PetroTal Corp. — Management Reports 2025

Mar 20, 2025

MANAGEMENT'S DISCUSSION AND ANALYSIS

For the years ended December 31, 2024 and 2023

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TABLE OF CONTENTS

1.	Corporate overview	4
2.	Overview and selected information	5
3.	2024 highlights	6
4.	Asset acquisition	7
5.	Outlook and growth strategy	8
6.	Selected financial information	11
7.	2024 Reserve report	25
8.	Significant judgements and estimates	27
9.	New accounting standards issued but not effective	29
10.	Related party transactions	30
11.	Taxes	30
12.	Contractual obligations and commitments	32
13.	Forward-looking statements and business risks	32

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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, 2024 and 2023, is dated March 18, 2025, and should be read in conjunction with the Company’s audited Consolidated Financial Statements (the “Financial Statements”) and the Company's Annual Information Form ("AIF") for the years ended December 31, 2024 and 2023. The audited Financial Statements were prepared by management in accordance with International Financial Reporting Standards (“IFRS®”) issued by the International Accounting Standards Board (“IASB”), 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 subsidiaries in Peru, the Company is currently engaged in the ongoing development of hydrocarbons at Block 95 and Block 131. PetroTal also has exploration prospects and leads in Block 107.

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The Bretana oil field is located within Block 95 in the Maranon Basin of northern Peru. To date, this basin has produced more than one billion barrels ("bbls.") of oil. Approximately 70% of the oil in the Maranon Basin has been produced from the Vivian formation, which is known as a high-quality oil reservoir characterized by high permeability and strong aquifer support. Generally, this type of reservoir achieves the highest oil recoveries. The Bretana field, which produces from the Vivian formation, is currently the largest producing oil field in Peru. PetroTal holds a 100% working interest in Block 95 and the Bretana field; as of year-end 2024, Bretana's Proved plus Probable oil reserves were independently assessed at 107.9 million bbls.

In 2024, PetroTal closed the acquisition of a 100% working interest in Peru's Block 131, which contains the producing Los Angeles field. Block 131 is located in the Ucayali Basin of central Peru, where the most notable hydrocarbon discovery is the Camisea gas field. The Camisea project, which came onstream in 2004, mainly produces natural gas feedstock for the Peru LNG export facility. However, the Ucayali Basin also contains a number of small, light oil fields which have been producing since the mid-1900's. The Los Angeles field, which was discovered in 2013, produced an average of approximately 800 barrels of oil per day ("bopd.") of light oil in 2024; as of year-end 2024, the field's Proved plus Probable oil reserves were independently assessed at 5.8 million bbls. In December 2024, PetroTal signed two Technical Evaluation Agreements surrounding Block 131, where a number of light oil exploration leads and prospects have already been identified by previous operators. The Company is currently conducting geological and geophysical evaluation of the acreage, with a view to advancing exploration activities in the coming years.

2.OVERVIEW AND SELECTED INFORMATION

The following table summarizes key financial and operating highlights associated with the Company’s performance for the periods ended December 31, 2024 and December 31, 2023, along with 2024 quarters.

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RESULTS AT A GLANCE

	Year Ended Three Months Ended
	2024 2023 December 31, 2024 September 30, 2024 June 30, 2024 March 31, 2024
Financial Oil revenue Royalties(1) Net operating income(2) Erosion expense Commodity price derivatives (gain) loss Net income Basic earnings per share ($/share) Capital expenditures	$373,940 $316,911 $91,421 $78,850 $103,086 $100,583 ($39,947) ($30,648) ($13,022) ($7,433) ($9,991) ($9,500) $274,325 $238,854 $57,458 $57,233 $80,025 $79,610 $10,117 — $9,569 $548 — — $10,424 $12,479 ($2,726) $21,481 $3,306 ($11,638) $111,450 $110,505 $21,242 $7,179 $35,405 $47,619 $0.12 $0.12 $0.02 $0.01 $0.04 $0.05 $162,827 $108,453 $50,589 $43,019 $38,867 $30,352
Operating Average production (bopd.) Average sales (bopd.) Average Brent price ($/bbl.)(3) Contracted sales price ($/ bbl.) Netback ($/bbl.)(2) Free funds flow(4)	17,785 14,248 19,142 15,203 18,290 18,518 17,558 14,421 19,087 14,760 18,050 18,347 78.98 81.53 73.42 77.74 83.87 81.01 79.15 80.54 73.16 78.58 83.92 81.14 42.68 45.39 32.71 41.74 48.72 47.68 $74,145 $107,192 ($10,422) $6,537 $36,334 $41,696
Balance Sheet Cash and restricted cash Working capital Total assets Current liabilities Equity	$114,528 $111,299 $114,528 $133,072 $95,859 $85,151 $90,989 $119,299 $90,989 $124,439 $144,133 $136,472 $810,467 $658,286 $810,467 $746,131 $720,700 $700,360 $135,172 $83,883 $135,172 $112,665 $93,283 $95,572 $511,508 $463,942 $511,508 $503,756 $509,921 $488,917

(1) Royalties include 2.5% community social trust initiative.

(2) Net operating income ("NOI") and Netback represent revenues less royalties, operating expenses (excludes erosion expense) and direct transportation. (3) bbl. = barrel

(4) Free funds flow 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.

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3. 2024 HIGHLIGHTS

The Company reached several key operational and financial achievements as described below:

Q4 2024 Highlights

• Oil production of 1.8 million bbls., an average of 19,142 bopd, an increase of 26% from 15,203 bopd. in Q3 2024, and a 29% increase from 14,865 bopd. in Q4 2023. At December 31, 2024, the Company has 25 producing oil wells and 4 water disposal wells;

• Oil sales allocations were 89.2% as exports through Brazil, 9.7% to the Iquitos refinery, and 1.1% from Ucawa;

• PetroTal completed drilling horizontal well 21H ("21H") in November 2024. This well was brought onstream on November 17, 2024 at a flush production rate of 7,144 bopd., before producing at an average rate of 2,522 bopd. over the next 30 days. Well 21H was completed on time and on budget, at a cost of approximately $14.4 million;

• PetroTal completed drilling horizontal well 22H ("22H") in December 2024. This well was brought onstream on January 9, 2025, producing an average of 4,344 bopd. over the next 30 days, while achieving a peak daily rate of 7,025 bopd. Well 22H was also completed on time and on budget, at a cost of approximately $12.0 million;

• In October 2024, PetroTal executed an agreement to acquire a drilling rig from a Houston-based equipment Company. The purchase of the rig was financed through a lease agreement with a Peruvian bank, for a term of 36 months at a payment of approximately $0.5 million per month. PetroTal intends to import the rig to Peru in Q1 2025;

• In December 2024, PetroTal signed two Technical Evaluation Agreements with Perupetro. The Technical Evaluation Agreements for Blocks 97 and 98 are located in the vicinity and on trend with PetroTal's Block 131, as well as the Aguaytia and Agua Caliente fields in Peru's Ucayali Basin. These new evaluation contracts offer growth potential in proven exploration acreage near PetroTal's existing operations in the area; and,

• In December 2024, PetroTal signed a contract extension with Perupetro for the exploration Block 107, in Peru's Ucayali Basin. The extension of the Fifth Exploration Period will now last until February 2027, providing ample time to undertake an exploration program at the Osheki-Kametza prospect.

2024 Operational Highlights

• Oil production of 6.5 million bbls. in 2024, representing an average of 17,785 bopd., an increase of 25% from 14,248 bopd. (5.2 million bbls.) in 2023;

• Oil sales allocations were 88.4% as exports through Brazil, 11.3% to the Iquitos refinery, and 0.3% from Ucawa;

• PetroTal drilled seven development wells at Bretana in 2024, compared to three development wells in 2023; and

• PetroTal's 2024 annual independent reserves assessment, as prepared by Netherland Sewell and Associates, Inc. ("NSAI") shows increases in all reserve categories, combined heavy plus light oil:

• Proved ("1P") reserves increased by 40% to 67.1 million bbls. Net present value discounted at 10% ("NPV-10") after tax is $1.1 billion;

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• Proved plus Probable ("2P") reserves increased by 14% to 113.7 million bbls., with an NPV-10 after tax valuation of $1.8 billion; and,

• Proved plus Probable plus Possible ("3P") reserves increased by 7% to 213.3 million bbls., with an NPV-10 after tax valuation of $2.8 billion.

2024 Financial Highlights

• The Company generated revenue of $373.9 million (6.4 million bbls. sold, 17,558 bopd., $58.19/bbl.) compared to $316.9 million (5.2 million bbls. sold, 14,421 bopd., $60.21/bbl.) in 2023;

• Royalties paid to the Peruvian government in 2024 were $29.5 million ($4.59/bbl., 7.9% of revenues) compared to $23.4 million ($4.44/bbl., 7.4% of revenues) in 2023. Contributions for the 2.5% community social trust fund represented $10.4 million in 2024, as compared to $7.3 million in 2023;

• Capital expenditures (“Capex”) totaled $161 million in 2024, primarily associated with the drilling of wells during the year, the expansion of fluid-handling facilities capacity in the Bretana field, and field infrastructure;

• PetroTal entered into a hedging agreement during the quarter, covering the future sale of 1.8 million barrels as of December 31, 2024. The costless collars have a floor price of $65.00/bbl. and a ceiling of $84.25/bbl., with a cap of $104.25/bbl.;

• Generated 2024 EBITDA and free funds flow of $227.9 million ($35.47/bbl.) and $74.1 million ($11.54/ bbl.), respectively;

• Net operating income was $274.3 million ($42.68/bbl.) compared to $238.9 million ($45.39/bbl.) in 2023;

• PetroTal ended the year with total cash of $114.5 million ($102.8 million unrestricted), compared to $111.3 million ($90.6 million unrestricted) in 2023; and,

• PetroTal continued its sustainable shareholder capital return policy. In 2024 PetroTal paid dividends totaling $60.5 million and repurchased 8.8 million shares ($4.9 million), compared to dividends paid of $55.6 million and repurchased shares of 11.3 million ($6.5 million) in 2023.

December 31, 2024 Subsequent Events

• On January 14, 2025, Banco Interamericano de Finanzas extended the exploratory block 107 letters of credit to February 2027;

• In January 2025, PetroTal entered into hedged trades that are costless collars with a cap and 1.8 million barrels through January 2026. The hedges were completed at a floor strike price of $65/bbl. and a ceiling strike price of approximately $80/bbl. In addition, a cap was placed at $100/bbl. to limit credit exposure in the event Brent prices rise above $100/bbl; and,

• On February 20, 2025, the Company declared a cash dividend of $0.015 per common share to be paid March 14, 2025.

4. ASSET ACQUISITION

On November 29, 2024, PetroTal closed the acquisition of a 100% working interest in Peru’s Block 131, as originally disclosed on May 8, 2024, pursuant to which the Company acquired all of the issued and outstanding shares of Ucawa Energy S.A.C. (formerly CEPSA Peruana, S.A.C. or “CEPSA Peru”). Cash consideration of $6.7 million paid for the asset was partially offset by the assumption of a cash balance of $5 million on closing. The cash balance reflects the cumulative cash flow from this asset between the effective date of the acquisition to

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its closing date on November 29, 2024. The amounts recognized on the date of acquisition to identifiable net assets were as follows:

	November 29, 2024
Net Assets acquired
Cash & Cash equivalents	4,988
Trade receivables and other assets	5,179
Property, plant and equipment, net	12,036
Trade and other payables	(1,926)
Decommissioningliabilities	(13,589)
Total Net Asset acquired	6,688
Purchase consideration	6,688
Total Purchase consideration	6,688

The acquisition of Block 131 represents an important milestone for PetroTal, and a pivotal step in the Company’s growth strategy. More importantly, Block 131 diversifies the production base within Peru, establishing a new platform for production and reserves growth. PetroTal’s technical team has already identified numerous synergies between the Block 131 assets and existing operations at Block 95. The Company also plans to apply modern drilling techniques at the Los Angeles field, which has significant unutilized facility capacity.

5. OUTLOOK AND GROWTH STRATEGY

STRATEGY OUTLOOK

PetroTal’s near-term strategy is focused on responsible stewardship of the Bretana Norte oil field, balancing priorities for key stakeholder groups while maximizing value for shareholders. Specifically, the key objectives of PetroTal’s 2024 capital program included:

• Continued migration of 2P reserves into 1P and PDP categories;

• Development of new export routes to maximize value for our product, while minimizing operational risk;

• Maintaining a debt-free balance sheet; and,

• Returning free cash flow to shareholders through stable dividends and share buybacks when appropriate.

As of December 31, 2024, PetroTal has drilled a total of 22 development wells at Bretana, plus 4 water injection wells. The ongoing 2024 development program is consistent with the Company’s year-end reserve report, which contemplated a field development plan consisting of 32 production wells in the 2P case. Remaining recoverable reserves of approximately 107.9 million barrels are expected to be produced prior to the Block 95 license contract expiry in 2041. The 3P case includes recoverable reserves upside to 207 million barrels, mainly through the drilling of additional development locations, and the extension of the Block 95 license contract.

PetroTal is continuously evaluating alternative development strategies which may lead to improved recovery factors and/or acceleration of undeveloped reserves, including infill drilling, extended reach horizontal wells, and multilateral drilling. For example, in Q3 2024, the Company drilled its first lateral into the Upper Vivian sand ("VS1") at Bretana, where a brief production test flowed 320 bopd. This zone, which PetroTal’s

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independent reserve evaluator estimates may contain more than 20% of the original oil in place at the Bretana field, was included in the Company's 3P reserves at year-end 2024.

Another key strategic priority is to secure new export routes throughout Peru, which will facilitate execution of PetroTal’s full 2P and 3P development plans. The company has identified four potential new transportation options in Peru, which could increase sales capacity by up to 20,000 bopd. over the next two to three years. In Q3 2024, PetroTal initiated a pilot shipment of Bretana crude to the Ecuador Pipeline ("OCP"); although the pilot was ultimately hampered by unusually low river levels.

Finally, as part of PetroTal’s unique value proposition to investors, the Company is committed to returning a portion of its free cash flow to shareholders through dividends and share buybacks. With relatively short payback periods on new production wells, PetroTal is capable of generating significant free cash flow which can be used to fund its ongoing development program while supporting returns of capital that have averaged between 11% and 18% on an annualized basis.

The 2024 capital budget was based on an estimated average annual Brent oil price forecast of $77/bbl.

Growth Strategy

PetroTal’s medium-term growth strategy is currently based on the reinvestment of free cash flow from Bretana into undeveloped assets elsewhere in Peru, where the Company has an established track record of operational success. The key objectives of our medium-term growth strategy include:

• Reach and extend Bretana plateau while developing other assets;

• Optimize cost structure through operating synergies;

• Achieve $2 billion in market capitalization through expansion; and,

• Continue to return free cash flow to shareholders.

As the main funding driver of PetroTal’s growth ambitions, the Bretana field remains critical to both the medium- and long-term strategy of the Company. Consistent with the performance of the field over the past few years, PetroTal continues to forecast significant free cash flow from Bretana, which will be used in part to fund the development of new assets elsewhere.

Employing its knowledge base and technical expertise in Latin America, the Company is also executing its growth strategy by sourcing inorganic M&A opportunities to create long-term value for shareholders. PetroTal closed its first acquisition in Peru on November 29, 2024, assuming control of the producing Block 131. The Company is currently finalizing development plans for the asset, including potentially drilling new production wells in 2025.

PetroTal recognizes that balance sheet flexibility is a key focus of investors, and remains a priority for the Company. Supported by the strong historical performance of the Bretana field, PetroTal has the ability to source debt capital at favorable terms, allowing for incremental investment in projects that align with the Company's strategic objectives when appropriate.

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Environmental, Social and Governance (“ESG”) Strategy

PetroTal believes in creating long-term value for our shareholders, employees, suppliers, communities, customers, financial entities, industry associations, international certification bodies and organizations, media, and the government, as well as ensuring economic value, safety for people and the environment, and creating a better future for all. 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 various departments throughout the Company;

• Collaborate with government entities and key stakeholders to promote the efficient and transparent utilization of resources, including the 2.5% social fund and other resources, aimed at promoting strong governance frameworks, mitigating risks of corruption and fund mismanagement, and enhancing institutional capacity and technical expertise;

• Continuously update initiatives to achieve Company goals;

• The Sustainable Development Goals (“SDG”) will be included, to which PetroTal contributes through its sustainability plan to 2030;

• Committed to climate action, the Company aims to implement methodologies that prevent deforestation, minimize its carbon footprint and support projects with zero net biodiversity loss. It prioritizes ecosystem restoration and promotes the sustainable use of local natural resources, while actively evaluating new technologies to eliminate direct emissions in its operations;

• Implement effective due diligence processes, awareness and training to prevent possible human rights violations, focusing efforts on the value chain;

• Develop and promote talent in PetroTal, the community, and within our suppliers; and,

• Engage in constant dialogue with our stakeholders to identify opportunities for collaboration, address concerns and doubts, build awareness, improve our performance, and prevent conflicts.

Exploratory Block 107 – Osheki-Kametza

PetroTal has a 100% working interest in the 623,280 acre block located in the Ucayali basin of Peru. 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 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. 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 in 2026. Perupetro extended the Company's Block 107 exploratory license to February 2027. The block is in a farm out process to acquire a partner, which is necessary for undertaking the drilling commitments.

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6.SELECTED FINANCIAL INFORMATION

6.1 FINANCIAL SUMMARY

		2024		Q4-2024	Q4-2024	Q3-2024	Q3-2024	Q2-2024	Q2-2024	Q1-2024	Q1-2024
($ thousands)		$/bbl.		$/bbl.		$/bbl.		$/bbl.		$/bbl.
PRODUCTION:	Average Production (bopd.)		17,785		19,142		15,203		18,290		18,518
SALES:	Average sales (bopd.)		17,558		19,087		14,760		18,050		18,347
	Total sales (bbls.)		6,426,106		1,756,030		1,357,961		1,642,578		1,669,537
	Average Brent price	$78.98		$73.42		$77.74		$83.87		$81.01
Weighted contracted sales price, gross		$79.15		$73.16		$78.58		$83.92		$81.14
	Tariffs, fees and
LESS:	differentials	($20.96)		($21.10)		($20.52)		($21.15)		($20.89)
	Realized sales price, net	$58.19		$52.06		$58.06		$62.76		$60.25
REVENUES:	Oil revenue(1)	$58.19	$373,940	$52.06	$91,421	$58.06	$78,850	$62.76	$103,086	$60.25	$100,583
LESS:	Royalties(2)	$6.22	$39,947	$7.42	$13,022	$5.47	$7,433	$6.08	$9,991	$5.69	$9,500
	Operating expense (excl.
	Erosion)	$6.90	$44,320	$7.88	$13,843	$8.23	$11,176	$6.10	$10,023	$5.56	$9,278
	Direct Transportation:
	Diluent	$0.77	$4,931	$0.14	$248	$0.90	$1,218	$1.16	$1,898	$0.94	$1,567
	Barging	$0.96	$6,200	$1.89	$3,317	$0.68	$927	$0.58	$951	$0.60	$1,005
	Diesel	$0.08	$520	$0.05	$81	$0.13	$173	$0.11	$186	$0.05	$80
	Dry Season Freight/
	Storage/Inventory	$0.58	$3,697	$1.97	$3,452	$0.51	$690	$0.01	$12	($0.27)	($457)
	Total Transportation	$2.39	$15,348	$4.05	$7,098	$2.22	$3,008	$1.86	$3,047	$1.32	$2,195
NET OPERATING INCOME (NOI)		$42.68	$274,325	$32.71	$57,458	$42.14	$57,233	$48.72	$80,025	$47.68	$79,610
	NOI as % of Revenue		73.4%		62.9%		71.9%		77.6%		79.1%
Erosion Expense		$1.57	$10,117	$5.45	$9,569	$0.40	$548	$—	$—	$—	$—
General and administrative expense		$5.65	$36,291	$4.86	$8,534	$6.75	$9,160	$6.41	$10,528	$4.83	$8,070
Commodity price derivative loss (gain)		$1.62	$10,424	($1.55)	($2,726)	$15.82	$21,481	$2.01	$3,306	($6.97)	($11,638)
Financial expense (gain)		$0.49	$3,156	$1.19	$2,096	($0.23)	($311)	$0.62	$1,018	$0.21	$353
Income tax expense (gain)		$6.21	$39,902	($0.12)	($209)	$4.45	$6,038	$8.81	$14,470	$11.74	$19,602
Depletion, depreciation and amortization		$9.69	$62,242	$10.54	$18,504	$9.64	$13,092	$9.32	$15,310	$9.19	$15,338
Foreign exchange loss (gain)		$0.12	$743	$0.25	$448	$0.03	$46	($0.01)	($14)	$0.16	$264
NET INCOME			$111,450		$21,242		$7,179		$35,407		$47,621
FREE FUNDS FLOW			$74,145		($10,422)		$6,537		$36,334		$41,696

(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.

Note: Free Funds Flow calculation methodology was changed in Q2 2024 and for prior periods to include adjustments for foreign exchange and share based compensation to better measure the Company's generated cash. Q1 2024 previously reported was $52,561 vs. $41,696 with the new methodology.

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		2023		Q4-2023	Q4-2023	Q3-2023	Q3-2023	Q2-2023	Q2-2023	Q1-2023	Q1-2023
($ thousands)		$/bbl.		$/bbl.		$/bbl.		$/bbl.		$/bbl.
PRODUCTION:	Average Production (bopd.)		14,248		14,865		10,909		19,031		12,193
SALES:	Average sales (bopd.)		14,421		15,033		11,553		18,483		12,618
	Total sales (bbls.)		5,263,485		1,383,061		1,062,851		1,681,962		1,135,611
	Average Brent price	$81.53		$82.21		$84.65		$77.29		$82.51
Weighted contracted sales price, gross		$80.54		$81.05		$84.31		$77.88		$80.32
	Tariffs, fees and
LESS:	differentials	($20.33)		($20.28)		($19.25)		($21.26)		($20.01)
	Realized sales price, net	$60.21		$60.77		$65.05		$56.61		$60.31
REVENUES:	Oil revenue(1)	$60.21	$316,911	$60.77	$84,046	$65.05	$69,142	$56.61	$95,229	$60.31	$68,494
LESS:	Royalties(2)	$5.82	$30,648	$7.00	$9,676	$5.49	$5,835	$5.29	$8,899	$5.49	$6,238
	Operating expense (excl.
	Erosion)	$6.16	$32,446	$7.24	$10,010	$8.45	$8,982	$4.22	$7,100	$5.60	$6,354
	Direct Transportation:
	Diluent	$1.30	$6,857	$1.46	$2,020	$1.72	$1,829	$0.98	$1,641	$1.20	$1,368
	Barging	$0.66	$3,475	$0.60	$828	$0.80	$845	$0.53	$896	$0.80	$906
	Diesel	$0.10	$516	$0.10	$142	$0.13	$141	$0.07	$120	$0.10	$113
	Dry Season Freight/
	Storage/Inventory	$0.78	$4,115	$1.45	$2,001	$1.99	$2,114	$—	$—	$—	$—
	Total Transportation	$2.84	$14,963	$3.61	$4,991	$4.64	$4,929	$1.58	$2,657	$2.10	$2,387
NET OPERATING INCOME (NOI)		$45.39	$238,854	$42.92	$59,369	$46.47	$49,396	$45.53	$76,573	$47.12	$53,515
	NOI as % of Revenue		75.4%		70.6%		71.4%		80.4%		78.1%
General and administrative expense		$5.33	$28,049	$6.21	$8,588	$6.92	$7,355	$3.89	$6,548	$4.90	$5,559
Commodity price derivative loss (gain)		$2.37	$12,479	$8.43	$11,662	($11.95)	($12,701)	$3.73	$6,272	$6.38	$7,247
Financial expense		$2.91	$15,341	$2.28	$3,150	$1.12	$1,187	$1.22	$2,046	$7.89	$8,958
Income tax expense		$6.27	$33,002	$2.95	$4,076	$18.30	$19,445	$1.64	$2,751	$5.93	$6,730
Depletion, depreciation and amortization		$7.56	$39,801	$8.33	$11,527	$7.49	$7,962	$7.23	$12,154	$7.18	$8,158
Foreign exchange (gain) loss		($0.06)	($323)	($0.84)	($1,163)	$0.74	$789	$0.10	$167	($0.10)	($116)
NET INCOME			$110,505		$21,529		$25,359		$46,635		$16,979
FREE FUNDS FLOW			$107,192		$19,767		$26,560		$45,044		$15,821

(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.

Note: Free Funds Flow calculation methodology was changed in Q2 2024 and for prior periods to include adjustments for foreign exchange and share based compensation to better measure the Company's generated cash. Previously reported was 2023: $90,674; Q4 2023: $8,127; Q3 2023: $36,944; Q2 2023: $37,697; and Q1 2023 $7,906.

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EARNINGS STATEMENT INFORMATION

Oil sales in 2024 increased by 22% to 6.4 million bbls. (17,558 bopd), compared to 5.3 million bbls. (14,421 bopd.) in 2023. Sales were 1.8 million bbls. (19,087 bopd.) in Q4 2024 compared to 1.4 million bbls. (15,033 bopd.) in Q4 2023.

The Company sells oil at three sales points: the local Iquitos refinery, exports through Brazil, and the Northern Peruvian Pipeline ("ONP"). In 2024, 88.4% of PetroTal's oil sales were through the Brazil export route and 11.3% to the Iquitos refinery. Sales to the Iquitos refinery are priced at the prevailing Brent oil price less a quality differential discount and barge transportation charges. Included in the Iquitos refinery sales during the month of December 2024 was 18,741 bbls. related to the new acquisition of Ucawa (0.3% of the total sales in 2024). 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 the ONP (Saramuro pump station) have been curtailed since February 2022, pursuant to Petroperu's inability to fulfill terms of the sales agreement. Sales to Petroperu at Saramuro 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.

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Royalties and social fund increased to $39.9 million ($6.22/bbl.) in 2024 from $30.6 million ($5.82/bbl.) in 2023, and in Q4 2024 increased to $13.0 million ($7.42/bbl.) from $9.7 million ($7.00/bbl.) in Q4 2023. 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 is calculated on an individual block basis, based either on production scales or on economic results.

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Operating expenses in 2024 were $44.3 million ($6.90/bbl.), as compared to $32.4 million ($6.16/bbl.) in 2023, and in Q4 2024 were $13.8 million ($7.88/bbl.) versus $10.0 million ($7.24/bbl.) in Q4 2023. Higher oil production resulted in higher operating costs mainly related to: $4.3 million in support and subcontracted services, $3.1 million of general and administrative expense allocation, and $4.5 million in community relations, monitoring costs and riverbank maintenance.

Direct Transportation expenses in 2024 totaled $15.3 million ($2.39/bbl.), representing barging and diluent blending costs, as compared to $15.0 million ($2.84/bbl.) in 2023, and in Q4 2024 totaled $7.1 million ($4.05/ bbl.) versus $5.0 million ($3.61/bbl.) in Q4 2023. Direct transportation costs include $3.7 million ($0.58/bbl.) in 2024, and $4.1 million ($0.78/bbl.) in 2023 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.

	Year Ended	Year Ended
	December 31,	December 31,
	2024	2023
Diluent	4,931	6,857
Barging	6,200	3,475
Diesel	520	516
Dryseason freight and storage	3,697	4,115
Total Direct Transportation	15,348	14,963

General and administrative ("G&A") expenses in 2024 were $36.3 million ($5.65/bbl.), as compared to $28.0 million ($5.33/bbl.) in 2023, and $8.5 million ($4.86/bbl.) in Q4 2024 versus $8.6 million ($6.21/bbl.) in Q4 2023. As production increases, per barrel G&A costs generally decrease.

	Year Ended	Year Ended
	December 31,	December 31,
	2024	2023
Salaries and benefits	23,306	14,065
Legal, audit and consulting fees	12,933	9,459
Community support	2,968	3,100
Office rent and administrative	5,927	4,350
Share based compensation plans	3,151	4,364
Costs directlyattributable to PP&E and operatingexpenses	(11,994)	(7,289)
Total	36,291	28,049

The Company allocated $12.0 million of G&A in 2024 to capital projects and operating expenses, compared to $7.3 million in 2023.

Depletion, Depreciation and Amortization (“DD&A”) for 2024 was $62.2 million ($9.69/bbl.) as compared to $39.8 million ($7.56/bbl.) in 2023, and in Q4 2024 totaled $18.5 million ($10.54/bbl.) versus $11.5 million ($8.33/bbl.) in Q4 2023. DD&A is calculated based on capital invested plus expected future capital using the unit of production method over their proved plus probable reserves.

Commodity price derivative loss of $10.4 million in 2024 is net fair value change of outstanding embedded derivatives, compared to $12.5 million derivative loss in 2023. 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. The loss is non-cash and is contingent upon the eventual sale of oil volumes. Until a sale occurs, no payment is

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required. Moreover, if oil prices rise, the projected loss could decrease, potentially benefiting the Company's financial position.

Foreign exchange loss in 2024 was $743 thousand compared to $323 thousand gain in 2023, and a $448 thousand loss in Q4 2024 compared to a $1.2 million gain in Q4 2023, due to fluctuations in relative currency positions and transactions.

Income tax of $39.9 million was recorded in 2024 compared to $33.0 million in 2023.

Financial expense was $3.2 million in 2024, mainly related to financial service fees and accretion of decommissioning obligation, as compared to $15.3 million in 2023. Finance expense in 2023 was higher due to debt bonds balances, paid during the same year.

6.2 BALANCE SHEET INFORMATION

BALANCE SHEET - SUMMARIZED

	December 31,	September 30,	June 30,	March 31,	December 31,
	2024	2024	2024	2024	2023
($ thousands)
Current Assets
Cash	$102,783	$121,328	$84,116	$62,498	$90,568
Restricted cash	$5,745	$5,744	$5,743	$16,653	$14,731
VAT receivable	$23,023	$20,032	$12,376	$9,034	$9,709
Trade and other receivables	$65,832	$47,011	$93,325	$93,402	$58,602
Inventory	$13,570	$23,560	$14,960	$16,525	$12,792
Prepaid expenses	$13,901	$16,199	$19,933	$15,867	$7,462
Derivative assets	$1,307	$3,230	$6,963	$18,065	$9,318
Total Current Assets	$226,161	$237,104	$237,416	$232,044	$203,182
Restricted cash	$6,000	$6,000	$6,000	$6,000	$6,000
Trade Receivable long-term	$19,279	$20,439	$19,985	$20,514	$20,370
VAT receivables and deferred taxes	$4,292	$3,180	$2,769	$14,659	$15,271
PP&E and E&E, net	$547,424	$479,369	$446,563	$422,559	$408,537
Prepaid expenses	$7,000	$—	$—	$—	$—
Derivative assets	$311	$39	$7,967	$4,584	$4,926
Total Non-current Assets	$584,306	$509,027	$483,284	$468,316	$455,104
Total Assets	$810,467	$746,131	$720,700	$700,360	$658,286
Current Liabilities
Trade and other payables	$94,955	$83,725	$71,271	$85,446	$79,328
Income tax payable	$19,744	$25,228	$18,133	$8,260	$—
Lease liabilities	$10,426	$3,712	$3,879	$1,866	$4,555
Short-term debt	$10,047	$—	$—	$—	$—
Total Current Liabilities	$135,172	$112,665	$93,283	$95,572	$83,883
Leases and other long-term	$46,322	$24,298	$25,304	$28,083	$26,373
Deferred income tax liabilities	$72,548	$65,006	$65,762	$62,633	$55,109
Long-term derivative liabilities	$10,534	$14,910	$3,974	$3,599	$6,832
Decommissioning liabilities	$34,383	$25,496	$22,456	$21,556	$22,147
Total Non-current Liabilities	$163,787	$129,710	$117,496	$115,871	$110,461
Total Equity	$511,508	$503,756	$509,921	$488,917	$463,942
Total Liabilities and Equity	$810,467	$746,131	$720,700	$700,360	$658,286

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Cash and liquidity

At December 31, 2024, the Company held cash of $102.8 million and restricted cash of $11.7 million, totaling $114.5 million, compared to $111.3 million at December 31, 2023. Working capital was $91.0 million at December 31, 2024 as compared to $119.3 million at December 31, 2023.

	December	31,	December 31,
	2024		2023
Cash	102,783		90,568
Restricted cash current		5,745	14,731
Restricted cash non-current		6,000	6,000
Total Cash	114,528		111,299

Current restricted cash of $5.7 million, is primarily related to the social fund and letters of credit bank guarantees for Block 107 exploration wells. The $6.0 million of non-current restricted cash is related to permitted hedging programs.

In March 2023, Peru’s President signed the Supreme Decree authorizing Perupetro S.A. to execute the amendment incorporating the 2.5% social trust fund (value of the monthly oil produced in Bretana’s Block 95, less transportation, for the benefit of local communities) into the Block 95 license contract, effective and retroactive to January 1, 2022. For the years ended December 31, 2024 and 2023, the Company paid to the community $17.8 million and $0.2 million, respectively.

VAT receivable

	December 31,	December 31,
	2024	2023
VAT receivable current	23,023	9,709
VAT receivable non-current	2,329	2,226
Total VAT receivables	25,352	11,935

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 $25.9 million during the year ended December 31, 2024 and expects to recover $23.0 million in the short-term.

Trade and other receivables

	December 31,	December 31,
	2024	2023
Trade receivables	84,754	76,163
Other receivables	357	2,809
Total trade and other receivables	85,111	78,972
Represented as:
Current receivables	65,832	58,602
Non-current receivables	19,279	20,370

At December 31, 2024, trade receivables represent revenue related to the sale of oil. The trade balance is mostly comprised of $22.0 million due from Petroperu ($2.7 million is short term and $19.3 million is long term), $58.7 million from export sales through Brazil and $4.0 million from Ucawa Energy S.A.C. customers (all

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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.

In Q4 2023, the Company reclassified a $22.6 million Petroperu receivable from short-term receivables to longterm receivables. The long-term receivable was discounted to a present value of $20.4 million that resulted in a charge to finance expense. At December 31, 2024, the value of this receivable was $19.3 million.

Capital expenditures

	Year Ended	Year Ended
	December 31,	December 31,
Drilling Program	103,870	67,271
Field Infrastructure	42,444	27,483
Fluid Handling Facilities (CPF)	10,454	6,247
Erosion Costs	154	3,205
Block 95	1,119	1,185
Block 107	1,422	1,547
Other	1,108	511
Exploration & development expenditures	160,571	107,449
SAP Project	2,425	1,004
Asset acquisition	9,078	—
Total capital expenditures	172,074	108,453

PetroTal invested $160.6 million in petroleum Capital Projects in 2024, an increase of $53.1 million compared to last year. The major capital expenditures were the costs associated with drilling wells 15H - 23H and water well 5WD at Bretana, along with the expansion of fluid handling capacity at the field and field infrastructure. Additionally, as a result of the asset acquisition, the Company added $9.1 million to its net PP&E balance as of December 31, 2024.

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, 2024, the Company has $10.4 million of exploration and evaluation assets related to Block 95 and Block 107.

Inventory

	December 31,	December 31,
	2024	2023
Oil inventory	2,676	813
Materials, parts and supplies	10,894	11,979
Total inventory	13,570	12,792

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, 2024, the oil inventory balance of $2.7 million consists of 85,863 bbls. of oil (including 3,466 bbls. from Ucawa Energy S.A.C.)

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valued at $31.16/bbl. (December 31, 2023: $0.8 million, based on 35,320 bbls. of oil at $23.01/bbl.). Materials, parts, and supplies, including diluent, are expected to be consumed in the short-term.

	Barrels
Oil inventory at January 1, 2024	35,320
Asset acquisition	3,889
Production	6,509,275
Diluent added	53,680
Internal use (power generation) and other	(90,195)
Sales	(6,426,106)
Oil inventory at December 31, 2024	85,863

Trade and other payables

	December 31,	December 31,
	2024	2023
Trade payables	39,201	25,037
Accrued payables and other obligations	55,754	54,291
Total trade and otherpayables	94,955	79,328

At December 31, 2024 and December 31, 2023, 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 $5.0 million at December 31, 2024 ($12.2 million at December 31, 2023).

Included in the trade and other payables balance at December 31, 2024 are $2.0 million related to the asset acquisition of Ucawa.

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, 2024.

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					Year Ended December 31	Year Ended December 31
					2024	2023
Net derivative asset at beginning of period					7,412	20,370
Cash settlements					(5,904)	(478)
Realized loss					(3,741)	(2,256)
Unrealized loss					(6,683)	(10,224)
Net derivative asset(liability) at	end ofperiod				(8,916)	7,412
Represented as:
Short-term derivative assets					1,307	9,318
Long-term derivative assets					311	4,926
Long-term derivative liabilities					(10,534)	(6,832)
Sales delivery / Executed month	Expected settlement month	Volume (bbls. in thousands)	Price range $/bbl.		Hedged range $/bbl.	Net Derivative Asset (Liability)
Peru Embedded Derivatives(1)
Apr-21 to Feb-22	Sep-26 to Nov-28	1,882	62.49 to	85.26	67.95 to 69.44	(10,223)
Corporate Derivatives Hedging(2)
Aug-24 and Oct-24	Jan-25 to Oct-25	1,655	—		65.00 to 104.50	1,307
				**Net Derivative(Liability) **		(8,916)

• 1) Embedded derivative related to original Petroperu sales agreement.

2) Corporate hedge program to cover a portion of 2024 and 2025 production.

1) Embedded derivative related to original Petroperu sales agreement.

For the year ended December 31, 2024, the Company realized true-up derivative gains from final sales at Bayovar of 0.5 million bbls. (during the year) for $5.9 million. At December 31, 2024, 1.9 million bbls. (2.4 million at December 31, 2023) remain in the pipeline or storage tanks, awaiting final sale by Petroperu. During the year, a decrease in future oil prices to the Peru embedded derivative resulted in a net derivative liability. A 1% change to the hedged range price would result in a $1.2 million change to the net derivative liability. The derivative gains/losses are only materialized when oil is effectively sold to third parties at Bayovar.

2) Corporate hedge program to cover a portion of 2024 and 2025 production.

During the year, the Company executed hedging agreements that consisted of multiple trades that totaled 2.6 million barrels of Brent oil with settlements dates from September 2024 to October 2025. The hedge types included put options of $65.00 per barrel, call options of $84.20 and $84.25 per barrel, and call options of $104.25 and $104.50 per barrel. At December 2024, there was a remainder of 1.7 million in hedged barrels of Brent oil that resulted in a net derivative asset of $1.3 million.

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Decommissioning liabilities

The undiscounted uninflated value of estimated decommissioning liabilities is $64.4 million ($39.0 million in 2023). The present value of the liabilities was calculated using average risk-free rates between 4.8% to 6.3% (December 31, 2023: 5.3%) to reflect the market assessment of the time value of money as well as risks specific to the liabilities that have not been included in the cash flow estimates. The inflation rate used in determining the cash flow estimate was 2.0%. The revisions to the decommissioning liabilities includes changes to cost estimates, the risk free rates and adjustments for inflation.

In Q4 2024, PetroTal acquired $13.6 million in decommissioning liabilities as part of the Ucawa Energy S.A.C. asset acquisition. The present value of the liability was calculated at December 31, 2024 using average risk free rates between 4.8% to 6.0%. The liability represents the present value of abandonment costs for four wells and one water well to be decommissioned in December 2037.

Balance at January1,2023	13,393
Additions	5,390
Revisions to decommissioning liabilities	2,370
Accretion	994
Balance at December 31,2023	22,147
Additions	3,205
Asset acquisition	13,590
Revisions to decommissioning liabilities	(5,851)
Accretion	1,292
Balance at December 31,2024	34,383

Short and long-term debt

At December 31, 2024 the Company had short term debt of $10.0 million at an interest rate of 5.99% to be paid in full 120 days from the date of borrowing. The proceeds will be used to fund short term working capital needs. The Company has $67.0 million in remaining available credit. No debt covenants were set forth by the lenders in the loan agreements and all lines of credit are available for one year with the option to renew.

Bank	Agreement Date	Balance	**Line of Credit **	Interest Rate	Payment Term	Collateral
BCP	March 2023	$10,047	$20,000	5.99 %	120 days	—
BanBif	April 2024	—	$2,000	—	90 days	—
Scotia Bank(1)	April 2024	—	$5,000	—	360 days	$5,000
JP Morgan Bank	May 2024	—	$20,000	—	120 days	—
GNB	August 2024	—	$10,000	—	180 days	—
Banco Pichincha	September 2024	—	$20,000	—	120 days	Insurance endorsement
Balance at December 31, 2024		$10,047	$77,000

(1) The Scotia Bank $5.0 million cash collateral requirement was removed on January 23, 2025.

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Leases

In prior years, PetroTal commenced a service lease arrangement with a supplier that provides turnkey power generation equipment services. In Q4 2024, the Company signed an addendum to lease additional equipment, which resulted in a $15.0 million present value increase to lease assets and liabilities on the balance sheet. The Company has the option to buy the equipment on June 27, 2031 for $3.0 million. The incremental borrowing rate used to measure the lease liabilities was 8.5%. The lease term ends September 2031.

Also in Q4 2024, PetroTal executed an agreement to acquire a drilling rig from a Houston-based equipment Company. The purchase of the rig was financed through a lease agreement (36 month term) with a Peruvian bank which resulted in a $13.3 million present value increase to lease assets and liabilities on the balance sheet. The Company has the option to buy the rig on October 31, 2028 for $0.1 million. The incremental borrowing rate used to measure the lease liability was 8.5%. The lease term ends December 2027.

The lease liabilities includes three office leases, one in Houston, Texas and two in Lima, Peru. The Houston lease was renewed with a 1.1 million present value increase for a term of 6.0 years with an incremental borrowing rate of 9.5%. The Lima leases are for 3-5 years with an incremental borrowing rate of 8.5% with no changes in present value.

Lease liabilities at January 1, 2023	19,642
Revisions	12,389
Payments	(4,465)
Interest on leases	1,304
Lease liabilities at December 31, 2023	28,870
Additions	28,125
Acquisition	15
Revisions	1,045
Payments	(5,819)
Interest on leases	2,405
Lease liabilities at December 31, 2024	54,641
Represented as:
Current liability	10,426
Non-current liability	44,215

As of December 31, 2024, total lease liabilities have the following minimum undiscounted payments per year:

Year
2025	13,119
2026	13,155
Thereafter	40,973
Total	67,247

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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 of Directors.

As of March 18, 2025, PetroTal has the following securities outstanding (in thousands):

Common shares	916,623	98%
Performance share units	18,279	2%
Total	934,902	100%

Dividends

During the years ended December 31, 2024 and 2023, the Company paid dividends to shareholders in the amount of $60.5 million and $55.6 million, respectively. The Company declared dividends per share in the amount of $0.02 in Q1 2024, and $0.015 in each of the following quarters through Q4 2024. The Company’s sustainable dividend policy is to pay dividends based on current liquidity exceeding $60.0 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 44.2 million 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. In May 2024, the Company announced the renewal the NCIB which ends no later than May 23, 2025. This renewal includes the intention to purchase up to 14.6 million common shares (representing approximately 2% of its outstanding common shares at May 10, 2024).

During the years ended December 31, 2024 and 2023, the Company purchased 8.8 million and 11.3 million common shares under the NCIB for total consideration of $4.9 million and $6.5 million, respectively. The surplus between the total consideration and the carrying value of the shares repurchased was recorded against retained earnings.

6.3. 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.

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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.

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:

	Three Months	Ended	Year Ended	Year Ended
	December	31	December	31
	2024	2023	2024	2023
Cash fow from operating activities
Net income	21,241	21,530	111,450	110,505
Adjustments for:
Depletion, depreciation and amortization	18,504	12,232	62,242	39,801
Accretion of decommissioning obligation	360	298	1,292	994
Equity based compensation expense	823	1,145	1,528	4,340
Financial interest expense	2,047	2,561	3,577	10,473
Deferred income tax expense	6,473	(3,160)	28,521	25,766
Commodity price unrealized derivatives(gain)loss	(2,725)	11,662	6,683	10,223
Funds flow provided by operations before non-cash working capital	46,724	46,268	215,293	202,102
Changes in non-cash working capital:
Receivables and restricted cash	(14,730)	(15,760)	(13,522)	26,668
Advances and prepaid expenses	(306)	(906)	(9,043)	(746)
Inventory	9,877	2,400	(302)	497
Trade and other payables	13,065	21,876	10,253	9,445
Income tax payable	(6,642)	—	18,586	—
Commodity price realized derivatives gain	—	—	9,645	2,734
Cash(paid)received for income taxes	(150)	(111)	(150)	(1,241)
Net cashprovided by operating activities	47,838	53,767	230,760	239,459

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	Three Months	Ended	Year Ended	Year Ended
	December	31	December	31
	2024	2023	2024	2023
Cash fow from investing activities
Exploration and evaluation asset additions	(402)	(359)	(1,434)	(1,631)
Property, plant and equipment additions	(50,187)	(31,798)	(161,393)	(106,822)
Asset acquisition	(1,700)	—	(1,700)	—
Non-cash changes in workingcapital	(8,998)	(1,243)	(1,788)	2,700
Net cash used in investingactivities	(61,287)	(33,400)	(166,315)	(105,753)
Net cash (used in) provided by operating and investing
activities	(13,449)	20,367	64,445	133,704

CAPITAL MANAGEMENT MEASURES

Adjusted EBITDA

Adjusted EBITDA means earnings before interest, taxes, depreciation and amortization, derivatives, foreign exchange, adjusted for realized derivatives gain (loss) and share based compensation.

	Three Months	Ended
	December	31	Year Ended December 31
	2024	2023	2024	2023
Net income	21,241	21,530	111,450	110,505
Adjustments to reconcile net income:
Depletion, depreciation and amortization	18,504	11,527	62,242	39,801
Financial expense	2,096	3,150	3,156	15,341
Income tax expense	(209)	4,076	39,902	33,002
Commodity price derivatives loss (gain)	(2,726)	11,662	10,424	12,479
Foreign exchange loss(gain)	448	(1,163)	743	(323)
EBITDA(non-GAAP)	39,355	50,782	227,917	210,805
Commodity price derivatives realized (loss) gain	—	—	5,904	478
Share based compensation	812	1,142	3,151	4,363
Adjusted EBITDA(non-GAAP)	40,167	51,924	236,972	215,646
Capital expenditures	(50,589)	(32,157)	(162,827)	(108,454)
Free funds flow(non-GAAP)	(10,422)	19,767	74,145	107,192

Note: The EBITDA and Adjusted EBITDA calculation methodology was changed in Q2 2024 and for prior periods to exclude realized derivatives gain (loss) and include adjustments for foreign exchange and share based compensation to better measure the Company's generated cash.

EBITDA: For the three months ended December 31, 2023, previously reported was $51,946 (year ended 2023 was $211,128) as the amount previously reported did not include foreign exchange gain. Adjusted EBITDA: For the three months ended December 31, 2023 previously reported was $40,284 (year ended 2023 was $199,127) as the amount previously reported included realized derivatives gain (loss) and did not include share based compensation.

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.

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Operating netback

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.

7. 2024 RESERVE REPORT

The summary below sets forth PetroTal’s reserves at December 31, 2024, for Bretana and Los Angeles oil fields, 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 Handbook”) and the reserve definitions contained in National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) of the Canadian Securities Administrators. More detailed information will be included in PetroTal’s AIF for the year ended December 31, 2024 to be posted on SEDAR (www.sedarplus.ca) and on PetroTal’s website.

Block 95 - Bretana heavy 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.

Block 131 - Los Angeles light oil field

The Los Angeles oil field at Block 131 was discovered by Ucawa (formerly CEPSA Peru S.A.C.) in 2013. As of September 30, 2024 the field has produced a total of approximately 7.8 million bbls. Block 131 is held under an exploration and production license agreement expiring in 2038, subject to a 23.48% royalty rate at field production levels under 5,000 bopd., with a similar scaling factor to Block 95 above 5,000 bopd. All produced oil is currently sold to Petroperu, Peru’s state-owned oil Company, at Pucallpa. The oil is then transported by barge along the Ucayali River (passing PetroTal’s Bretana oil field) to the Iquitos refinery.

Summary of Oil Reserves and Net Present Values as of December 31, 2024

Company Oil Reserves					Future Net Revenue After Income	Future Net Revenue After Income	Future Net Revenue After Income	Future Net Revenue After Income	Future Net Revenue After Income
(bbls. in millions)	**Heavy **	Oil	Light	Oil	Taxes Discounted at (inUSD billion)
	Gross	Net	Gross	Net	0%	5%	10%	15%	20%
Proved Developed Producing	44.7	44.7	0.8	0.8	$1.2	$0.9	$0.8	$0.7	$0.6
Proved Undeveloped	18.2	18.2	3.4	3.4	$0.6	$0.5	$0.4	$0.3	$0.2
Total Proved	62.9	62.9	4.2	4.2	$1.8	$1.4	$1.2	$1.0	$0.8
Probable	45.0	45.0	1.6	1.6	$1.5	$0.9	$0.6	$0.4	$0.3
Total Proved & Probable	107.9	107.9	5.8	5.8	$3.3	$2.3	$1.8	$1.4	$1.1
Possible	98.7	98.7	0.9	0.9	$4.0	$1.9	$1.0	$0.6	$0.4
Total Proved & Probable & Possible	206.6	206.6	6.7	6.7	$7.3	$4.2	$2.8	$2.0	$1.5

Summary of Pricing and Inflation Rate Assumptions - Forecast Prices and Costs (US$/bbl.)

Year-end Forecast	2025	2026	2027	2028	2029	2030
Brent December 31,	$75.58	$78.51	$79.89	$81.82	$83.46	$85.13
Brent January 1, 2025 (Heavy Oil)	$66.15	$69.01	$70.30	$72.17	$73.88	$75.44
Brent January1,2025(Light Crude)	$80.98	$83.91	$85.29	$87.22	$88.86	$90.53

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Year-end Crude Oil Reserves (bbls. in millions)

Category	2024	2023	Change
Proved Developed Producing	45.5	28.5	59.6%
Proved Undeveloped	21.6	19.5	10.8%
Total Proved	67.1	48.0	39.8%
Probable	46.6	52.2	(10.7%)
Total Proved plus Probable	113.7	100.2	13.5%
Possible	99.6	99.4	0.2%
Total Provedplus Probable & Possible	213.3	199.6	6.9%

Year-end Net Present Value at 10% - After Income Tax ($ millions)

Category	2024	2023	Change
Proved Developed Producing	$776	$487	59.3%
Proved Undeveloped	$353	$401	(12.0%)
Total Proved	$1,129	$888	27.1%
Probable	$592	$751	(21.2%)
Total Proved plus Probable	$1,721	$1,639	5.0%
Possible	$1,036	$869	19.2%
Total Provedplus Probable & Possible	$2,757	$2,508	9.9%

Year-end Net Asset Value ("NAV") per Share - After Tax

	December	31,	2024	December	31,	2023
Category	US$/sh		CAD$/sh	US$/sh		CAD$/sh
Proved	$1.89		$2.74	$0.97		$1.29
Proved plus Probable	$2.91		$4.21	$1.80		$2.39
Provedplus Probable & Possible	$4.67		$6.76	$2.75		$3.65

Reserve Life Index ("RLI")

Category	December 31, 2024
Proved	10.3 years
Proved plus Probable	17.5 years
Provedplus Probable & Possible	32.8years

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Future Development Costs

The following information sets forth development costs deducted in the estimation of PetroTal’s future net revenue attributable to the reserve categories noted below:

Proved $192 million Proved plus Probable $645 million Proved plus Probable & Possible $932 million

The future development costs are estimates of capital expenditures required in the future for PetroTal to convert the corresponding reserves to proved developed producing reserves. Future abandonment cost estimates are $68 million (1P), $81 million (2P), and $113 million (3P).

Bretana's reserve life index for 1P and 2P reserves is 10.3 years and 17.5 years, respectively. The cumulative capital invested combined with all future development and abandonment costs represents total finding and development costs of $12.06/bbl. for 1P reserves, $10.64/bbl. for 2P reserves and $6.23/bbl. for 3P reserves.

Original Oil in Place (“OOIP”) remains relatively flat from 2022 levels. Now at 411, 528, and 702 million bbls. (including Los Angeles) for the 1P, 2P and 3P cases, respectively.

In addition to ongoing development of the Bretana oilfield, there are other prospects and exploration opportunities.

8. 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 along with additional information about such judgements and estimates are included in the Consolidated Financial Statements and the accompanying notes as of December 31, 2024 and 2023.

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.

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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.

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 riskfree 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.

Erosion Costs

Erosion control costs are expenses incurred by the Company to protect the producing fields and nearby community from erosion cause by the river. These costs will be capitalized and/or expensed depending on the nature of the outflow and the direct benefits received by the Company or the community. Erosion costs are presented in a separate expense line in the Statement of Earnings and Other Comprehensive Income, recognized as incurred and for a better reliable measurement. The financial statement notes presents the nature, measurement basis, and transparency of this new activity.

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

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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.

Business Combinations

The Company adopted the amendments to IFRS 3 – Business Combinations. Acquisitions of corporations or groups of assets are accounted for as business combinations using the acquisition method if the acquired assets constitute a business. Under the acquisition method, assets acquired and liabilities assumed in a business combination are measured at their fair values. If applicable, the excess or deficiency of the fair value of net assets acquired compared to consideration paid is recognized as a gain on business combination or as goodwill on the consolidated balance sheet. Acquisition-related costs incurred to effect a business combination are expensed in the period incurred. As part of the assessment to determine if the acquisition constitutes a business, the Company may elect to apply the concentration test on a transaction by transaction basis. The test is met if substantially all of the fair value related to the gross assets acquired is concentrated in a single identifiable asset (or group of similar assets) resulting in the acquisition not being deemed a business and recorded as an asset acquisition. The amendments introduced an optional concentration test, narrowed the definitions of a business and outputs, and clarified that an acquired set of activities and assets must include an input and a substantive process that together significantly contribute to the ability to create outputs.

9. NEW ACCOUNTING STANDARDS ISSUED BUT NOT EFFECTIVE

New accounting standards and interpretations were issued and are mandatory for future accounting periods. With respect to IFRS 18 (Presentation and Disclosure in Financial Statements) issued by the IASB in April 2024, the Company is currently evaluating the impact on the Company’s Financial Statements. Retrospective application of the standard is mandatory for annual reporting periods starting from January 1, 2027 onwards with earlier application permitted.

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10. 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. The summary of benefits paid or accrued to executives and directors is:

	Year Ended December 31	Year Ended December 31
	2024	2023
Salaries, incentives and short term benefits	2,021	1,846
Director's fees	1,322	1,014
Share-based compensation	1,736	2,430
Total	5,079	5,290

The compensation, share-based awards, and non-equity incentive, paid or accrued to the Chief Executive Officer and Board of Directors members are as follows:

			Non-Equity
	Compensation	Share-based	Incentive
Name	Earned	awards	Plans	2024 Total	2023 Total
Manuel Pablo Zuniga-Pflucker(1)	520,000	1,272,000	261,945	2,053,945	1,887,500
Mark McComiskey (Chair)	105,000	183,352	—	288,352	287,733
Gavin Wilson	75,000	101,979	—	176,979	121,671
Eleanor J. Barker	97,000	101,429	—	198,429	143,158
Roger M. Tucker(2)	57,651	61,419	—	119,070	141,158
Jon Harris	83,174	100,455	—	183,629	120,250
Felipe Arbelaez	80,000	100,227	—	180,227	58,109
Emily Morris	75,000	100,165	—	175,165	26,460
Luis Carranza(3)	—	—	—	—	115,034
Director Compensation	1,092,825	2,021,026	261,945	3,375,796	2,901,073

(1) Mr. Zuniga-Pflucker does not receive compensation fees or share-based awards for his role as a Director.

(2) Director retired from the Board in August 2024.

(3) Director retired from the Board in June 2023.

11. TAXES

The Company’s effective tax rate is impacted 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:

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	Year Ended
	December 31 December 31 2024 2023
Earnings before income taxes Canadian corporate tax rate	151,352 143,507 23 % 23 %
Expected income tax expense Increase (decrease) in taxes resulting from: Non-deductible expenses and other Tax differential on foreign jurisdictions Change in valuation allowance	34,811 33,007 (1,349) 1,408 6,440 10,212 — (11,625)
Provision for income taxes	39,902 33,002

The deferred income tax balances are as follows:

	Year Ended
	December 31 December 31 2024 2023
Deferred income tax asset: Property, plant, and equipment Net operating loss carryover Other taxpools	— 7 1,013 4,119 950 8,919
Deferred income tax asset	1,963 13,045
Deferred income tax liability: Property, plant, and equipment Derivative assets and liabilities Preoperative expenses Net operating loss carryover Other taxpools	(81,082) (58,554) 3,271 (2,372) 1,912 2,549 41 2,156 3,310 1,112
Deferred income tax liability	(72,548) (55,109)

The Company recognized the net tax amount related to Net Operating Losses (“NOLs”) and deferred tax liabilities in Canada, Peru and the US. As of December 31, 2024, the Company consumed all losses in Canada (December 31, 2023: $21 million) and all losses in Peru related to Bretana (December 31, 2023: $7 million). The US has $4 million tax losses remaining (December 31, 2023: $1 million). The US non-capital losses can be carried forward indefinitely.

Ucawa has $82 million in tax losses at the end of December 31, 2024 but no related deferred tax asset has been recognized. These losses are being carried forward and are available to offset against future tax gains.

The aggregate amount of temporary differences associated with investments in subsidiaries for which deferred tax liabilities have not been recognized as of December 31, 2024 is approximately $22 million (December 31, 2023: $29 million).

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12. CONTRACTUAL OBLIGATIONS AND COMMITMENTS

GUARANTEES AND COMMITMENTS

As at December 31, 2024, the Company holds the following letters of credit guaranteeing its commitments in exploration block 107:

Block	Beneficiary	Amount	Commitment	Expiration
107	Perupetro	$1,500	1st exploration well, minimum work 5th exploratory period	May 2026
107	Perupetro	$1,500	2nd exploration well,minimum work 5th exploratory period	May2026
		$3,000

PetroTal also signed two Technical Evaluation Agreements (“TEA”) with Perupetro in December 2024. The TEA’s for Blocks 97 and 98 are located in the vicinity and on trend with PetroTal’s Block 131, as well as the Aguaytia and Agua Caliente fields in Peru’s Ucayali Basin. Contractual commitments will be executed in two 12-month phases, and mainly include geological and geophysical studies such as seismic imaging, geochemical modeling and hydrocarbon potential evaluation reports.

The Company progressed its preventive riverbank erosion control program aimed to protect the Bretana field and nearby community. The estimated total project cost has a range of $65 million to $75 million, which will be allocated approximately 65% to operating expense and 35% to capital expenditures during the next years. This program represents a significant operational and environmental commitment, and indicates a proactive approach to environmental stewardship for a permanent solution for the riverbank erosion.

As part of Ucawa Energy S.A.C. asset acquisition, a tax administrative and a judicial legal case were considered as possible, with a total legal contingency of approximately $2.5 million. According to clause 12.5 in the Purchase Agreement, the seller (CEPSA S.A.) is obligated to indemnify PetroTal of any legal action, and/or fines if applicable.

CONTRACTUAL OBLIGATIONS

Refer to "Short and long-term debt" in section "6.2 Balance Sheet Information" for material changes to the Company's contractual obligations.

13. 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, 2024.

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

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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 may 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 and transportation 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 the year ended December 31, 2024, 88.4% of oil sales were to Novum (Brazil export route), 11.3% were to Petroperu (Iquitos refinery), and 0.3% from Ucawa. The Company has not experienced any material credit losses in the collection of its trade receivables.

Impairment to a financial asset is only recorded when there is objective evidence of impairment and the loss event has an impact on future cash flow and can be reliably estimated. Evidence of impairment may include default or delinquency by a debtor or indicators that the debtor may enter bankruptcy. Management believes that there is no risk on the recoverability and/or applicability of the sales tax credits. Therefore, no impairment to the carrying value of these assets has been estimated. The Company has deposited its cash and cash equivalents with reputable financial institutions, with which management believes the risk of loss to be remote. The maximum credit exposure associated with financial assets is their carrying value. At December 31, 2024, 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.

Additional information regarding risk factors including, but not limited to, risks related to political developments in Peru and environmental risks is available in the Company’s AIF, a copy of which may be accessed through the SEDAR+ website (www.sedarplus.ca).

FORWARD-LOOKING STATEMENTS

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

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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 2025 capital program and budget, including drilling plans, balance sheet strength, hedging program and the terms thereof, and future development and growth prospects. All statements other than statements of historical fact may be forward-looking statements. In addition, statements relating to expected production, reserves, prospective resources, recovery, costs and valuation are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future. Forward-looking statements are often, but not always, identified by the use of words such as “anticipate”, “plan”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “predict”, “potential”, “intend”, “could”, “might”, “should”, “believe” and similar expressions.

The forward-looking statements are based on certain key expectations and assumptions made by the Company, including, but not limited to, expectations and assumptions concerning the ability of existing infrastructure to deliver production and the anticipated capital expenditures associated therewith, reservoir characteristics, recovery factor, exploration upside, prevailing commodity prices and the actual prices received for PetroTal's products, including pursuant to hedging arrangements, the availability and performance of drilling rigs, facilities, pipelines, other oilfield services and skilled labor, royalty regimes and exchange rates, the application of regulatory and licensing requirements, the accuracy of PetroTal's geological interpretation of its drilling and land opportunities, current legislation, receipt of required regulatory approval, the success of future drilling and development activities, the performance of new wells, the Company's growth strategy, general economic conditions and availability of required equipment and services. Although the Company believes that the expectations and assumptions on which the forward-looking statements are based are reasonable, undue reliance should not be placed on the forward-looking statements because the Company can give no assurance that they will prove to be correct. The Company believes that the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon by investors. These statements speak only as of the date of this MD&A and are expressly qualified, in their entirety, by this cautionary statement.

These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of reserve estimates, the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price volatility, price differentials and the actual prices received for products, exchange rate fluctuations, legal, political and economic instability in Peru, access to transportation routes and markets for the Company's production, changes in legislation affecting the oil and gas industry and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. Please refer to the risk factors identified in the AIF which is available on SEDAR+ at www.sedarplus.ca.

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-

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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 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.

ADDITIONAL INFORMATION

Additional information about PetroTal Corp. and its business activities, including PetroTal’s audited Financial Statements for the years ended December 31, 2024 and 2023 are available on the Company's website at www.petrotal-corp.com, and at www.sedarplus.ca.

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DIRECTORS Mark McComiskey[(1)(4)(5)] Chair of the Board

Felipe Arbelaez[(3)(4)] Eleanor Barker[(4)(5)] Jon Harris[(1)(2)(5)] Emily Morris[(5)] Gavin Wilson[(1)(2)(3)]

Manuel Pablo Zuniga-Pflucker[(2)]

OFFICERS AND SENIOR EXECUTIVES Manuel Pablo Zuniga-Pflucker President and Chief Executive Officer

Camilo McAllister Executive VP and Chief Financial Officer

Jose Contreras Chief Operating Officer

Sudan Maccio

Chief Legal Counsel and Corporate Secretary

CORPORATE HEADQUARTERS PetroTal Corp. 16200 Park Row, Suite 300 Houston, Texas 77084 Office: 713.609.9101 info@petrotal-corp.com www.petrotal-corp.com

REGISTERED OFFICE PetroTal Corp. 4200 Bankers Hall West, 888-3rd Street Calgary, Alberta, Canada

OPERATING OFFICE PetroTal Peru SRL 144 Dionisio Derteano, Suite 1200 San Isidro Lima, Peru

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

LEGAL COUNSEL Stikeman Elliott LLP Calgary, Alberta, Canada

AUDITORS Deloitte LLP Calgary, Alberta, Canada

NOMINATED & FINANCIAL ADVISER Strand Hanson Limited London, United Kingdom

JOINT BROKERS Stifel Nicolaus Europe Limited London, United Kingdom

Peel Hunt LLP

London, United Kingdom

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

Glen Priestley

VP Finance and Treasurer

Emilio Acin-Daneri

VP Business Development

Max Torres

VP Exploration

Guillermo Florez

General Manager Peru

(1) Member of the Corporate Governance and Compensation Committee.

(2) Member of the Reserves Committee.

(3) Member of the HSE CSR Committee.

(4) Member of the Audit Committee.

(5) Member of the Technical Committee.

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GLOSSARY / ABBREVIATIONS

1P	Proved
2P	Proved plus Probable
3P	Proved plus Probable and Possible
AIF	Annual Information Form
bbl(s)	Barrel(s)
bopd	Barrels of Oil per Day
Capex	Capital Expenditures
CGUs	Cash Generating Units
COGE	Canadian Oil and Gas Evaluation Handbook
CSR	Community, Social and Regulatory
DD&A	Depletion, Depreciation and Amortization
E&E	Exploration and Evaluation
EIA	Environmental Impact Assessment
ESG	Environmental and Social Governance
FOB	Freight on board
FFO	Funds Flow Provided by Operations
G&A	General and Administrative
GAAP	Generally Accepted Accounting Principles
IFRS®	International Financial Reporting Standards (“IFRS®” or "IFRS® Accounting Standards") as issued by
	the International Accounting Standards Board (“IASB”)
MD&A	Management's Discussion and Analysis
mmboe	Million Barrels of Oil Equivalent
NAV	Net Asset Value
NCIB	Normal Course Issuer Bid
Netback	Benchmark to assess the profitability based on revenues less royalties, operating and transportation
	costs
NI 51-101	National Instruments - Standards of Disclosure for Oil and Gas Activities
NOI	Net Operating Income
NPV	Net Present Value
NSAI	Netherland Sewell and Associates, Inc.
OCP	Ecuador Pipeline
ONP	Northern Peruvian Pipeline
OOIP	Original Oil in Place
PP&E	Property, Plant and Equipment
RLI	Reserve Life Index
SDGs	Sustainable Development Goals
USD	United States Dollar ($)
VAT	Value Added Tax
VS1	Upper Vivian Sand

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