Frontera Energy Corporation: Frontera Announces First Quarter 2025 Results

Recorded $27.5 million in Net Income and $13.6 million in Income from Operations

Generated Operating EBITDA of $83.5 Million

Generated Adjusted Infrastructure EBITDA of $28.6 million and $44.9 million Segment Income

Recapitalization of its ODL Interest Through a New $220 Million Non-Recourse Secured Loan Expected to be Completed Shortly

Announces its Intention to Commence a $65 Million Substantial Issuer Bid

Launches a $65 Million Capped Tender and Consent Solicitation for the 2028 Senior Unsecured Notes

Declared Quarterly Dividend of C$0.0625 Per Share, or $3.5 Million in Aggregate, Payable on or around July 17, 2025

Released its 2024 Sustainability Report

CALGARY, AB, May 9, 2025 /PRNewswire/ - Frontera Energy Corporation (TSX: FEC) ("Frontera" or the "Company") today reported financial and operational results for the first quarter ended March 31, 2025. All financial amounts in this news release and in the Company's financial disclosures are in United States dollars, unless otherwise stated.

Gabriel de Alba, Chairman of the Board of Directors, commented:

"Frontera remains focused on the delivery of its strategic objectives and generating value for its stakeholders. In the first quarter, the Company generated $83.5 million in Operating EBITDA, produced $28.6 million of Adjusted Infrastructure EBITDA, and maintained a strong balance sheet, finishing the quarter with a total cash balance of $199.8 million.

The Board is advancing on the strategic path for maximizing shareholder value in Frontera's Infrastructure assets. The next step is the strategic recapitalization of its investment in the ODL pipeline and the development of key growth projects in Puerto Bahia. Frontera's Board will remain open to and consider all opportunities to enhance shareholder value, including a potential future separation and other strategic transactions involving the Infrastructure business, which could include a potential LNG import facility in Puerto Bahia. We would like to thank Goldman Sachs for their advice as the Board reviewed various alternatives.

In connection with the recapitalization of ODL, the Company expects to receive net proceeds of approximately $115 million (after the refinancing of existing debt) and is launching a $65 million capped tender and consent solicitation of the 2028 Senior Unsecured Notes and plans to commence a substantial issuer bid to purchase up to $65 million of the Company's outstanding shares.

The Company is also declaring its quarterly dividend of C$0.0625 per share, or $3.5 million in aggregate, and plans to commence its NCIB program once the announced substantial issuer bid is completed.

These efforts are consistent with the Company's strategy of returning capital to its stakeholders. The Company will continue to consider similar investor-focused initiatives in 2025 and beyond, including potential additional dividends, distributions, share or bond buybacks, based on the overall results of the businesses, oil prices and cash flow generation. Additionally, the Company will consider all options to enhance the value of its common shares in the short term, and in so doing may consider other strategic initiatives or transactions."

Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented:

"Following the close of the first quarter, the Company signed a commitment letter for a $220 million non-recourse secured financing supported by Frontera's indirect interest in ODL. The Company expects to enter into definitive agreements shortly, pursuant to which the Company expects to receive approximately $115 million in net proceeds, after the refinancing of existing indebtedness. The recapitalization would allow Frontera to distribute significant value to its investors, while maintaining the future upside of this key transportation asset in Colombia. Furthermore, the financing is expected to exclude Puerto Bahía from the security package, which would provide Puerto Bahía greater flexibility to secure independent financing for new strategic growth projects.

Frontera's first quarter financial results in our Colombia and Ecuador upstream onshore business are in-line with expectations despite some unforeseen challenges, including lower than expected quarterly production levels.

First quarter production was lower on a quarter over quarter basis, mainly due to delays in the heavy oil assets' drilling campaign, lower water handling on SAARA than expected, the impact of the natural decline as well as a greater need for well interventions in the light and medium blocks, that have since been resolved. Despite these challenges, the Company is gaining momentum into the second quarter, with production increasing to an estimated average daily production for May to approximately 42,400 boe/d and increasing water handling in our SAARA water treatment plant to 130,000 barrels per day. The Company remains confident it will meet its full year average production guidance of 41,000 - 43,000 boe/d.

On the cost side, the company's transportation and energy cost per barrel metrics were within our 2025 Guidance, however production costs rose this quarter mainly due to the impact of higher well intervention activity in our light and medium blocks.

Given the current oil price environment and the challenges facing the Oil & Gas industry in Colombia and globally, Frontera's focus remains on taking actions by identifying additional operational improvements, reduction in capital spend and greater cost and processes efficiencies in the business supporting a strong production profile and optimizing cash flow generation.

In our standalone and growing Colombia infrastructure business, which includes the Company's interest in ODL, the segment generated an Adjusted Infrastructure EBITDA of $28.6 million. During the first quarter of 2025, ODL transported over 236,000 barrels of oil. ODL also declared a $151 million dividend ($52.9 million, net to Frontera), paying 50% of this amount in March 2025, highlighting the strong cash generation capacity of this strategic infrastructure investment. For Puerto Bahia, the Company's focus remains on starting up the Reficar Connection Project. With construction effectively complete, the Company aims to transport the first volume in the third quarter of 2025. Ongoing strategic investments in the port, including the LPG JV with Empresas Gasco, are progressing as planned. Additionally, the port is also reviewing new investment opportunities that leverage its facilities and infrastructure for profitable long-term growth.

We are very pleased to announce that on March 11, 2025, Frontera was once again recognized by Ethisphere as one of the World's most Ethical Companies. This is the fifth consecutive year that the Company has received this distinction from Ethisphere, a global leader in defining and advancing the standards of ethical business practices.

Additionally, we also released our 2024 Sustainability Report which highlights the progress we have made over the last year against our sustainability goals, as we work towards a culture of corporate consciousness that allows us to state that we are committed to developing a sustainability strategy throughout our business to drive operational efficiency."

First Quarter 2025 Operational and Financial Summary:

		Q1 2025	Q4 2024	Q1 2024
Operational Results
Heavy crude oil production (1)	(bbl/d)	27,167	27,740	23,398
Light and medium crude oil production (1)	(bbl/d)	10,998	12,234	12,580
Total crude oil production	(bbl/d)	38,165	39,974	35,978
Conventional natural gas production (1)	(mcf/d)	2,274	2,633	3,283
Natural gas liquids production (1)	(boe/d)	1,913	1,970	1,639
Total production (2)	(boe/d) (3)	40,477	42,406	38,193
Inventory Balance
Colombia	(bbl)	392,821	501,778	683,335
Peru	(bbl)	480,200	480,200	480,200
Ecuador	(bbl)	38,865	47,488	115,228
Total Inventory	(bbl)	911,886	1,029,466	1,278,763
Brent price Reference	($/bbl)	74.98	74.01	81.76
Produced crude oil and gas sales (4)	($/boe)	68.42	67.18	76.10
Purchase crude net margin (4)(5)	($/boe)	(3.81)	(3.42)	(3.01)
Oil and gas sales, net of purchases(4)(5)	($/boe)	64.61	63.76	73.09
Premiums paid on oil price risk management contracts (6)(7)	($/boe)	(1.35)	0.07	(1.27)
Royalties (6)	($/boe)	(1.00)	(0.88)	(1.64)
Net sales realized price (4)(5)	($/boe)	62.26	62.95	70.18
Production costs (excluding energy cost), net of realized FX hedge impact (4)	($/boe)	(10.04)	(7.66)	(10.21)
Energy costs, net of realized FX hedge impact (4)	($/boe)	(5.38)	(5.29)	(5.29)
Transportation costs, net of realized FX hedge impact (4)(5)	($/boe)	(12.32)	(11.35)	(11.47)
Operating netback per boe (4)(5)	($/boe)	34.52	38.65	43.21
Financial Results
Oil & gas sales, net of purchases (8)	($M)	197,975	215,724	200,774
Premiums paid on oil price risk management contracts (7)	($M)	(4,141)	253	(3,489)
Royalties	($M)	(3,060)	(2,971)	(4,506)
Net sales (8)	($M)	190,774	213,006	192,779
Net income (loss) (9)	($M)	27,524	(29,401)	(8,503)
Per share - basic	($)	0.35	(0.36)	(0.10)
Per share - diluted	($)	0.34	(0.36)	(0.10)
General and administrative	($M)	13,571	13,170	13,556
Outstanding Common Shares	Number of shares	77,294,460	80,793,387	84,693,416
Operating EBITDA (8)	($M)	83,458	113,479	97,248
Cash provided by operating activities	($M)	70,137	168,691	65,616
Capital expenditures (8)	($M)	46,711	85,866	69,381
Cash and cash equivalents - unrestricted	($M)	170,094	192,577	154,907
Restricted cash short and long-term (10)	($M)	29,738	30,249	27,058
Total cash (10)	($M)	199,832	222,826	181,965
Total debt and lease liabilities (10)	($M)	505,486	506,037	537,151
Consolidated total indebtedness (Excl. Unrestricted Subsidiaries) (11)	($M)	409,675	414,481	429,556
Net Debt (Excluding Unrestricted Subsidiaries) (11)	($M)	290,732	302,403	309,038

⁽¹⁾ References to heavy crude oil, light and medium crude oil combined, conventional natural gas and natural gas liquids in the above table and elsewhere in this news release refer to the heavy crude oil, light crude oil and medium crude oil combined, conventional natural gas and natural gas liquids, respectively, product types as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.

⁽²⁾ Represents working interest (W.I). production before royalties. Refer to the "Further Disclosures" section on page 36 of the Company's management's discussion and analysis for the three months ended on March 31, 2025 ("MD&A").

⁽³⁾ Boe has been expressed using the 5.7 to 1 Mcf/bbl conversion standard required by the Colombian Ministry of Mines & Energy. Refer to the "Further Disclosures - Boe Conversion" section on page 36 of the MD&A.

⁽⁴⁾ Non-IFRS ratio is equivalent to a "non-GAAP ratio", as defined in National Instrument 52-112 - Non-GAAP and Other Financial Measures Disclosure ("NI 52-112"). Refer to the "Non-IFRS and Other Financial Measures"' section on page 23 of the MD&A or below under the heading "Non-IFRS Financial Measures".

⁽⁵⁾ 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahia (as defined below) inter-segment costs related to diluent and oil purchases as well as transportation costs.

⁽⁶⁾ Supplementary financial measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 23 of the MD&A or below under the heading "Supplementary Financial Measures".

⁽⁷⁾ Includes the net of the put premiums paid for expired positions and the positive cash settlement received from oil price contracts during the period. Please refer to the "Loss (gain) on risk management contracts" section on page 13 of the MD&A for further details.

⁽⁸⁾ Non-IFRS financial measure (equivalent to a "non-GAAP financial measure", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 23 of the MD&A.

⁽⁹⁾ Net (loss) income attributable to equity holders of the Company.

⁽¹⁰⁾ Capital management measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 23 of the MD&A or below under the heading "Capital Management Measures".

⁽¹¹⁾ "Unrestricted Subsidiaries" include CGX Energy Inc. ("CGX"), listed on the TSX Venture Exchange under the trading symbol "OYL"; FEC ODL Holdings Corp., including its subsidiary Frontera Pipeline Investment AG ("FPI", formerly named Pipeline Investment Ltd); Frontera BIC Holding Ltd.; Frontera Energy Guyana Holding Ltd.; Frontera Energy Guyana Corp.; and Frontera Bahía Holding Ltd, including Sociedad Portuaria Puerto Bahia S.A ("Puerto Bahia"). Refer to the "Liquidity and Capital Resources" section on page 29 of the MD&A.

First Quarter 2025 Operational and Financial Results:

• The Company recorded a net income of $27.5 million or $0.35 /share in the first quarter of 2025, compared with a net loss of $29.4 million or $0.36 /share in the prior quarter and net loss of $8.5 million or $0.10 /share in the first quarter of 2024. Net income for the first quarter included an income tax recovery of $9.7 million (including $15.4 million of deferred income tax recovery), income from operations of $13.6 million (net of a non cash impairment expense of $1.1 million), $15.1 million from share of income from associates, foreign exchange income of $2.2 million and $0.6 million related to gain on risk management contracts, partially offset by finance expenses of $15.4 million. This compared to net loss, attributable to equity holders of the Company of $8.5 million for the first quarter of 2024, mainly resulting from income tax expense of $26.6 million (including $21.6 million of deferred income tax expenses), finance expenses of $17.3 million and $8.8 million related to loss on risk management contracts, partially offset by an operating income of $29.7 million, and $13.9 million from share of income from associates.
• Production averaged 40,477 boe/d in the first quarter of 2025, down 5% compared to 42,406 boe/d in the prior quarter and up 6% against 38,193 boe/d in the first quarter of 2024. Compared to the fourth quarter 2024, heavy oil production decreased by 2%, mainly due to delays in the 2025 drilling campaign. Light and medium crude oil combined production and conventional natural gas production decreased primarily as a result of natural decline of the blocks, greater need of well interventions and increasing water production. Natural gas liquids production decreased quarter over quarter by 3%.

	Q1 2025	Q4 2024	Q1 2024
Heavy crude oil production (bbl/d)	27,167	27,740	23,398
Light and medium crude oil production (bbl/d)	10,998	12,234	12,580
Conventional natural gas production (mcf/d)	2,274	2,633	3,283
Natural gas liquids production(boe/d)	1,913	1,970	1,639
Total production	40,477	42,406	38,193

• Operating EBITDA was $83.5 million in the first quarter of 2025 compared to $113.5 million in the prior quarter and $97.2 million in the first quarter of 2024. The decrease in operating EBITDA compared to the prior quarter was mainly due to lower realization price ($62.26 versus $62.95), lower volumes sold and higher production costs during the quarter.
• Cash provided by operating activities in the first quarter of 2025 was $70.1 million, compared to $168.7 million in the prior quarter and $65.6 million in the first quarter of 2024.
• The Company reported a total cash position of $199.8 million at March 31, 2025, compared to $222.8 million at December 31, 2024 and $182.0 million at March 31, 2024. The Company generated $70.1 million of cash provided from operations during the quarter, compared to $168.7 million in the previous quarter. During the quarter, the Company invested $46.7 million of capital expenditures and paid $34 million in shareholder distributions.
• As at March 31, 2025, the Company had a total crude oil inventory balance of 911,886 bbls compared to 1,029,466 bbls at December 31, 2024. As of March 31, 2025, the Company had a total inventory balance in Colombia of 392,821 barrels, including 223,484 crude oil barrels and 169,337 barrels of diluent and others. This compared to 501,778 as of December 31, 2024, and 683,335 barrels as at March 31, 2024. The decrease in inventory balance was primarily due to lower production during the quarter.
• Capital expenditures were approximately $46.7 million in the first quarter of 2025, compared with $85.9 million in the prior quarter and $69.4 million in the first quarter of 2024. During the first quarter, the Company drilled 13 development wells at its Quifa and CPE-6 blocks in Colombia.
• The Company's net sales realized price was $62.26 /boe in the first quarter of 2025, compared to $62.95 /boe in the prior quarter and $70.18 /boe in the first quarter of 2024. The decrease in the Company's net sales realized price quarter over quarter was mainly driven by higher purchased crude net margin and the premiums paid from oil price risk management contracts settled during the first quarter 2025, partially offset by higher Brent benchmark oil price and better oil price differentials.
• The Company's operating netback was $34.52 /boe in the first quarter of 2025, compared with $38.65 /boe in the prior quarter and $43.21 /boe in the first quarter of 2024. The decrease was a result of higher production cost (excluding energy cost), net of realized FX hedge impact, driven by higher well intervention activities during the quarter, higher transportation costs, net of realized FX hedge impact attributed to annual transportation tariff increases and higher energy costs, net of realized FX hedge impact.
• Production costs (excluding energy cost), net of realized FX hedge impact, averaged $10.04 /boe in the first quarter of 2025, compared with $7.66 /boe in the prior quarter and $10.21 /boe in the first quarter of 2024. The increase in production cost was driven by higher well intervention activities resulting from unforeseen well failures during the quarter.
• Energy costs, net of realized FX hedging impacts, averaged $5.38 /boe in the first quarter of 2025, compared to $5.29 /boe in the prior quarter and up from $5.29 /boe in the first quarter of 2024. The increase quarter over quarter was mainly due to carbon credits purchases in the first quarter of 2025 and higher energy price increase.
• Transportation costs, net of realized FX hedging impacts averaged $12.32 /boe in the first quarter of 2025, compared with $11.35 /boe in the prior quarter and $11.47 /boe in the first quarter of 2024. The increase in transportation costs during the quarter was primarily attributed to tariff increases for the Ocensa pipeline and trucking.
• ODL volumes transported were 236,387 bbl/d during the first quarter of 2025, which were in line with 235,528 bbl/d transported in the fourth quarter of 2024.
• Total Puerto Bahia liquids volumes were 51,579 bbl/d during the first quarter 2025 compared to 61,990 bbl/d in the fourth quarter of 2024. The decrease in volumes during the quarter was related to lower Nafta imported, due to lower requirements from third parties.
• Adjusted Infrastructure EBITDA in the first quarter of 2025 was $28.6 million, compared to $27.5 million in the fourth quarter 2024, which increased mainly due to positive results in the ODL segment driven by the pipeline tariff increase and lower costs during the quarter.

Frontera's Sustainability Strategy

Frontera successfully achieved 100% of its 2024 sustainability goals, marking the first milestone towards its 2028 Sustainability Strategy.

On environmental achievements:

• The Company neutralized 50% of all the 2024 emissions
• A total of 70,162 tons of CO2 eq were absorbed from our environmental compensation areas
• 35% of Frontera's operation water was reused

Regarding the Company's social contributions:

• Frontera achieved its best Total Recordable Incident Rate (TRIR) ever, with a 6% reduction compared to 2023
• 12% of total purchases from local goods and services suppliers and providers, 3% increase compared to 2023
• Invested $4.1 million in social projects benefiting 66,303 people near its operations
• Frontera was ranked among the top 20 best companies to work in Colombia by Great Place to Work in 2024

On the governance front

• Ethisphere recognized Frontera for the 4^th consecutive year, as one of the most ethical companies in the world

As reflected in our 2024 Sustainability Report, Frontera Energy ratifies its commitment to develop its business in a responsible manner aiming to build a sustainable future.

Frontera's Sustainability Report can be accessed on the Company's website at: https://www.fronteraenergy.ca/sustainability-reports/.

Strategic Review Update: ODL Recapitalization, Additional Opportunities, Shareholder Distribution and Debt Tender

The Board is advancing on the strategic path for maximizing shareholder value in Frontera's Infrastructure assets. The next step is the strategic recapitalization of its investment in Oleoducto de los Llanos S.A. ("ODL"), and the development of key growth projects in Puerto Bahia. Frontera's Board will remain open to and consider all opportunities to enhance shareholder value, including a potential future separation and other strategic transactions involving the Infrastructure business, which could include a potential LNG import facility in Puerto Bahia.

Pursuant to the terms and conditions of the commitment letter amongst the Company's wholly-owned subsidiary, Frontera Pipeline Investment AG, as borrower, and Macquarie Group. and subject to the execution of definitive documentation, the Company expects to raise $220 million in non-recourse secured financing supported by Frontera's indirect interest in ODL. The recapitalization financing would be a non-recourse secured financing supported by the cash flows from the Company's interest in ODL. The recapitalization is expected to allow the Company to receive approximately $115 million in proceeds, after the refinancing of existing indebtedness, while maintaining the future upside of this key transportation asset in Colombia. Furthermore, the financing is expected to exclude Puerto Bahía from the security package, which would provide Puerto Bahía with greater flexibility to secure independent financing for new strategic growth projects.

Although there can be no assurance that the financing will be completed, the Company expects to enter into definitive agreements and close the financing shortly. As a result, the Company is launching a $65 million capped tender and consent solicitation of the 2028 Senior Unsecured Notes (which is subject to a financing and other conditions) and plans to commence a substantial issuer bid to purchase up to $65 million of the Company's outstanding shares.

Enhancing Shareholder Returns

The Company will continue to consider investor-focused initiatives in 2025 and beyond, including potential additional dividends, distributions, share or bond buybacks, based on the overall results of the businesses, oil prices and cash flow generation. Additionally, the Company also continues to consider all options to enhance the value of its common shares in the short term, and in so doing may consider forms of strategic initiatives or transactions, which may include a further return of capital to shareholders, a merger or a business combination, or the transfer, sale or other disposition of all or a significant portion of the business, assets or securities of the Company or the recapitalization of interests in one or more subsidiaries or in assets of the Company, whether in one or a series of transactions. However, there can be no assurance that any such initiative or transaction will occur or if it occurs, the timing thereof.

SIB: As mentioned above, subject to and conditional upon closing the ODL recapitalization, the Company intends to commence a substantial issuer bid ("SIB") pursuant to which the Company will offer to purchase up to $65 million of its common shares for cancellation at a fixed price per share.

The Company intends to determine the terms of the SIB, including pricing, in due course, and expects that the SIB will be completed in July 2025. Commencement and/or completion of the SIB would be subject to receipt of a satisfactory liquidity opinion from a qualified financial adviser, approval of the Board of Directors, and obtaining any necessary exemptive relief under applicable securities laws in Canada. The SIB would not be conditional upon any minimum number of shares being tendered and will be subject to conditions customary for transactions of this nature.

NCIB: Frontera expects to commence a normal course issuer bid for its common shares (the "NCIB") following the completion of the SIB. Subject to the acceptance of the TSX, the Company will seek to purchase, for cancellation, up to that number of common shares equal to the greater of (a) 5% of the Company's issued and outstanding common shares, and (b) 10% of the Company's "public float" (as such term is defined in the TSX Company Manual), during the 12-month period following commencement of the NCIB.

Bond Buybacks: In the first quarter 2025, the Company repurchased in the open market $1 million of its 2028 Unsecured Notes for cash, for a total cash consideration of $0.8 million and recognizing a gain of $0.2 million. As a result, the carrying value for the 2028 Unsecured Notes as of March 31, 2025, is $389.0 million.

Bond Capped Cash Tender & Consent Solicitation: As mentioned above, the Company is launching a capped cash tender and consent solicitation in connection with its 2028 Senior Unsecured Notes, pursuant to which the Company will offer to purchase up to $65 million of its 2028 Senior Unsecured Notes.

Simultaneously with the tender offer, Frontera is launching a solicitation of consents from holders of the 2028 Senior Unsecured Notes to effect certain proposed amendments to the indenture governing the 2028 Senior Unsecured Notes dated as of June 21, 2021 (as amended and/or supplemented from time to time, the "Notes Indenture"). The tender offer and consent solicitation will be subject to various conditions, including, without limitation, the condition that the Company shall have obtained debt financing on terms and conditions and yielding net cash proceeds reasonably satisfactory to the Company.

The purpose of the tender offer and consent solicitation is to gain greater financial and operational flexibility while simultaneously reducing the Company's overall debt. Additionally, the proposed amendments shall permit the Company to take certain actions previously limited by certain restrictions in the Notes Indenture, including, but not limited to, allowing for additional restricted payments (including those related to unrestricted subsidiaries), provide additional flexibility in managing working capital to support operational efficiency and financial resilience, increase the amount of permitted indebtedness and liens and reduce conditions and requirements limiting the Company's ability to pursue strategic transactions that may enhance the issuer's growth and value, in each case, without violating the provisions of the Note Indenture. Further details regarding the tender offer and solicitation are expected to be announced later today.

Dividend: Pursuant to Frontera's dividend policy, Frontera's Board of Directors has declared a dividend of C$0.0625 per common share to be paid on or around July 17, 2025, to shareholders of record at the close of business on July 3, 2025.

This dividend payment to shareholders is designated as an "eligible dividend" for purposes of the Income Tax Act (Canada). This dividend is eligible for the Company's Dividend Reinvestment Plan which provides shareholders of Frontera who are resident in Canada with the option to have the cash dividends declared on their common shares reinvested automatically back into additional common shares, without the payment of brokerage commissions or service charges

Frontera's Three Core Businesses

Frontera's three core businesses include: (1) its Colombia and Ecuador Upstream Onshore business, (2) its standalone and growing Colombian Infrastructure business, and (3) its potentially transformational Guyana Exploration business offshore Guyana.

Colombia & Ecuador Upstream Onshore

Colombia

During the first quarter of 2025, Frontera produced 39,010 boe/d from its Colombian operations (consisting of 27,167 bbl/d of heavy crude oil, 9,531 bbl/d of light and medium crude oil, 2,274 mcf/d of conventional natural gas and 1,913 boe/d of natural gas liquids).

In the first quarter of 2025, the Company drilled 13 development wells at the Quifa and CPE-6 blocks in Colombia and completed well interventions at 36 others.

Currently, the Company has 1 drilling rig and 2 intervention rigs active at its Quifa and CPE-6 blocks.

Quifa Block: Quifa SW and Cajua

At Quifa, first quarter 2025 production averaged 16,766 bbl/d of heavy crude oil (including both Quifa and Cajua). The Company invested new and improved flow lines facilities in the Cajua field, to support production for new wells and the connection to Company's reverse osmosis water treatment facility ("SAARA").

In the first quarter 2025, the Company handled an average of approximately 1.67 million barrels of water per day in Quifa including the water handled at SAARA.

CPE-6

At CPE-6, first quarter 2025 production averaged approximately 8,056 bbl/d of heavy crude oil, decreasing from 8,466 bbl/d during the fourth quarter of 2024.

During the first quarter 2025, the Company handled an average of approximately 317 thousand barrels of water per day in CPE-6.

The Company's current water handling capacity in CPE-6 is approximately 360 thousand barrels of water per day.

Other Colombia Developments

At Guatiquia, production during the first quarter 2025 averaged 5,119 bbl/d of light and medium crude compared with 5,690 bbl/d in the fourth quarter of 2024.

In the Cubiro block production averaged 1,213 bbl/d of light and medium crude oil in the first quarter of 2025 compared with 1,310 bbl/d in the fourth quarter 2024.

At VIM-1 (Frontera 50% W.I., non-operator), production averaged 1,840 boe/d of light and medium crude oil in the first quarter of 2025 compared to 1,883 boe/d of light and medium crude oil in the fourth quarter of 2024.

At the Sabanero block, production averaged 2,346 boe/d of heavy oil crude production in the first quarter of 2025 compared to 2,384 boe/d in the fourth quarter of 2024.

Colombia Exploration Assets

During the first quarter of 2025, the Company's exploration focus remained on the Lower Magdalena Valley and Llanos Basins in Colombia. At the Cachicamo block, the Papilio-1 well was spud on December 31, 2024, reaching a total measured depth of 8,580 feet by January 8, 2025. Integration of drilling data and petrophysical interpretation identified 21.5 feet of net pay and well is currently producing approximately 130 boe/d with 97% basic sediment and water (BSW).

The Greta Norte-1 well was drilled on January 18, 2025, and reached a total measured depth of 12,174 feet on February 5, 2025. Integration of drilling data and petrophysical interpretation identified 12.5 feet of net pay, and the well will be plugged and abandoned. At the VIM-1 block, ongoing discussions with authorities and communities to drill the Hidra-1 well during the second half of 2025. At the Llanos 119 Block, the Company has requested the transfer of the remaining exploration commitments to VIM-46 block and subsequent relinquishment.

In addition, the Company is also engaged in pre-seismic and pre-drilling activities related to social and environmental studies in the Llanos-99 and VIM-46 blocks.

Ecuador

In Ecuador, first quarter 2025 production averaged approximately 1,467 bbl/d of light and medium crude oil compared to 1,750 bbl/d in the prior quarter.

At the Espejo block (Frontera holds a 50% W.I. and is a non-operator), the Espejo Sur-B3 well continues its long-term tests with a production of 380 bbl/d gross and a BSW of 73%. The Company still continue to evaluate the development plan.

2. Infrastructure Colombia

Frontera's Infrastructure Colombia Segment includes the Company's 35% equity interest in the ODL pipeline through Frontera's wholly owned subsidiary, PIL and the Company's 99.97% interest in Puerto Bahia. Beginning in 2024, the Infrastructure Colombia Segment also includes SAARA and its palm oil plantation (ProAgrollanos).

Frontera processed 81,481 barrels of water per day at is SAARA reverse osmosis water-treatment facility during the quarter and remains focused on reaching the 250,000 barrels of water per day processed goal. The Company continues to execute on its strategic priorities supporting the long-term growth and sustainability of its businesses.

For Puerto Bahia, the Company's focus remains on starting up the connection project between Puerto Bahia's port facility and the Cartagena refinery (the "Reficar Connection Project"). With construction effectively complete, the Company aims to transport the first volume in the third quarter of 2025. Ongoing strategic investments in the port, including the LPG JV with Empresas Gasco, are progressing as planned. Additionally, the port is also reviewing new investment opportunities that leverage its facilities and infrastructure for profitable long-term growth.

Infrastructure Colombia Segment Results

Adjusted Infrastructure EBITDA in the first quarter of 2025 was $28.6 million, compared with $27.5 million during the fourth quarter of 2024. The increase was mainly due to positive results in the ODL segment driven by the pipeline tariff increase and lower costs during the quarter.

	Three months ended March 31
($M)	2025	2024
Adjusted Infrastructure Revenue (1)	44,912	40,907
Adjusted Infrastructure Operating Cost (1)	(13,116)	(12,138)
Adjusted Infrastructure General and Administrative (1)	(3,193)	(3,082)
Adjusted Infrastructure EBITDA (1)	28,603	25,687

⁽¹⁾ Non-IFRS financial measure (equivalent to a "non-GAAP financial measures", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page [23] of the MD&A or below under the heading "Non-IFRS Financial Measures".

Segment capital expenditures for the three months ended March 31, 2025, were $2.7 million mostly for Puerto Bahia investments by $1.9 million, including: (i) the Reficar Connection Project by $0.8 million, (ii) tank maintenance, and (iii) general cargo terminal facilities. In addition, this includes investment in the SAARA project.

	Three months ended March 31
($M)	2025	2024
Revenue	12,864	10,528
Costs	(8,930)	(8,149)
General and Administrative expenses	(1,507)	(1,479)
Depletion, depreciation and amortization	(2,026)	(1,816)
Restructuring, severance and other costs	(214)	(426)
Infrastructure (loss) income from operations	187	(1,342)
Share of Income from associates - ODL	15,109	13,894
Infrastructure Colombia Segment Income	15,296	12,552
Infrastructure Colombia Segment cash flow from operating activities	25,580	645
Capital Expenditures Infrastructure Colombia segment (1)	2,700	4,556

⁽¹⁾ Non-IFRS financial measures (equivalent to a "non-GAAP financial measures", as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures' section on page 23 of the MD&A or below under the heading "Non-IFRS Financial Measures"

The following table shows the volumes pumped per injection point in ODL:

	Three months ended March 31
(bbl/d)	2025	2024
At Rubiales Station	172,988	167,378
At Jagüey and Palmeras Station	63,399	78,664
Total	236,387	246,042

The following table shows throughput for the liquids port facility at Puerto Bahia:

	Three months ended March 31
(bbl/d)	2025	2024
FEC volumes	8,388	16,647
Third party volumes	43,191	36,713
Total	51,579	53,360

The following table shows the barrels of water per day treated and irrigated in SAARA and field performance indicators for Proagrollanos:

		Three months ended March 31
		2025	2024
Fresh fruit bunch from palm oil (produced - sold)	(tons)	7,684	5,095
Production per hectare per year (1)	(tons/ ha/year)	9.44	6.98
Palm oil fruit price	($/ton)	209	158
Volumes of reverse osmosis water treated	(bwpd)	81,481	33,272
Volumes of water irrigated in palm oil cultivation	(bwpd)	81,609	23,613

⁽¹⁾ Tons per hectare per year for the three months ended March 31, are calculated using the total production for the last twelve months ended March 31.

3. Guyana Exploration

On March 13, 2025, the Company and CGX (the "Joint Venture") announced the receipt of a communication from the Government of Guyana indicating that, on the one hand, the Government was of the view that the Petroleum Prospecting License ("PPL") and Petroleum Agreement are at an end but, on the other hand, that the Government was terminating the Petroleum Agreement and cancelling the PPL.

On March 26, 2025, the Company and its subsidiaries Frontera Petroleum International Holding B.V. and Frontera Energy Guyana Holding Ltd. (the "Investors") sent a notice of intent to the Government of Guyana, by which the Investors alleged breaches of the United Kingdom - Guyana Bilateral Investment Treaty (BIT) and the Guyana Investment Act by the Government of Guyana (the "Notice of Intent"). The Notice of Intent initiated a three-month period for consultations and negotiations between the parties to resolve the dispute amicably.

The Joint Venture remains firmly of the view that its interest in, and the PPL for, the Corentyne block remain in place and in good standing, and continues to invite the Government to amicably resolve the issues affecting the Joint Venture's investments in the Corentyne block. Should the parties not reach a mutually agreeable solution, the Joint Venture and its other stakeholders are prepared to assert their legal rights.

The Joint Venture looks forward to expeditiously resolving this matter and continuing its multi-year efforts and investments to realize value for the people of Guyana and its shareholders from the Corentyne block.

Hedging Update

As part of its risk management strategy, Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company's strategy aims to protect a minimum of 40% of its estimated net after royalties' production with a tactical approach using derivative commodity instruments, to protect the Company's revenue generation and cash position, while maximizing the upside.

The following table summarizes Frontera's hedging position as of May 7, 2025.

Term	Type of Instrument	Positions (bbl/d)	Strike Prices Put/Call
Apr 25	Put	7,400	70
May 25	Put	10,548	70
	Put Spread	6,452	70/55
Jun 25	Put	10,900	70/55
	Put Spread	6,667	70.00
2Q-2025	Total Average	14,022
Jul 25	Put Spread	6,452	70/55
Aug 25	Put Spread	8,387	70/55
3Q-2025	Total Average	5,000

The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of May 7, 2025 the Company had the following foreign currency derivatives contracts:

Term	Type of Instrument	Open Interest (US$ MM)	Strike Prices Put/Call	Hedging Ratio
2Q-2025	Zero Cost Collars	60	4,200/4,626	40 %
3Q-2025	Zero-Cost Collars	60	4,200/4,795	40 %
4Q-2025	Zero-Cost Collars	30	4,295/4,787	20 %

First Quarter 2025 Financial Results Conference Call Details

A conference call for investors and analysts will be held on Monday, May 9, 2025, at 12:00 p.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Rene Burgos, Chief Financial Officer, and other members of the senior management team.

Analysts and investors are invited to participate using the following dial-in numbers:

RapidConnect URL:	https://emportal.ink/42ASyR9
Participant Number (Toll Free North America):	1-888-510-2154
Participant Number (Toll Free Colombia):	[phone]
Participant Number (International):	1-437-900-0527
Conference ID:	12268
Webcast URL:	www.fronteraenergy.ca

A replay of the conference call will be available until 11:59 p.m. Eastern Time on May 16, 2025.

Encore Toll free Dial-in Number:	1-888-660-6345
International Dial-in Number:	1-289-819-1450
Encore ID:	12268

About Frontera:

Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 22 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally and ethically responsible manner.

If you would like to receive News Releases via e-mail as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe.

Social Media

Follow Frontera Energy social media channels at the following links:

Twitter: https://twitter.com/fronteraenergy?lang=en
Facebook: https://es-la.facebook.com/FronteraEnergy/
LinkedIn: https://co.linkedin.com/company/frontera-energy-corp.

Advisories:

Cautionary Note Concerning Forward-Looking Statements

This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, the Company entering into definitive agreements with respect to the ODL recapitalization and the closing of the financing related thereto, the Company's goal of enhancing shareholder value by considering forms of strategic initiatives or transactions, the commencement of a substantial issuer bid and the terms and timing thereof, the commencement of the tender offer and consent solicitation for the 2028 Senior Unsecured Notes and the terms and timing thereof,] the commencement of the NCIB and the terms and timing thereof, the timing of the payment of the dividend, future activities with respect to the Company's Colombia exploration assets, the operational timing of the Reficar Connection Project, the water handling capacity at its SAARA water treatment facility, the Company's exploration and development plans and objectives, production levels, profitability, costs, future income generation capacity, cash levels (including the timing and ability to release restricted cash), regulatory approval, the Company's hedging program and its ability to mitigate the impact of changes in oil prices), and holding the conference call for investors and analysts and the timing thereof are forward-looking statements.

These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: the failure to enter into definitive agreements with respect to the ODL recapitalization and close such transaction, which could prevent or the commencement of the SIB or lead to the termination or withdrawal of the tender offer and solicitation in respect of the 2028 Senior Unsecured Notes; volatility in market prices for oil and natural gas; measures the Company has taken and continues to take or may take in response to pandemics; the newly imposed U.S. trade tariffs affecting over fifty countries and escalating tensions with China; the impact of the Russia - Ukraine conflict and the conflict in the Middle East; actions of the Organization of Petroleum Exporting Countries; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; the Company's ability to complete strategic initiatives or transactions to enhance the value of its common shares and the timing thereof; the Company's ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; political developments in the countries where the Company operates; the uncertainties involved in interpreting drilling results and other geological data; geological, technical, drilling and processing problems; timing on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility; the ability of the Joint Venture to reach an agreement with the Government of Guyana in respect of the Joint Venture's interest in, and the petroleum prospecting license for, the Corentyne block, and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 10, 2025 filed on SEDAR+ at www.sedarplus.ca.

Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.

This news release contains future oriented financial information and financial outlook information (collectively, "FOFI") (including, without limitation, statements regarding expected average production), and are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the Company's activities and results, and such information may not be appropriate for other purposes. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments, however, actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it is made, and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or otherwise, unless required by applicable laws.

Non-IFRS Financial Measures

This press release contains various "non-IFRS financial measures" (equivalent to "non-GAAP financial measures", as such term is defined in NI 52-112), "non-IFRS ratios" (equivalent to "non-GAAP ratios", as such term is defined in NI 52-112), "supplementary financial measures" (as such term is defined in NI 52-112) and "capital management measures" (as such term is defined in NI 52-112), which are described in further detail below. Such measures do not have standardized IFRS definitions. The Company's determination of these non-IFRS financial measures may differ from other reporting issuers and they are therefore unlikely to be comparable to similar measures presented by other companies. Furthermore, these financial measures should not be considered in isolation or as a substitute for measures of performance or cash flows as prepared in accordance with IFRS. These financial measures do not replace or supersede any standardized measure under IFRS. Other companies in our industry may calculate these measures differently than we do, limiting their usefulness as comparative measures.

The Company discloses these financial measures, together with measures prepared in accordance with IFRS, because management believes they provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. These financial measures highlight trends in the Company's core business that may not otherwise be apparent when relying solely on IFRS financial measures. Further, management also uses non-IFRS measures to exclude the impact of certain expenses and income that management does not believe reflect the Company's underlying operating performance. The Company's management also uses non-IFRS measures in order to facilitate operating performance comparisons from period to period and to prepare annual operating budgets and as a measure of the Company's ability to finance its ongoing operations and obligations.

Set forth below is a description of the non-IFRS financial measures, non-IFRS ratios, supplementary financial measures and capital management measures used in the MD&A.

Operating EBITDA

EBITDA is a commonly used non-IFRS financial measure that adjusts net income as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and DD&A. Operating EBITDA is a non-IFRS financial measure that represents the operating results of the Company's primary business, excluding the following items: restructuring, severance and other costs, post-termination obligation, payments of minimum work commitments and, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, and share-based compensation) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA, as they are not indicative of the underlying core operating performance of the Company.

A reconciliation of Operating EBITDA to net loss (income) is as follows:

	Three months ended March 31
($M)	2025	2024
Net loss (income)	27,524	(8,503)
Finance Income	(1,483)	(1,592)
Finance expenses	15,405	17,270
Income tax expense	(9,651)	26,585
Depletion, depreciation and amortization	67,394	65,812
Minimum work commitment paid	-	-
Expense (recovery) of asset retirement obligation	375	(1,042)
Expenses of impairment	1,134	1,027
Trunkline incident costs	2,000	-
Post-termination obligation	297	550
Shared-based compensation	862	286
Restructuring, severance and other cost	1,001	1,803
Share of income from associates	(15,109)	(13,894)
Foreign exchange loss (gain)	(2,239)	1,097
Other loss, net	112	359
Unrealized loss (gain) on risk management contracts	(4,786)	7,939
Realized loss on risk management contract for ODL dividends received	-	-
Non-controlling interests	(127)	(155)
Gain on repurchased 2028 Unsecured Notes	(190)	(294)
Temporal taxes	939	-
Operating EBITDA	83,458	97,248

Capital Expenditures

Capital expenditures is a non-IFRS financial measure that reflects the cash and non-cash items used by the Company to invest in capital assets. This financial measure considers oil and gas properties, plant and equipment, infrastructure, exploration and evaluation assets expenditures which are items reconciled to the Company's Statements of Cash Flows for the period.

	Three months ended March 31
($M)	2025	2024
Consolidated Statements of Cash Flows
Additions to oil and gas properties, infrastructure port, and plant and equipment	42,582	62,849
Additions to exploration and evaluation assets	1,835	2,487
Total additions in Consolidated Statements of Cash Flows	44,417	65,336
Non-cash adjustments (1)	2,328	4,045
Cash adjustments	(34)	-
Total Capital Expenditures	46,711	69,381

⁽¹⁾ Related to materials inventory movements, capitalized non-cash items and other adjustments

Infrastructure Colombia Calculations

Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative, is a non-IFRS financial measure, and each is used to evaluate the performance of the Infrastructure Colombia Segment operations. Adjusted Infrastructure Revenue includes revenues of the Infrastructure Colombia Segment including ODL's revenue direct participation interest. Adjusted Infrastructure Operating Costs includes costs of the Infrastructure Colombia Segment including ODL's cost direct participation interest. Adjusted Infrastructure General and Administrative includes general and administrative costs of the Infrastructure Colombia Segment including ODL's general and administrative direct participation interest.

A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative is provided below.

	Three months ended March 31
($M)	2025	2024
Revenue Infrastructure Colombia Segment	12,864	10,528
Revenue from ODL	91,566	86,797
Direct participation interest in the ODL	35 %	35 %
Equity adjustment participation of ODL (1)	32,048	30,379
Adjusted Infrastructure Revenues	44,912	40,907
Operating Cost Infrastructure Colombia Segment	(8,930)	(8,149)
Operating Cost from ODL	(11,959)	(11,396)
Direct participation interest in the ODL	35 %	35 %
Equity adjustment participation of ODL (1)	(4,186)	(3,989)
Adjusted Infrastructure Operating Costs	(13,116)	(12,138)
General and administrative Infrastructure Colombia Segment	(1,507)	(1,479)
General and administrative from ODL	(4,818)	(4,581)
Direct participation interest in the ODL	35 %	35 %
Equity adjustment participation of ODL (1)	(1,686)	(1,603)
Adjusted Infrastructure General and Administrative	(3,193)	(3,082)

⁽¹⁾ Revenues and expenses related to ODL are accounted for using the equity method, as described in Note 12 of the Interim Condensed Consolidated Financial Statements.

Adjusted Infrastructure EBITDA

The Adjusted Infrastructure EBITDA is a non-IFRS financial measure used to assist in measuring the operating results of the Infrastructure Colombia Segment business.

	Three months ended March 31
($M)	2025	2024
Adjusted Infrastructure Revenue (1)	44,912	40,907
Adjusted Infrastructure Operating Cost (1)	(13,116)	(12,138)
Adjusted Infrastructure General and Administrative (1)	(3,193)	(3,082)
Adjusted Infrastructure EBITDA (1)	28,603	25,687

⁽¹⁾ Non-IFRS financial measure

Net Sales

Net sales is a non-IFRS financial measure that adjusts revenue to include realized gains and losses from oil risk management contracts while removing the cost of any volumes purchased from third parties. This is a useful indicator for management, as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these oil risk management activities. The deduction of cost of purchases is helpful to understand the Company's sales performance based on the net realized proceeds from its own production, the cost of which is partially recovered when the blended product is sold. Net sales also exclude sales from port services, as it is not considered part of the oil and gas segment. Refer to the reconciliation in the "Sales" section on page 10 of the MD&A.

Operating Netback and Oil and Gas Sales, Net of Purchases

Operating netback is a non-IFRS financial measure and operating netback per boe is a non-IFRS ratio. Operating netback per boe is used to assess the net margin of the Company's production after subtracting all costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel and is an indicator of how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of any trading activities and results from its Infrastructure Colombia Segment from the per barrel metrics and adds the effects attributable to transportation and operating costs of any realized gain or loss on foreign exchange risk management contracts. Refer to the reconciliation in the "Operating Netback" section on page 9 of the MD&A.

The following is a description of each component of the Company's operating netback and how it is calculated. Oil and gas sales, net of purchases, is a non-IFRS financial measure that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining costs. Oil and gas sales, net of purchases per boe, is a non-IFRS ratio that is calculated using oil and gas sales, net of purchases, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below:

	Three months ended March 31
	2025	2024
Purchased crude oil and products sales ($M)(1)	209,627	209,043
Purchase crude net margin ($M)	(11,652)	(8,269)
Oil and gas sales, net of purchases ($M)	197,975	200,774
Sales volumes, net of purchases - (boe)	3,063,960	2,746,835
Produced crude oil and gas sales ($/boe)	68.42	76.10
Oil and gas sales, net of purchases ($/boe)	64.61	73.09

⁽¹⁾ Excludes sales from infrastructure services, as they are not part of the oil and gas segment. Refer to the "Infrastructure Colombia" section on page 18 for further details.

Non-IFRS Ratios

Realized oil price, net of purchases, and realized gas price per boe

Realized oil price, net of purchases, and realized gas price per boe are both non-IFRS ratios. Realized oil price, net of purchases, per boe is calculated using oil sales net of purchases, divided by total sales volumes, net of purchases. Realized gas price is calculated using sales from gas production divided by the conventional natural gas sales volumes.

	Three months ended March 31
	2025	2024
Oil and gas sales, net of purchases ($M) (1)	197,975	200,774
Crude oil sales volumes, net of purchases - (bbl)	3,032,796	2,694,482
Conventional natural gas sales volumes - (mcf)	177,756	298,144
Realized oil price, net of purchases ($/bbl)	64.95	73.82
Realized conventional natural gas price ($/mcf)	5.61	6.26

(1) Non-IFRS financial measure.

Net sales realized price

Net sales realized price is a non-IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts and less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below:

	Three months ended March 31
($M)	2025	2024
Oil and gas sales, net of purchases ($M) (1)	197,975	200,774
(-) Premiums paid on oil price risk management contracts ($M)	(4,141)	(3,489)
(-) Royalties ($M)	(3,060)	(4,506)
Net Sales ($M)	190,774	192,779
Sales volumes, net of purchases (boe)	3,063,960	2,746,835
Oil and gas sales, net of purchases ($/boe)	64.61	73.09
Premiums paid on oil price risk management contracts ($/boe) (2)	(1.35)	(1.27)
Royalties ($/boe) (2)	(1.00)	(1.64)
Net sales realized price ($/boe)	62.26	70.18

⁽¹⁾ Non-IFRS financial measure.

⁽²⁾ Supplementary financial measure.

Purchase crude net margin

Purchase crude net margin is a non-IFRS financial measure that is calculated using the purchased crude oil and products sales, less the cost of those volumes purchased from third parties including its transportation and refining costs. Purchase crude net margin per boe is a non-IFRS ratio that is calculated using the Purchase crude net margin, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below:

	Three months ended March 31
	2025	2024
Purchased crude oil and products sales ($M)	57,363	51,285
(-) Cost of diluent and oil purchases ($M) (1)	(68,860)	(57,859)
Puerto Bahía inter-segment costs(2)	(155)	(1,695)
Purchase crude net margin ($M)	(11,652)	(8,269)
Sales volumes, net of purchases - (boe)	3,063,960	2,746,835
Purchase crude net margin ($/boe)	(3.81)	(3.01)

⁽¹⁾ Cost of third-party volumes purchased for use and resale in the Company's oil operations, including its transportation and refining costs.

⁽²⁾ 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahía inter-segment costs related to diluent and oil purchases as well as transportation costs.

Production costs (excluding energy cost), net of realized FX hedge impact, and production cost (excluding energy cost), net of realized FX hedge impact per boe

Production costs (excluding energy cost), net of realized FX hedge impact is a non-IFRS financial measure that mainly includes lifting costs, activities developed in the blocks, processes to put the crude oil and gas in sales condition and the realized gain or loss on foreign exchange risk management contracts attributable to production costs. Production cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using production cost (excluding energy cost), net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:

	Three months ended March 31
	2025	2024
Production costs (excluding energy cost) ($M)	35,679	36,839
(-) Realized gain on FX hedge attributable to production costs (excluding energy cost) ($M) (1)	-	(1,337)
Inter-segment costs	913	-
Production costs (excluding energy cost), net of realized FX hedge impact ($M) (2)	36,592	35,502
Production (boe)	3,642,930	3,475,563
Production costs (excluding energy cost), net of realized FX hedge impact ($/boe)	10.04	10.21

⁽¹⁾ See "(Loss) Gain on Risk Management Contracts" on page 13 of the MD&A.

⁽²⁾ Non-IFRS financial measure.

Energy costs, net of realized FX hedge impact, and production cost, net of realized FX hedge impact per boe

Energy costs, net of realized FX hedge impact is a non-IFRS financial measure that describes the electricity consumption and the costs of localized energy generation and the realized gain or loss on foreign exchange risk management contracts attributable to energy costs. Energy cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using energy cost, net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:

	Three months ended March 31
	2025	2024
Energy costs ($M)	19,584	18,968
(-) Realized gain on FX hedge attributable to energy costs ($M) (1)	-	(581)
Energy costs, net of realized FX hedge impact ($M) (2)	19,584	18,387
Production (boe)	3,642,930	3,475,563
Energy costs, net of realized FX hedge impact ($/boe)	5.38	5.29

⁽¹⁾ See "(Loss) Gain on Risk Management Contracts" on page 13 of the MD&A.

⁽²⁾ Non-IFRS financial measure.

Transportation costs, net of realized FX hedge impact, and transportation costs, net of realized FX hedge impact per boe

Transportation costs, net of realized FX hedge impact is a non-IFRS financial measure, that includes all commercial and logistics costs associated with the sale of produced crude oil and gas such as trucking and pipeline, and the realized gain or loss on foreign exchange risk management contracts attributable to transportation costs. Transportation cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using transportation cost, net of realized FX hedge impact divided by net production after royalties. A reconciliation of this calculation is provided below:

	Three months ended March 31
	2025	2024
Transportation costs ($M)	39,549	35,195
(-) Realized gain on FX hedge attributable to transportation costs ($M) (1)	-	(409)
Puerto Bahía inter-segment costs(2)	636	431
Transportation costs, net of realized FX hedge impact ($M) (2)(3)	40,185	40,185
Net Production (boe)	3,262,950	3,070,613
Transportation costs, net of realized FX hedge impact ($/boe)	12.32	11.47

⁽¹⁾ See "(Loss) Gain on Risk Management Contracts" on page 13 of the MD&A.

⁽²⁾ 2024 prior period figures are different compared with those previously reported as a result as a result of the inclusion of Puerto Bahia inter-segment costs related to cost of diluent and oil purchased, and transportation cost.

⁽³⁾ Non-IFRS financial measure.

Supplementary Financial Measures

Realized (loss) gain on oil risk management contracts per boe

Realized (loss) gain on oil risk management contracts includes the gain or loss during the period, as a result of the Company's exposure in derivative contracts of crude oil. Realized (loss) gain on oil risk management contracts per boe is a supplementary financial measure that is calculated using Realized (loss) gain on risk management contracts divided by total sales volumes, net of purchases.

Royalties per boe

Royalties includes royalties and amounts paid to previous owners of certain blocks in Colombia and cash payments for PAP. Royalties per boe is a supplementary financial measure that is calculated using the royalties divided by total sales volumes, net of purchases.

Capital Management Measures

Restricted cash short- and long-term

Restricted cash (short- and long-term) is a capital management measure, that sums the short-term portion and long-term portion of the cash that the Company has in term deposits that have been escrowed to cover future commitments and future abandonment obligations, or insurance collateral for certain contingencies and other matters that are not available for immediate disbursement.

Total cash

Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available, is comprised by the cash and cash equivalents and the restricted cash short and long-term.

Total debt and lease liabilities

Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company and is comprised of the debt of the 2028 Unsecured Notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets.

Definitions:

bbl(s)	Barrel(s) of oil
bbl/d	Barrel of oil per day
boe	Refer to "Boe Conversion" disclosure above
boe/d	Barrel of oil equivalent per day
Mcf	Thousand cubic feet
Net Production	Net production represents the Company's working interest volumes, net of royalties and internal consumption

www.fronteraenergy.ca

SOURCE Frontera Energy Corporation