readers are cautioned that the foregoing list of factors is not exhaustive. Please refer to the risk factors identified in the Company's most recent annual information form and management’s discussion and analysis (the “MD&A”) which which can be accessed either on PetroTal's website at www.petrotal-corp.com or 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. Forward looking CAPEX and OPEX assumptions in this presentation are consistent with the NSAI Reserve Report as of Dec 31, 2023 and current historical operating results to date, however, the timing and pace of the development plan has been adjusted from the NSAI Report to align with management's internal view on commodity price and liquidity. Management may create and post alternative development cases at their discretion and label them internal. FOFI DISCLOSURE : This presentation contains future-oriented financial information and financial outlook information (collectively, "FOFI") about PetroTal's prospective results of operations, and production results, 2024 drilling program and budget, well investment payback, cash position, liquidity and components thereof, all of which are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraphs. FOFI contained in this presentation was approved by management as of the date of this presentation 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 presentation, 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 presentation should not be used for purposes other than for which it is disclosed herein. All FOFI contained in this presentation complies with the requirements of Canadian securities legislation, including NI 51-101.
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Disclaimer Reader advisories P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 53 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. SPECIFIED FINANCIAL MEASURES, OIL AND GAS METRICS AND OTHER KEY PERFORMANCE INDICATORS : This presentation includes various specified financial measures, including non-GAAP financial measures, non-GAAP financial ratios and capital management measures such as “Netback”, “EBITDA”, “Adjusted EBITDA”, “Net Operating Income” and “free funds flow”. 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. In addition, this presentation contains metrics commonly used in the oil and natural gas industry and other key performance indicators, financial and non-financial, that do not have standardized meanings under the applicable securities legislation. 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. “Netback” (non-GAAP financial measure) equals total petroleum sales less quality discount, lifting costs, transportation costs and royalty payments calculated on a bbl basis. The Company considers netbacks to be a key measure as they demonstrate Company’s profitability relative to current commodity prices. “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 EBITDA as a measure of operational performance and cash flow generating capability. EBITDA impacts the level and extent of funding for capital projects investments. “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. “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. “NPV-10” or similar expressions represents the net present value (net of capex) of net income discounted at 10%, with net income reflecting the indicated oil, liquids and natural gas prices and IP rate, less internal estimates of operating costs and royalties. “Enterprise value” is calculated as the market capitalization of the Company plus net debt, where market capitalization is defined as the total number of shares outstanding multiplied by the price per share at a given point in time. “CAPEX” means capital expenditures. “IP” means the initial production from a well for a set unit of time. “Capital efficiency” is CAPEX divided by production rate (bopd). “EUR” means estimated ultimate.
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Disclaimer Reader advisories P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 54 recovery, an approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well. EUR is not a defined term within the COGE Handbook and therefore any reference to EUR in this presentation is not deemed to be reported under the requirements of NI 51- 101. Readers are cautioned that there is no certainty that the Company will ultimately recover the estimated quantity of oil or gas from such reserves or wells. “F&D” means finding and development costs, calculated as the sum of capital expenditures incurred in the period and the change in FDC required to develop reserves. “Free cash” or “free funds flow” defined as Adjusted EBITDA before minus CAPEX. “Yield” means free funds flow per year as a percentage of market capitalization. Please refer to the MD&A for additional information relating to specified financial measures. RESOURCES DISCLOSURE . The prospective resource estimates contained herein were derived from a resource assessment and evaluation prepared by NSAI, a qualified independent reserves evaluator, with an effective date of June 30, 2020 (the “NSAI Resources Report”). The NSAI Resources Report has been prepared in accordance with definitions, standards and procedures contained in NI 51-101 and the COGE Handbook. 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. All of the prospective resources have been classified as light oil with a gravity of 46 degrees API. There is uncertainty that it will be commercially viable to produce any portion of the resources in the event that it is discovered. “Unrisked Prospective Resources” are 100% of the volumes estimated to be recoverable from the field in the event that it is discovered and developed. NSAI has determined that a 16% chance of discovery is appropriate for the prospective resources based on an assessment of a number of criteria. The estimates of prospective resources provided in this presentation are estimates only and there is no guarantee that the estimated prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources evaluated. Not only are such prospective resources estimates based on that information which is currently available, but such estimates are also subject to uncertainties inherent in the application of judgmental factors in interpreting such information. Prospective resources should not be confused with those quantities that are associated with contingent resources or reserves due to the additional risks involved. Because of the uncertainty of commerciality and the lack of sufficient exploration drilling, the prospective resources estimated herein cannot be classified as contingent resources or reserves. The quantities that might actually be recovered, should they be discovered and developed, may differ significantly from the estimates herein. The prospective resources estimates that are referred to herein are risked Oil and Gas Advisories RESERVES DISCLOSURE . The reserve estimates contained herein were derived from a reserves assessment and evaluation prepared by Netherland Sewell & Associates, Inc. (“NSAI”), a qualified independent reserves evaluator, with an effective date of December 31, 2023 (the “NSAI Reserves Report”). The NSAI Reserves Report has been prepared in accordance with definitions, standards and procedures contained in NI 51-101 and the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”). The reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Volumes of reserves have been presented based on a company interest. Readers should give attention to the estimates of individual classes of reserves and appreciate the differing probabilities of recovery associated with each category as explained herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation.
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Disclaimer P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 55 there is at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate. MEAN ESTIMATE. Represents the arithmetic average of the expected recoverable volume. It is the most accurate single point representation of the volume distribution. BOE DISCLOSURE . The term barrels of oil equivalent (“BOE”) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. OIL REFERENCES : All references to "oil" or "crude oil" production, revenue or sales in this press release mean "heavy crude oil" as defined in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51- 101”). All references to “light oil” production, revenue or sales mean “light crude oil” as defined in NI 51-101. Brent refers to Intercontinental Exchange “ICE” Brent. ANALOGOUS INFORMATION . Certain information in this document may constitute "analogous information" as defined in NI 51-101, including, but not limited to, information relating to areas, wells and/or operations that are in geographical proximity to or on-trend with lands held by PetroTal and production information related to wells that are believed to be on trend with PetroTal's properties. Such information has been obtained from government sources, regulatory agencies or other industry participants. Management of PetroTal believes the information may be relevant to help define the reservoir characteristics in which PetroTal may hold an interest and such information has been presented to help demonstrate the basis for PetroTal's business plans and strategies. Oil and Gas Advisories as to chance of discovery. Risks that could impact the chance of discovery include, without limitation, geological uncertainty, political and social issues, and availability of capital. In general, the significant factors that may change the prospective resources estimates include further delineation drilling, which could change the estimates either positively or negatively, future technology improvements, which would positively affect the estimates, and additional processing capacity that could affect the volumes recoverable or type of production. Additional facility design work, development plans, reservoir studies and delineation drilling is expected to be completed by PetroTal in accordance with its long-term resource development plan. RESERVE CATEGORIES . Reserves are classified according to the degree of certainty associated with the estimates. Proved reserves (1P) 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 (2P) are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible reserves (3P) are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. RESOURCE CATEGORIES. Prospective resources are classified according to the degree of certainty associated with the estimates. The following classification of prospective resources used in the presentation: Low Estimate (or 1C) means there is at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate. Best Estimate (or 2C) means there is at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. High Estimate (or 3C) means
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Disclaimer P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 56 achieving more production history on older wells or more recent completion information on newer wells. OOIP DISCLOSURE . The term original-oil-in-place (“OOIP”) is equivalent to total petroleum initially-in-place (“TPIIP”). TPIIP, as defined in the COGE Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the estimated volumes of TPIIP will never be recovered. US DISCLAIMER. This presentation is not an offer of the securities for sale in the United States. The securities have not been registered under the U.S. Securities Act of 1933, as amended, and may not be offered or sold in the United States absent registration or an exemption from registration. This presentation shall not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the securities in any state in which such offer, solicitation or sale would be unlawful. All figures in US dollars unless otherwise denoted. Oil and Gas Advisories However, PetroTal has no way of verifying the accuracy of such information. There is no certainty that the results of the analogous information or inferred thereby will be achieved by PetroTal and such information should not be construed as an estimate of future production levels. Such information is also not an estimate of the reserves or resources attributable to lands held or to be held by PetroTal and there is no certainty that the reservoir data and economics information for the lands held or to be held by PetroTal will be similar to the information presented herein. The reader is cautioned that the data relied upon by PetroTal may be in error and/or may not be analogous to such lands to be held by PetroTal. SHORT TERM RESULTS: References in this presentation to peak rates, initial production rates, current production rates, initial 14-day production rates, IP 90, IP 180, IP 365, test rates, flow rates, initial and/or final raw test or production rates, early production, test volumes and/or "flush" 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. Such rates may also include recovered "load" fluids used in well completion stimulation. 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. TYPE CURVES. Certain type curves disclosure presented herein represent estimates of the production decline and ultimate volumes expected to be recovered from wells over the life of the well. The type curves represent what management thinks an average well will achieve. Individual wells may be higher or lower but over a larger number of wells, management expects the average to come out to the type curve. Over time type curves can and will change based on
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Disclaimer P e t r o T a l C o r p . I n v e s t o r P r e s e n t a t i o n 57 Free Funds/ Cash Flow Adjusted EBITDA less CAPEX or as defined in footnotes FFO Funds flow from operations Adj. EBITDA Earnings before interest, taxes, depreciation, amortization, and after realized derivative adjustments; EBITDA is Adj. EBITDA prior to derivative impacts 3P Proved + Probable + Possible Reserves Adjusted free funds flow Free funds flow adjusted by changes in non cash working capital Normalized EBITDA EBITDA excluding material one time non- recurring expenses Ha Hectares PDP Proved Developed Producing Reserves Abbreviations Bbl Barrel Bopd Barrel of oil per day k bopd / Thousand barrel of oil per day F&D Finding and development cost NIBD Net interest-bearing debt Mmbbl Million barrels of oil NGL Natural gas liquids Bbo Billion barrels of oil API an indication of the specific gravity of crude oil measured on the American Petroleum Institute gravity scale. Liquid petroleum with a specified gravity of 28° API or higher is generally referred to as light crude oil 1P Proved Reserves 2P Proved + Probable Reserves 3P Proved + Probable + Possible Reserves Net surplus 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. .