FRONTERA ANNOUNCES FOURTH QUARTER 2025, YEAR-END 2025 RESULTS AND RESERVES

Mar 18 2026 04:19 BST

Special Meeting of Shareholders to Approve Colombian E&P Divestiture to Parex on April 30, 2026

Recorded Fourth-Quarter Net Loss from Continuing Operations of $663 Million, Including Non‑Cash Impairment Related to the Divestment of the Colombian E&P Assets Portfolio ($603 million) and the Guyana Interest ($17 Million)

Strong Business Performance, Achieved All 2025 Guidance Metrics, Including FY 2025 Average Production of 39,011 boed, Operating EBITDA of $308 Million, Production of $9.23/boe, Energy of $5.49/boe and Transportation Costs of $12.00/boe

Year-End Gross Reserves: 94.4 Million Boe 1P and 133.8 Million Boe 2P

Definitive Agreement Signed to Divest the Company's Colombian E&P Assets Portfolio for a Firm Value of Approximately $750 Million with Parex, Including $525 Million in Equity Consideration

Targeting $470 Million in Shareholder Distributions from the Sale, (Approximately CAD $9.18 per share), Including the $25 Million Contingent Payment

Frontera Emerges as a New Infrastructure-Focused Business Anchored by its Interest in ODL and Puerto Bahía, and with Significant Growth Opportunities Including the Potential LNG Regasification Project with Ecopetrol

Full Year Adjusted Infrastructure EBITDA of $116.6 million, Distributable Cash Flow of $76.7 million and Segment Income of $40.9 million, Led by Strong Performance of the ODL Pipeline

CALGARY, AB , March 18, 2026 /CNW/ - Frontera Energy Corporation (TSX: FEC) (OTCQX: FECCF) ("Frontera" or the "Company") today reported financial and operational results for the fourth quarter and year ended December 31, 2025, and the results of its annual independent reserves assessment conducted by DeGolyer and MacNaughton Corp ("D&M"). Figures from previous reporting periods were changed due to the re-presentation of continuing operations following the divestment of non-core assets in Ecuador. Refer to the "Discontinued Operations" section of the interim management's discussion and analysis for the three and twelve months ended December 31, 2025 dated March 17, 2026 (the "MD&A") for further details.

Due to the pending shareholder vote in respect of the previously announced arrangement with Parex Resources Inc., the Company will not host a conference call in connection with its fourth quarter and full year 2025 results.

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

"2025 was a year of decisive execution and disciplined capital allocation, as Frontera delivered on its commitments and strengthened its financial position. The Company generated $308 million of Operating EBITDA and closed the year with $242 million of cash, providing a strong foundation to execute on its strategic priorities.

Following year-end, Frontera entered into a definitive arrangement with Parex for the divestment of its Colombian E&P assets, marking the successful culmination of a multi-year, comprehensive strategic process. This transaction crystallizes a $125 million increase in cash consideration to shareholders—a 31% improvement over the GeoPark outcome—while preserving significant long-term upside through our Infrastructure platform and retained assets.

Throughout this process, the Board remained focused on a clear objective: maximizing long-term shareholder value through disciplined evaluation, thoughtful engagement with counterparties, and careful stewardship of the Company's strategic options. The outcome reflects both the intrinsic quality of our team, assets and the strength of our positioning.

With this transaction, Frontera completes its transition into a focused infrastructure platform anchored by its interests in ODL and Puerto Bahía—high-quality assets that generate stable cash flows and offer attractive growth opportunities.

Subject to closing, the Company expects to return approximately $470 million to shareholders, representing a substantial return of capital, while retaining the financial flexibility to invest in high-conviction growth initiatives, including its LNG regasification project with Ecopetrol.

In total, this strategy will have unlocked approximately $1.3 billion of capital for shareholders. Frontera now enters its next phase as a more focused, cash-generative infrastructure company, well positioned to deliver durable returns and continued value creation."

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

"In 2025, Frontera successfully generated positive results, continued to maintain operational flexibility, drive cost efficiencies, prioritize operational improvements and maintain a strong balance sheet, and as a result, achieving all the 2025 guidance metrics targets.

In our infrastructure business, we delivered another year of strong results. ODL transported almost 239,000 bbl/d while generating approximately $300.0 million in full-year consolidated EBITDA (approximately $105 million attributable to Frontera based on its 35% equity interest). Through our equity interest in the pipeline, we received more than $62 million in cash distributions. Puerto Bahia generated approximately $15 million in operating EBITDA, broadly flat year-over-year, and setting the basis for growth in key dry terminal areas, including increased container activity, offsetting lower volumes from our liquids terminal.

Looking ahead, Frontera will emerge as a newly focused infrastructure business, which will be the backbone of our post-transaction Frontera. Our Infrastructure Business generated 2025 Adjusted Infrastructure EBITDA and Distributable Cash Flows totaling $116.6 million and $76.7 million, respectively, supported by a stable dividend stream from ODL and an attractive growth profile at Puerto Bahía. Key growth initiatives include LPG import facilities, a potential LNG regasification project and containerized cargo expansion. The LPG project is expected to achieve an early start-up later in March, and emerging opportunities like the LNG regasification project, supported by a binding take‑or‑pay agreement with Ecopetrol, with an initial capacity of approximately 126 MMcfd, anticipated to increase to at least 300 MMcfd by 2029, shall continue to drive growth into 2026 and beyond."

Fourth Quarter / Full Year 2025 Operational and Financial Summary:

					Year ended December 31
		Q4 2025	Q3 2025	Q4 2024	2025	2024
Operational Results from Continuing Operations
Heavy crude oil production ⁽¹⁾	(bbl/d)	26,696	27,078	27,740	27,118	25,328
Light and medium crude oil combined production ⁽¹⁾	(bbl/d)	8,918	9,235	10,484	9,381	10,882
Total crude oil production	(bbl/d)	35,614	36,313	38,224	36,499	36,210

Conventional natural gas production ⁽¹⁾	(mcf/d)	5,261	4,406	2,633	3,773	3,278
Natural gas liquids production ⁽¹⁾	(boe/d)⁽³⁾	1,795	1,848	1,970	1,850	1,838

Total production Colombia⁽²⁾	(boe/d)⁽³⁾	38,332	38,934	40,656	39,011	38,623

Total inventory balance of Colombia and Peru	(bbl)	860,362	919,914	1,029,466	860,362	981,978

Brent price reference	($/bbl)	63.08	68.17	74.01	68.19	81.82

Produced crude oil and gas sales ⁽⁴⁾	($/boe)	59.52	64.40	67.31	63.86	72.95
Purchased crude net margin ⁽⁴⁾⁽⁵⁾	($/boe)	(2.27)	(2.70)	(3.55)	(3.12)	(3.25)

Oil and gas sales, net of purchases ⁽⁴⁾⁽⁵⁾	($/boe)	57.25	61.70	63.76	60.74	69.70
(Loss) gain on oil price risk management contracts ⁽⁶⁾⁽⁷⁾	($/boe)	(0.38)	(1.20)	0.08	(0.72)	(0.72)
Royalties ⁽⁶⁾	($/boe)	(0.73)	(0.78)	(0.80)	(0.79)	(1.26)

Net sales realized price ⁽⁴⁾⁽⁵⁾	($/boe)	56.14	59.72	63.04	59.23	67.72

Production costs (excluding energy costs), net of realized FX hedge impact ⁽⁴⁾	($/boe)	(9.64)	(8.46)	(7.60)	(9.23)	(9.39)
Energy costs, net of realized FX hedge impact ⁽⁴⁾	($/boe)	(6.22)	(5.56)	(5.46)	(5.49)	(5.26)
Transportation costs, net of realized FX hedge impact ⁽⁴⁾⁽⁵⁾	($/boe)	(11.92)	(11.72)	(11.59)	(12.00)	(11.80)

Operating netback from Continuing Operations per boe ⁽⁴⁾⁽⁵⁾	($/boe)	28.36	33.98	38.39	32.51	41.27

Financial Results
Oil & gas sales, net of purchases ⁽⁸⁾	($M)	177,038	194,153	207,518	727,544	815,993
(Loss) gain on oil price risk management contracts ⁽⁷⁾	($M)	(1,186)	(3,784)	253	(8,680)	(8,457)
Royalties	($M)	(2,241)	(2,454)	(2,599)	(9,448)	(14,704)

Net sales ⁽⁸⁾	($M)	173,611	187,915	205,172	709,416	792,832

Net (loss) income for the period from continuing operations ⁽⁹⁾	($M)	(663,354)	28,235	(20,485)	(1,020,361)	(18,628)
Net income (loss) for the period from discontinued operations	($M)	2,905	(2,818)	(8,916)	(42,359)	(5,534)
Net (loss) income for the period ⁽⁹⁾	($M)	(660,449)	25,417	(29,401)	(1,062,720)	(24,162)
Per share – diluted from continuing operations	($)	(9.51)	0.38	(0.25)	(13.77)	(0.22)
Per share – diluted from discontinued operations	($)	0.04	(0.04)	(0.11)	(0.57)	(0.07)

General and administrative	($M)	15,898	14,877	11,820	58,174	50,292

Outstanding Common Shares	Number of Shares	69,530,049	69,833,514	80,793,387	69,530,049	80,793,387

Operating EBITDA from continuing operations ⁽⁸⁾	($M)	68,907	86,585	109,620	308,029	405,118

Cash provided by operating activities	($M)	195,486	115,034	168,691	422,443	508,152

Capital expenditures ⁽⁸⁾	($M)	53,247	50,859	84,544	209,193	290,684

Cash and cash equivalents – unrestricted	($M)	230,489	158,614	192,577	230,489	192,577
Restricted cash short and long-term ⁽¹⁰⁾	($M)	11,320	13,437	30,249	11,320	30,249
Total cash ⁽¹⁰⁾	($M)	241,809	172,051	222,826	241,809	222,826

Total debt and lease liabilities ⁽¹⁰⁾	($M)	493,909	532,789	506,037	493,909	506,037
Consolidated total indebtedness (excluding Unrestricted Subsidiaries) ⁽¹¹⁾	($M)	429,256	357,228	414,481	429,256	414,481
Net debt (excluding Unrestricted Subsidiaries) ⁽¹¹⁾	($M)	219,531	252,640	277,298	219,531	277,298

* Figures from previous reporting periods were changed due to the re-presentation of continuing operations following the divestment of non-core assets in Ecuador. Refer to the "Discontinued Operations" section on page 21 of the MD&A for further details.

⁽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 MD&A refer to 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 W.I. production before royalties. Refer to the "Further Disclosures" section on page 48 of the MD&A for further details.

⁽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 48 of the MD&A for further details.

⁽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 31 of the MD&A for further details.

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

⁽⁶⁾ Supplementary financial measures (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 31 of the MD&A for further details.

⁽⁷⁾ Includes the net effect of put premiums paid for expired positions and positive cash settlements received from oil price contracts during the period. Refer to the "Gain (Loss) on Risk Management Contracts" section on page 20 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 31 of the MD&A for further details.

⁽⁹⁾ Capital management measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 31 of the MD&A for further details.

⁽¹⁰⁾ " 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 37 of the MD&A for further details.

Fourth Quarter and Full Year 2025 Operational and Financial Results:

During the fourth quarter of 2025, the Company reported net loss from continuing operations, attributable to equity holders of the Company, of $663.4 million mainly resulting from a loss from operations of $636.6 million (net of a non-cash impairment expense of $620.4 million), an income tax expense of $21.5 million (including $28.2 million of deferred income tax expenses), finance expenses of $18.9 million and foreign exchange loss of $4.4 million, partially offset by $14.1 million from share of income from associates, $3.3 million related to income on risk management contracts and $1.4 million of finance income. This compares with net loss from continuing operations, attributable to equity holders of the Company, in the fourth quarter of 2024, of $20.5 million, which included an income tax expense of $35.6 million (including $36.4 million of deferred income tax expenses), finance expenses of $21.5 million, $8.9 million related to loss on risk management contracts, and foreign exchange loss of $1.8 million, partially offset by income from operations of $25.5 million (net of a non cash impairment expense of $18.2 million) and $13.2 million from the share of income from associates.

Total Colombian production averaged 38,332 boe/d in the fourth quarter of 2025, compared with 38,934 boe/d in the prior quarter and compared with 40,656 boe/d in the fourth quarter of 2024. Production decreased mainly due to (i) a 4% and 1% decline in heavy crude oil production, respectively, resulting from equipment and well failures in heavy oil fields, and community blockades in the Sabanero block, and (ii) light and medium crude oil combined, and natural gas liquids production decreased mainly due to natural decline. These were partially offset by increases in conventional natural gas production driven by the commercialization of natural gas volumes from the VIM-1 block. Frontera's production averaged 39,011 boe/d, within the Company's guidance of 39,000 - 39,500 boe/d.

		Production
					Year ended December 31
Production from Continuing Operations:		Q4 2025	Q3 2025	Q4 2024	2025	2024
Producing blocks in Colombia
Heavy crude oil	(bbl/d)	26,696	27,078	27,740	27,118	25,328
Light and medium crude oil combined	(bbl/d)	8,918	9,235	10,484	9,381	10,882
Conventional natural gas	(mcf/d)	5,261	4,406	2,633	3,773	3,278
Natural gas liquids	(boe/d)	1,795	1,848	1,970	1,850	1,838
Total production Colombia	(boe/d)	38,332	38,934	40,656	39,011	38,623

Production from Discontinued Operations ⁽¹⁾ :
Producing blocks in Ecuador
Light and medium crude oil combined	(bbl/d)	848	940	1,750	1,131	1,665
Total production Ecuador	(bbl/d)	848	940	1,750	1,131	1,665

⁽¹⁾ Refer to the "Discontinued Operations" section on page 19 of the MD&A for further details.

Operating EBITDA from continuing operations was $68.9 million in the fourth quarter of 2025, compared with $86.6 million in the prior quarter and $109.6 million in the fourth quarter of 2024. The quarter-over-quarter decrease was primarily due to lower Brent oil prices, an increase in production cost (excluding energy costs) and transportation costs. Frontera's weighted average oil price was $68.13/bbl in 2025, generating $308.0 million of EBITDA within the Company's guidance.

Cash provided by operating activities reported was $195.5 million in the fourth quarter of 2025 ($116.5 million, excluding the $80 millionChevron prepayment), compared with $115.0 million in the prior quarter, and $168.7 million in the fourth quarter of 2024. During the quarter, the Company invested $53.2 million in capital expenditures, and received cash dividends of $12.2 million and a cash return of capital of $4.6 million from Oleoducto de los Llanos Orientales S.A. ("ODL").

The Company reported a total cash position of $241.8 million at December 31, 2025, compared with $172.1 million at September 30, 2025, and $222.8 million at December 31, 2024. The Company generated $422.4 million of cash from operations in 2025, compared to $508.1 million in 2024. During the year, the Company invested $209.2 million of capital expenditures, and $4 million to repurchase senior notes.

As at December 31, 2025, the Company had a total crude oil inventory balance of 860,362 barrels compared to 919,914 barrels at September 30, 2025. The Company had a total inventory balance in Colombia of 380,162 barrels, including 242,912 crude oil barrels and 137,162 barrels of diluent and others. This compared to 439,714 barrels as at September 30, 2025, and 501,778 barrels as at December 31, 2024. The decrease in inventory levels was associated with higher volumes of oil inventory sold during the quarter.

Capital expenditures were $53.2 million in the fourth quarter of 2025, compared with $50.9 million in the prior quarter and $84.5 million in the fourth quarter of 2024. During the fourth quarter the Company spudded 3 development wells and drilled the Guapo-1 exploration well in the VIM-1 block. Total capital expenditures executed for the year were $209.1 million, within the Company's guidance of $200 - $223 million.

The Company's net sales realized price was $56.14/boe in the fourth quarter of 2025, compared to $59.72/boe in the prior quarter and $63.04/boe in the fourth quarter of 2024. The decrease was primarily driven by a lower Brent oil price, partially offset by better oil price differentials and lower cash royalties paid. The Company's net sales realized price in 2025 was $59.23/boe compared to $67.72/boe in 2024.

The Company's operating netback from continuing operations was $28.36/boe in the fourth quarter of 2025, compared with $33.98/boe in the prior quarter and $38.39/boe in the fourth quarter of 2024. The Company's operating netback decrease quarter-over-quarter was a result of lower net sales realized prices, and an increase in production costs (excluding energy cost) and transportation costs. The Operating netback for the year ended December 31, 2025, was $32.51/boe, compared to $41.27/boe in 2024.

Production costs (excluding energy costs), net of realized FX hedge impact, averaged $9.64/boe in the fourth quarter of 2025, compared with $8.46/boe in the prior quarter and $7.60/boe in the fourth quarter of 2024. Production costs increase was primarily driven by higher well service activity and the impact of the strong Colombian peso. Production costs (excluding energy costs), net of realized FX hedge impact for the year was $9.23/boe within the Company's guidance of $8.75 - $9.25/boe.

Energy costs, net of realized FX hedging impacts, averaged $6.22/boe in the fourth quarter of 2025, compared to $5.56/boe in the prior quarter and up from $5.46/boe in the fourth quarter of 2024. The increase quarter over quarter was mainly due to higher fuel consumption resulting from higher processed production liquid volumes and the impact of the strong Colombian peso. Energy costs, net of realized FX hedge impact for the year was $5.49/boe within the Company's guidance of $5.25 - $5.75/boe.
Transportation costs, net of realized FX hedging impacts averaged $11.92/boe in the fourth quarter of 2025, compared with $11.72/boe in the prior quarter and $11.59/boe in the fourth quarter of 2024. The increase in transportation costs during the quarter was mainly driven by increased transported volumes resulting from inventory drawdown. Transportation costs, net of realized FX hedge impact for the year was $12.00/boe below the Company's guidance of $12.50 - $13.00/boe.

Frontera Infrastructure Fourth Quarter and Full Year 2025 Operational and Financial Results:

ODL volumes transported were 241,734 bbl/d during the fourth quarter of 2025, in line with the previous quarter, which saw 241,958 bbl/d in volumes transported. During the year 2025, ODL transported an average of 238,994 bbl/d.

Total Puerto Bahia liquids volumes were 40,548 bbl/d during the quarter compared to 39,560 bbl/d the previous quarter. In the fourth quarter of 2025, lower third-party liquids volumes reflected reduced throughput from key customers and the absence of certain trading flows, partially offset by strong performance in the dry port. During 2025, Puerto Bahia had higher revenues from roll-on/ roll-off (RoRo), containerized cargo, and general cargo, supported by volume growth and tariff adjustments.

Adjusted Infrastructure EBITDA, including $0.4 million of negative Adjusted Infrastructure EBITDA related to ProAgrollanos and SAARA activities, which will be divested as part of the Parex transaction, in the quarter was $30.5 million, compared to $30.4 million in the prior quarter. EBITDA in the fourth quarter was driven by higher EBITDA from Puerto Bahia, mainly due to higher throughput for the liquids and container volumes handled at the port, partially offset by higher costs in ODL. Adjusted Infrastructure EBITDA for the year was $116.6 million, including $3.4 million of negative Adjusted Infrastructure EBITDA related to ProAgrollanos and SAARA activities.
Capital expenditures for the three months ended December 31, 2025, totaled $2.8 million primarily driven by investments totaling $1.7 million made in Puerto Bahia, including: (i) $0.9 million towards the connection project between Puerto Bahia's port facility and the Cartagena refinery, (ii) tank maintenance, and (iii) general expenditures related to the cargo terminal facilities. Fourth quarter capital expenditures also included investment in the SAARA project and palm oil plantation.
Puerto Bahía secured a take‑or‑pay agreement with Ecopetrol, subject to certain conditions precedent, to develop an LNG regasification project in early 2026. The project is expected to benefit from Puerto Bahía's existing and robust port facilities and operating platform, including the repurposing of the Reficar connection to transport natural gas, enabling an accelerated development timeline and faster time‑to‑market. The project contemplates two phases, with an initial regasification capacity of approximately 126 MMcfd, anticipated to increase to at least 300 MMcfd by 2029, providing integrated logistics and regasification services to Reficar and the Colombian Natural Gas Transportation System (SNT).

2025 Year End Reserves Evaluation

Frontera announced the results of its annual independent reserves assessment for the year ended December 31, 2025, conducted by D&M in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter) (the "COGE Handbook"), National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and CSA Staff Notice 51-324, and are based on the Reserves Report (as defined below). All of the Company's booked reserves for the year ended December 31, 2025 are located in Colombia.

The following tables provide a summary of the Company's oil and natural gas reserves based on forecast prices and costs effective December 31, 2025, as applied in the Reserves Report. The Company's net reserves after royalties at December 31, 2025, incorporate all applicable royalties under Colombia fiscal legislation based on forecast pricing and production rates evaluated in the Reserves Report, including any additional participation interest related to the price of oil applicable to certain Colombian blocks, as at year-end 2025.

2025 Year-End D&M Certified Gross Reserves Volumes ⁽¹⁾

Reserve Category	December 31, 2025 Mboe ⁽²⁾	December 31, 2024 Mboe ⁽²⁾	Percentage Change 2025 versus 2024
Proved Developed Producing (PDP)	29.3	36.7	(20) %
Proved Developed Non-Producing (PDNP)	9.5	7.6	25 %
Proved Undeveloped (PUD)	55.6	56.3	(1) %
Total Proved (1P)	94.4	100.6	(6) %
Probable	39.5	50.7	(22) %
Total Proved plus Probable (2P)	133.8	151.3	(12) %
Possible⁽³⁾	25.9	33.2	(22) %
Total Proved Plus Probable Plus Possible (3P)	159.7	184.6	(13) %

⁽⁷⁾ Gross reserves represent Frontera's W.I. before royalties

⁽⁸⁾ See "Boe Conversion" section in the "Advisories" section, at the end of this press release.

⁽⁸⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Reserves Reconciliation

	Oil Equivalent Gross 2P Reserves (MMboe) ⁽¹⁾⁽²⁾
December 31, 2024	151.3
Discoveries	0
Extensions & Improved Recovery	0
Technical Revisions⁽³⁾	3.5
Acquisitions	0
Dispositions ⁽⁴⁾	(5.4)
Economic Factors	(1.5)
Production⁽⁵⁾	(14.2)
December 31, 2025	133.8

⁽¹⁾ See "Boe Conversion" section in the "Advisories" section, at the end of this press release.

⁽²⁾ Gross refers to Frontera's W.I. before royalties. Net refers to Frontera's W.I. after royalties.

⁽³⁾ Includes technical revisions mainly in the CPE-6 block, Quifa block, Cubiro block, VIM-1 block and the Guatiquia block.

⁽⁴⁾ Mainly associated with the planned disposition of the Caruto, Corcel E, Cernícalo, Petirrojo, Petirrojo Sur, Tijereto Sur and Entrerríos fields in Colombia and Perico and Espejo blocks in Ecuador.

⁽⁵⁾ Production represents the Company's production for the twelve-month period ended December 31, 2025, for asset with associated reserves.

N et Present Value of Future Revenue Before Tax Summary - D&M Reserves Report (2025 Brent Forecast) ⁽¹⁾

Reserves Category	December 31, 2024	December 31, 2025	December 31, 2025
$(000's), except per share data	NPV10 ($ 000's) ⁽²⁾	NPV10 ($ 000's) ⁽³⁾	NPV10 (C$/share) ⁽⁴⁾
Proved Developed Producing (PDP)	942,785	607,902	12.00
Proved Developed Non-Producing (PDNP)	187,260	224,892	4.44
Proved Undeveloped	1,130,849	719,063	14.19
Total Proved (1P)	2,260,895	1,551,857	30.63
Probable	1,129,008	732,608	14.46
Total Proved Plus Probable (2P)	3,389,903	2,284,464	45.09
Possible⁽⁵⁾	718,012	527,254	10.41
Total Proved Plus Probable Plus Possible (3P)	4,107,915	2,811,718	55.50

⁽¹⁾ See "Advisories" at the end of this press release. The Reserves Report

⁽²⁾ Includes Future development costs ("FDC") as at December 31, 2024, of $658 million of 1P and $1,023 million for 2P

⁽³⁾ Includes FDC as at December 31, 2025, of $812,844 million for 1P and $1,196,953 million for 2P

⁽⁴⁾ Calculated by dividing the December 31, 2025 NPV10 value by 69,530,049shares outstanding as at December 31, 2025 and a USD:CAD foreign exchange rate of 1.37245. Per share valuations do not attribute any value to the Company's material ownership in infrastructure assets as well as any equity value for its ownership in CGX Energy Inc. (TSXV:OYL) ("CGX")

⁽⁵⁾ Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Frontera's Sustainability Strategy

Frontera met all its 2025 sustainability targets and is progressing with its 2028 Sustainability Strategy.

On environmental achievements:

The Company neutralized 50% of all 2025 emissions
A total of 70,162 tons of CO2 equivalent were absorbed from our environmental compensation areas
35% of Frontera's operational water was reused

Regarding the Company's social contributions:

Frontera achieved its best Total Recordable Incident Rate (TRIR), 0.43% remaining below international benchmark indicators.
12.24% of total purchases from local goods and services suppliers and $95.1 (USD million) in local purchases.
Invested $3,4 million in social projects benefiting 53,248 people near its operations
Frontera was ranked 4th in the overall list of the Best Workplaces by Great Place to Work, in the segment of companies in Colombia with 401 to 1,500 employees improving its position compared to 2024.

On the governance front:

Ethisphere recognized Frontera for the 5th consecutive year, as one of the most ethical companies in the world

Divestment of Colombian E&P Asset Portfolio

As part of Frontera's on-going commitment to unlock shareholder value, the Company previously announced it had entered into a definitive agreement with Parex Resources Inc. and Parex AcquisitionCo Inc (together "Parex") (the "Parex Arrangement Agreement"), pursuant to which Parex will acquire Frontera's upstream Colombian exploration and production business (the "Frontera E&P Assets") by way of a plan of arrangement under the Business Corporations Act (British Columbia) for an equity value of up to $525 million.

Pursuant to the Arrangement, Parex will acquire 100% of Frontera's Colombian upstream business, which consists of all of Frontera's oil and gas exploration and production assets in Colombia, the reverse osmosis water treatment facility ("SAARA") and the palm oil plantation ("ProAgrollanos").

Total cash consideration is up to $525 million, ("Cash Consideration") comprising:

$500 million payable at closing, subject to customary closing adjustments; and
An additional $25 million contingent payment payable upon execution of the contractual amendment, or other binding agreement, extending the term of the Quifa Association Contract within 12 months of closing of the Parex Arrangement Agreement.

Under the terms of the Parex Arrangement Agreement, Parex or and affiliate thereof, will also assume all of Frontera's obligations under the $310 million aggregate principal amount of outstanding 2028 unsecured notes of the Company and the $80 million outstanding under Frontera's prepayment facility with Chevron Products Company. The Arrangement implies a firm value of approximately $750 million for the acquired assets, comprising cash consideration and the assumption of existing debt.

Below is a breakdown of the Operating EBITDA by the relevant businesses for 2025:

	Unit	2025 Consolidated Operating EBITDA	2025 Frontera E&P Operating EBITDA	2025 Frontera Infrastructure Operating EBITDA	Intersegment Adjustment ⁽²⁾
Frontera E&P	$MM	301.5	301.5	—	——
Puerto Bahia	$MM	15.1	—	15.1
ODL Pipeline	$MM	—	—	—	—
SAARA & Palm Oil Assets	$MM	(3.4)	(3.4)	—	—
Intersegment Adjustment⁽¹⁾	$MM	(5.2)	—	—	(5.2)
Total	$MM	308.0	298.1	15.1	(5.2)

Total Debt and Lease Liabilities	$MM	493.9	325.3	168.6	—
Less: Cash and Cash Equivalents⁽²⁾	$MM	230.5	214.4	16.1	—
Adjusted Net Debt	$MM	263.4	110.9	152.5	—

(1) Intersegment adjustment refers to intercompany revenues between Frontera E&P and Puerto Bahia

(2) Cash and Cash Equivalent refers to the portion of Frontera's portion of Cash and cash Equivalents from ODL and Puerto Bahia's Cash & Cash Equivalents on December 31, 2025.

The Arrangement has an effective date of January 1, 2026, is anticipated to close in the second quarter of 2026 subject to customary closing conditions including, without limitation, receipt of Frontera's shareholder approval in accordance with applicable corporate and securities laws, approval of the plan of arrangement by the British Columbia Supreme Court and receipt of required regulatory approvals. The Arrangement is not subject to any financing conditions and payment of the Cash Consideration by Parex will be funded entirely through a combination of Parex's existing cash and credit facilities, and an underwritten financing commitment from Scotiabank.

In connection with the Parex Arrangement Agreement, the Catalyst Capital Group Inc. and Gramercy Funds Management LLC, which beneficially own approximately 41% and 12% of the Company's outstanding shares, respectively, have entered into support agreements under which, subject to the terms of the agreements, they have agreed to vote in favor of the Transaction.

Frontera intends to make a cash distribution to Frontera shareholders of approximately $470 million, as previously announced following the Arrangement, comprised of: (a) an amount between $445 to $455 million payable upon completion of the Arrangement (the "Closing Amount"); and (b) up to an additional $25 million associated to the contingent payment. Subject to the completion of the Arrangement and the approval of a shareholder resolution to approve the Return of Capital (the "Return of Capital Resolution").

As highlighted above, the final distribution amount will be determined by the Board following completion of the Arrangement based on the net cash proceeds of the Arrangement after deducting capital reserved for growth investments, transaction costs, fees and other expenses. Frontera currently expects to allocate approximately $25 million of the proceeds from the Arrangement to its infrastructure business to fund its strategic growth projects, particularly its potential LNG regasification project with Ecopetrol. On a pro forma basis for the 2025 fiscal year, following completion of the Arrangement and after giving effect to the $25 million of capital allocation, management of Frontera expects Frontera Infrastructure to have approximately $50 million of cash and cash equivalents.

The Return of Capital is conditional on the completion of the Arrangement. Accordingly, if the Arrangement is not approved by Frontera shareholders or the Arrangement is not otherwise completed, the Return of Capital will not be completed, regardless of whether Frontera shareholders approve the Return of Capital.

Frontera intends to hold a special meeting of shareholders (the "Meeting") on April 30, 2026, to approve the Arrangement (the "Arrangement Resolution") and, the Return of Capital Resolution and to transact such further and other business as may properly brought before the Meeting or any adjournments or postponements thereof. To become effective, each of the Arrangement Resolution and the Return of Capital Resolution requires approval by at least 66 2/3% of the votes cast by Frontera's shareholders present in person or represented by proxy at the Meeting. The record date (the "Record Date") for the determination of shareholders entitled to receive notice of, and to vote at, the Meeting is expected to be the close of business on March 30, 2026.

Further details regarding the Arrangement and the Return of Capital will be contained in the management information circular (the "Circular"), to be mailed to the Shareholders in connection with the Meeting.

Unlocking Frontera Infrastructure

Upon completion of the Arrangement, Frontera will emerge as a new Infrastructure-focused business, anchored by its interest in ODL and Puerto Bahía. Frontera Infrastructure will own and operate its Infrastructure Colombia business, and will retain certain other non‑Colombian assets, including its interest in Guyana.

Frontera's key assets and interests will comprise (a) a multi‑purpose maritime terminal (the "Port Facility") in the Cartagena Bay through its 99.97% equity interest in Puerto Bahía, and (b) pipeline transportation services through its 35% equity interest in ODL. The business is expected to generate cash flows primarily from pipeline transportation services at ODL and liquids and general cargo terminal operations at the Port Facility, complemented by near‑term growth initiatives that enhance connectivity within Colombia's downstream value chain.

ODL's robust and predictable cash‑flow generation and Puerto Bahía's pipeline of strategic growth projects will form the backbone of Frontera's post‑Arrangement infrastructure portfolio.

Puerto Bahia Highlights

Centrally located operations hub in Cartagena Bay with unrestricted draft and direct access to key road and logistics corridors serving Colombia's industrial mainland.
Integrated liquids and general cargo operations with vast expansion area.
Completed pipeline connection to Reficar, Colombia's most important refinery.
Several near-term expansion opportunities that will enhance asset value and cash flow potential including the liquified petroleum gas ("LPG") import facilities, an LNG regasification project, and containerized cargo expansion.

ODL Highlights

Key midstream asset in Colombia, transporting ~30% of Colombian oil production and serving the Llanos area holding ~70% of Colombian proven crude oil reserves.
Stable cash generation and strong market and operating position.
Estimated 12+ years of economic life for the blocks transported via ODL.
Unique position to capture additional revenue streams from its area of influence.

Below is a breakdown of Frontera's Infrastructure Adjusted EBITDA:

	Unit	2025 Infrastructure EBITDA	Equity Interest	Frontera Infrastructure Adjusted EBITDA ⁽²⁾
Puerto Bahia	$MM	15.1	99.97 %	15.1
ODL Pipeline	$MM	299.8	35.00 %	104.9
Total	$MM	314.9		120.0

Total Frontera Infrastructure Debt	$MM			168.6
Less: Cash and Cash Equivalents⁽¹⁾	$MM			45.0
Net Debt	$MM			123.6

(1) Cash and Cash Equivalents refer to the portion of Frontera's portion of Cash and Cash Equivalents from Frontera Energy Corporation, Frontera Pipeline Investment AG and Puerto Bahia's Cash & Cash Equivalents as of December 31, 2025.

(2) Refers only to the EBITDA from Puerto Bahia and the proportional EBITDA from Frontera's 35% interest in ODL, does not include the negative effect from Agrocascada and Proagrollanos EBITDA ($3.4) million.

Frontera Infrastructure 2025	($ millions)
Frontera Infrastructure Operating EBITDA (Puerto Bahia)	15.1
ODL Dividends, net of Taxes	61.6
Infrastructure Distributable Cash Flow	76.7
PIL Debt Service, net⁽¹⁾	(60.9)
Infrastructure Capex⁽²⁾	(2.5)
Infrastructure Free Cash Flow	13.3

(1) 2025 financing flows including cash sweep

(2) Excludes Capex related to the Reficar Connection construction

Enhancing Shareholder Returns

NCIB: On July 18, 2025, the Company initiated a Normal Course Issuer Bid ("NCIB"), through which the Company may purchase up to 3,502,962 Frontera's shares for cancellation, representing approximately 5% of the issued and outstanding shares as at July 15, 2025.

In 2025, the Company repurchased approximately 532,300 common shares for cancellation for approximately $2.6 million. As at March 17, 2026, year to date, the Company repurchased approximately 183,800 Frontera shares for cancellation for approximately $1.2 million under the current NCIB.

As a result of the announcement of the Arrangement, the Company intends to suspend purchases under the NCIB that are made pursuant to the Company's automatic securities purchase plan, and the Company is not aware of any material undisclosed information about itself.

Bond Buybacks: In the fourth quarter of 2025, the Company repurchased $4 million in aggregate amount of its 2028 senior unsecured notes in the open market for a total cash consideration of $2.8 million and recognizing a gain of $1.4 million. In total for 2025, the Company repurchased $85 million in aggregate principal amount of its 2028 senior unsecured notes pursuant to a cash tender offer and concurrent consent solicitation and in the open market for a total cash consideration of $61.2 million recognizing a gain of $13.3 million. As a result, the carrying value for the 2028 senior unsecured notes as of December 31, 2025, is $306.8 million.

Dividends: In connection with the recently announced transaction with Parex, and considering the transaction's effective date (January 1, 2026), the Company has determined to suspend the declaration and payment of its quarterly dividend until the transaction is finalized.

Frontera's Core Businesses

Colombia Upstream Onshore

Colombia

During the fourth quarter of 2025, Frontera produced 38,332 boe/d from its Colombian operations (consisting of 26,696 bbl/d of heavy crude oil, 8,918 bbl/d of light and medium crude oil, 5,261 mcf/d of conventional natural gas and 1,795 boe/d of natural gas liquids).

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

Quifa Block: Quifa SW and Cajua

For the Quifa block, fourth quarter 2025 production averaged 17,639 bbl/d of heavy crude oil (including both Quifa and Cajua) as compared to 17,586 bbl/d during the previous quarter. The Company invested in facility expansion and the installation of new flow lines in the Cajua field, in the Quifa block to support new well production and the SAARA connection.

During the fourth quarter of 2025, the Company processed approximately 1.76 million barrels of water per day in Quifa including SAARA.

CPE-6

For the CPE-6 block, production averaged approximately 7,346 bbl/d of heavy crude oil during the fourth quarter, compared to 7,710 bbl/d during the third quarter of 2025.

The Company invested in the expansion of crude oil storage capacity and the implementation of new field production technologies.

The Company processed approximately 385 thousand barrels of water per day in CPE-6 in the fourth quarter of 2025. The Company's current water handling capacity in CPE-6 is approximately 400 thousand barrels of water per day.

Other Colombia Developments

For Guatiquia, production during the fourth quarter 2025 averaged 5,007 bbl/d of light and medium crude compared with 5,145bbl/d in the third quarter of 2025.

For the Cubiro block production averaged 896 bbl/d of light and medium crude oil in the fourth quarter of 2025 compared with 981 bbl/d in the third quarter of 2025.

For VIM-1 (Frontera 50% W.I., non-operator), production averaged 2,286 boe/d of light and medium crude oil in the fourth quarter of 2025 compared to 2,187 boe/d of light and medium crude oil in the third quarter of 2025.

For the Sabanero block, production averaged 1,711 boe/d of heavy crude oil production in the fourth quarter of 2025 compared to 1,781 boe/d in the third quarter of 2025.

Colombia Exploration Assets

During the three months and the year ended December 31, 2025, expenditures related to exploration activities were $16.4 million and $31.0 million, respectively, compared with $5.9 million and $17.0 million, respectively, in the same periods of 2024. During the fourth quarter of 2025, the Company's exploration focus remained on the Lower Magdalena Valley and Llanos Basins in Colombia. At the VIM-1 block, the Guapo-1 exploration well was spudded on October 16, 2025, and reached total depth, approximately 15,000 feet, on December 31, 2025.

Following logging operations, it was determined that hydrocarbon production was not commercial. Parex and Frontera have agreed to proceed with plugging and abandoning the well. In addition, the Company is engaged in pre-seismic and pre-drilling activities related to social and environmental studies in the Llanos-99 and VIM-46 blocks to ensure the drilling of exploratory wells from 2026 onward. At the Llanos-99 block, the operational phase of the 3D seismic survey has commenced with the mobilization of materials and equipment.

Infrastructure Colombia

For Fiscal Year 2025, Frontera's Infrastructure Colombia Segment includes the Company's 35% equity interest in the ODL pipeline through Frontera's wholly owned subsidiary, FPI and the Company's 99.97% interest in Puerto Bahia. Beginning in 2024, the Infrastructure Colombia Segment also includes the Company's reverse osmosis water treatment facility (SAARA) and its palm oil plantation (ProAgrollanos). As part of the Parex Arrangement Agreement, Frontera is selling the SAARA and ProAgrollanos assets, given their close operational linkage to supporting activities in the Quifa block. Following the closing of the Parex Arrangement Agreement, Frontera's Infrastructure Colombia business will no longer include SAARA or ProAgrollanos.

As previously announced, in connection with the standalone and growing Colombia infrastructure business, the planned LPG project has been approved for development. The initial phase of the project is being fast-tracked and expected to be operational in later in March, supporting the supply constraints in Colombia's domestic LPG market.

At the beginning of 2026, Puerto Bahía secured a take‑or‑pay agreement with Ecopetrol, subject to certain conditions precedent, to develop an LNG regasification project, providing integrated logistics and regasification services to Reficar and the Colombian Natural Gas Transportation System (SNT). The project is expected to benefit from Puerto Bahía's existing and robust port facilities and operating platform, including the repurposing of the Reficar connection, enabling an accelerated development timeline and faster time‑to‑market. The project contemplates two phases, with an initial regasification capacity of approximately 126 MMcfd, anticipated to increase to at least 300 MMcfd by 2029. The services are planned to be available in the fourth quarter of 2026, and the agreement contemplates an up to seven‑year service term commencing from the start of operations, with options to extend for an additional five years by mutual agreement.

The Company continues to pursue strategic investment opportunities to maximize the port's infrastructure and drive long-term value creation.

Infrastructure Colombia Segment Results

Adjusted Infrastructure EBITDA in the fourth quarter of 2025 was $30.5 million, compared with $30.4 million during the third quarter of 2025, EBITDA was in line with previous quarter, driven by higher EBITDA from Puerto Bahia, mainly due to higher throughput of liquids and container volumes handled at the Port, partially offset by higher costs in ODL.

On the SAARA side, water management volumes continue to increase and stabilize, reaching an average of 181,637 barrels for the quarter, gaining momentum towards the goal of 250,000 barrels per day.

	Three months ended December 31		Year ended December 31
($M)	2025	2024	2025	2024
Adjusted Infrastructure Revenue	51,984	45,278	191,037	171,392
Adjusted Infrastructure Operating Costs	(17,871)	(13,794)	(61,814)	(50,346)
Adjusted Infrastructure General and Administrative	(3,572)	(3,952)	(12,578)	(13,823)
Adjusted Infrastructure EBITDA	30,541	27,532	116,645	107,223

⁽¹⁾ Non-IFRS financial measure

Segment capital expenditures for the three months ended December 31, 2025, totaled $2.8 million primarily driven by investments totaling $1.7 million made in Puerto Bahia, including: (i) $0.9 million towards the connection project between Puerto Bahia's port facility and the Cartagena refinery, (ii) tank maintenance, and (iii) general expenditures related to the cargo terminal facilities. Fourth quarter capital expenditures also included investment in the SAARA project and palm oil plantation.

	Three months ended December 31			Year ended December 31
($M)	Q4 2025	Q3 2025	Q4 2024	2025	2024
Revenue	17,065	15,647	13,873	60,055	48,542
Costs	(12,007)	(11,244)	(8,099)	(42,674)	(31,438)
General and administrative expenses	(1,537)	(1,429)	(1,507)	(5,653)	(5,903)
Depreciation, amortization and impairment expenses	(20,326)	(2,815)	(1,877)	(27,212)	(7,976)
Other operating costs	(1,446)	(472)	(407)	(12,739)	(1,710)
Infrastructure Colombia (loss) income from operations	(18,251)	(313)	1,983	(18,223)	1,565
Share of income from associates - ODL	14,107	15,857	13,200	59,197	53,912
Infrastructure Colombia segment income	(4,144)	15,544	15,183	40,974	55,477

Infrastructure Colombia segment cash flow from operating activities	12,570	22,062	14,788	61,806	58,034
Capital Expenditures Infrastructure Colombia Segment ⁽¹⁾	2,828	5,344	25,999	15,706	47,882

⁽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 28 of the MD&A.

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

				Year ended December 31
(bbl/d)	Q4 2025	Q3 2025	Q4 2024	2025	2024
At Rubiales Station	133,831	131,536	167,272	142,747	169,890
At Caño Sur Station	50,266	50,484	—	36,412	—
At Jagüey and Palmeras Stations	57,637	59,938	68,256	59,835	73,779
Total	241,734	241,958	235,528	238,994	243,669

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

				Year ended December 31
(bbl/d)	Q4 2025	Q3 2025	Q4 2024	2025	2024
FEC volumes	12,587	10,286	11,626	10,555	13,513
Third party	27,961	29,274	50,364	35,639	42,506
Total	40,548	39,560	61,990	46,194	56,019

The following table shows the RORO units, their dwell times, the containers and break-bulk volumes, for the general cargo port facility at Puerto Bahia:

		Three months ended December 31		Year ended December 31
		2025	2024	2025	2024
RORO	Units ⁽¹⁾	38,727	21,676	121,536	74,425
RORO	Dwell time in days ⁽²⁾	34	48	31	54
Containers	TEUs ⁽³⁾	6,436	539	17,890	1,003
Break Bulk Volumes	Tons/m³⁽⁴⁾	15,406	34,690	73,568	69,494

⁽¹⁾ Wheeled cargo, primarily cars imported to Colombia.

⁽²⁾ Dwell time refers to the time spent by the units within the general cargo port facility. The variance in dwell time associated with Break Bulk Volumes could depend on the characteristics of the cargo, especially in situations where the cargo is received and dispatched within a single day.

⁽³⁾ Twenty-foot Equivalent Unit.

⁽⁴⁾ Other types of cargo other than wheeled cargo and containers.

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

					Year ended December 31
($M)		Q4 2025	Q3 2025	Q4 2024	2025	2024
Fresh fruit bunches for palm oil (produced - sold)	(Tons)	7,191	6,214	6,183	28,128	25,357

Production per hectare per year ⁽¹⁾	(Tons/ha/year)	9.73	9.35	8.40	9.73	8.40
Palm oil fruit price	($/Ton)	228	208	203	215	174

Volumes of reverse osmosis water treated	(bwpd)	181,637	156,767	78,716	135,158	44,121
Volumes of water irrigated for palm oil cultivation ⁽²⁾	(bwpd)	171,685	150,125	80,276	130,863	40,837

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

Guyana Update

On March 26, 2025, the Company and its subsidiaries, Frontera Petroleum International Holding B.V. and Frontera Energy Guyana Holding Ltd. (the "Investors"), delivered a Notice of Intent to the Government of Guyana (the "GoG"). In this Notice, the Investors alleged breaches of the United Kingdom–Guyana Bilateral Investment Treaty and the Guyana Investment Act by the GoG. This communication triggered a 90-day consultation and negotiation period intended to resolve the dispute amicably.

On July 23, 2025, the GoG, through its legal counsel, responded to the Notice of Intent, rejecting the claims regarding the Corentyne block license, and reaffirmed its view that the interest of Frontera Energy Guyana Corp. ("Frontera Guyana") and CGX Resources Inc. ("CGX Resources", and together with Frontera Guyana, the "Joint Venture") expired on June 28, 2024. The Joint Venture has continued to exchange without prejudice communications with the GoG, and remains open to engaging in good faith discussions with the GoG.

The Joint Venture continues to firmly maintain that its interests in, and the license for, the Corentyne block remain valid and in good standing and that the Petroleum Agreement for such block has not been terminated. While the GoG has publicly stated its position that the Joint Venture's interest expired on June 28, 2024, the Joint Venture strongly disagrees and remains committed to asserting its legal rights under applicable treaties and agreements.

The Joint Venture jointly holds 100% working interest in the Corentyne block, located offshore Guyana. Frontera Guyana and CGX Resources have agreed that their respective participating interests are 72.52% and 27.48%, which includes a 4.52% interest that CGX Resources agreed to assign to Frontera Guyana in 2023. This assignment remains subject to the approval of the GoG but is enforceable between Frontera Guyana and CGX Resources.

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 40-60% of its estimated net after royalties' production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, thereby allowing the Company to take a more dynamic approach to the management of its hedging portfolio.

The following table summarizes Frontera's hedging position as of March 17, 2026.

Term	Type of Instrument	Positions (bbl/d)	Strike Prices Put/Call
Jan 26	Put Spread	8,097	65/55
Feb 26	Put Spread	14,500	65/55
Mar 26	Put Spread	20,613	65/55
1Q-2026	Total Average	14,400	65/55
Apr 26	Put Spread	8,073	62.7/55
May 26	Put Spread	21,258	62.7/55
Jun 26	Put Spread	14,633	62.7/55
2Q-2026	Total Average	14,727	62.7/55

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 17 exploration and production blocks in Colombia, pipeline transportation services and a multi-purpose maritime terminal in Colombia and certain other non-Colombian assets, including its interest in Guyana. 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 social media channels at the following links:

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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, statements regarding the expected closing date of the Arrangement, the ability of Frontera to obtain all necessary court, third-party and shareholder approvals to complete the Arrangement, the cash consideration to be received pursuant to the Arrangement, the expected use of proceeds resulting from the Arrangement, the anticipated Return of Capital and the expected timing thereof, the focus and business of the Company following completion of the Arrangement, the expected completion date of the LPG project and its impact on Colombia's domestic LPG market, the expected capacity of the LNG regasification project, future growth initiatives, the mailing and the contents of the Circular in respect of the Meeting, the holding of the Meeting and the timing thereof and the related Record Date, the conditions to completing the Arrangement, the source of expected future cash flows following completion of the Arrangement, future growth initiatives, the estimated years of remaining economic life for the blocks transported via ODL, the potential outcome of the dispute with the GoG over the Corentyne block, the Company's development plans and objectives, production levels, profitability, cash flows, and future income generation capacity 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: volatility in market prices for oil and natural gas; the U.S. trade tariffs affecting numerous countries; the impact of the Russia-Ukraine conflict and the conflict in the Middle East and economic sanctions related thereto; actions of the Organization of Petroleum Exporting Countries; the risk that the sale of the Colombian upstream business pursuant to the Arrangement is not completed; actions by other third parties including customers, suppliers, industry partners or relevant governmental or regulatory authorities, 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 the Frontera Shares and the timing thereof; the Company's intent to continue to consider investor-focused initiatives; 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; the intentions of the Company with regard to its capital allocation decisions; 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 of receipt of government approvals; measures the Company may take in response to pandemics of similar events; and fluctuations in foreign exchange or interest rates and stock market volatility, the ability of the Joint Venture to reach an agreement with the GoG in respect of the Joint Venture's interest in the agreements relating to the Corentyne block or the results of any ongoing discussions or legal processes relating to such matters, and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 17, 2026 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 from Continuing Operations *

EBITDA is a commonly used non-IFRS financial measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and DD&A. Operating EBITDA from continuing operations 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, trunkline costs, temporal taxes, payments of minimum work commitments and, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, share-based compensation and debt extinguishment cost) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA from continuing operations, as they are not indicative of the underlying core operating performance of the Company.

The following table provides a reconciliation of net income (loss) to Operating EBITDA from continuing operations:

	Three months ended December 31		Year ended December 31
($M)	2025	2024	2025	2024
Net loss for the period from continuing operations ⁽¹⁾	(663,354)	(20,485)	(1,020,361)	(18,628)

Finance income	(1,392)	(1,851)	(6,677)	(8,363)
Finance expenses	18,888	21,473	71,333	73,252
Income tax (recovery) expense	(15,058)	35,594	(22,557)	99,324
Depletion, depreciation and amortization	75,115	62,737	275,419	254,791
Colombian temporary taxes ⁽²⁾	1,983	—	7,233	—
Expense (recovery) of asset retirement obligation	1,691	(2,214)	5,500	2,335
Impairment expense	620,436	18,205	1,063,169	19,985
Trunkline costs	162	1,485	2,162	5,314
Post-termination obligation	740	705	3,339	577
Share-based compensation	1,063	827	2,746	1,685
Restructuring, severance and other costs	2,279	2,096	21,084	5,312
Share of income from associates	(14,107)	(13,200)	(59,197)	(53,912)
Foreign exchange loss	4,357	1,795	2,565	11,041
Other loss (income)	6,359	(6,696)	(7,008)	672
Unrealized (gain) loss on risk management contracts	(2,306)	10,035	(7,518)	13,976
Realized loss (gain) on risk management contract for ODL dividends received	1,076	(921)	2,297	(633)
Non-controlling interests	(4,242)	35	(18,206)	(609)
Gain on repurchase of senior unsecured notes net of consent solicitation	(1,363)	—	(13,288)	(1,001)
Debt extinguishment cost	—	—	5,964	—
Operating EBITDA from continuing operations	68,907	109,620	308,029	405,118

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 December 31		Year ended December 31
	2025	2024	2025	2024
Consolidated Statements of Cash Flows
Additions to oil and gas properties, infrastructure port, and plant and equipment	54,710	93,074	205,800	311,759
Additions to exploration and evaluation assets	1,567	1,471	5,244	11,749
Total additions in Consolidated Statements of Cash Flows	56,277	94,545	211,044	323,508
Non-cash adjustments ⁽¹⁾	(3,030)	(7,520)	(1,808)	(30,343)
Cash adjustments ⁽²⁾	—	(2,481)	(43)	(2,481)
Total Capital Expenditures from Continuing Operations	53,247	84,544	209,193	290,684

Capital Expenditures attributable to Infrastructure Colombia Segment	2,828	25,999	15,706	47,882
Capital Expenditures attributable to other segments different to Infrastructure Colombia Segment	50,419	58,545	193,487	242,802
Total Capital Expenditure from Continuing Operations	53,247	84,544	209,193	290,684

⁽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 December 31		Year ended December 31
($M) ⁽¹⁾	2025	2024	2025	2024
Revenue Infrastructure Colombia Segment	17,065	13,873	60,055	48,542
Revenue from ODL	99,769	89,728	374,235	351,000
Direct participation interest in the ODL	35 %	35 %	35 %	35 %
Equity adjustment participation of ODL ⁽¹⁾	34,919	31,405	130,982	122,850
Adjusted Infrastructure Revenues	51,984	45,278	191,037	171,392

Operating cost Infrastructure Colombia Segment	(12,007)	(8,099)	(42,674)	(31,438)
Operating Cost from ODL	(16,753)	(16,270)	(54,684)	(54,020)
Direct participation interest in the ODL	35 %	35 %	35 %	35 %
Equity adjustment participation of ODL ⁽¹⁾	(5,864)	(5,695)	(19,140)	(18,908)
Adjusted Infrastructure Operating Costs	(17,871)	(13,794)	(61,814)	(50,346)

General and administrative Infrastructure Colombia Segment	(1,537)	(1,507)	(5,653)	(5,903)
General and administrative from ODL	(5,814)	(6,985)	(19,788)	(22,628)
Direct participation interest in the ODL	35 %	35 %	35 %	35 %
Equity adjustment participation of ODL ⁽¹⁾	(2,035)	(2,445)	(6,925)	(7,920)
Adjusted Infrastructure General and Administrative	(3,572)	(3,952)	(12,578)	(13,823)

⁽¹⁾ Revenues and expenses related to ODL are accounted for using the equity method, as described in Note 19 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 December 31		Year ended December 31
($M)	2025	2024	2025	2024
Adjusted Infrastructure Revenue ⁽¹⁾	51,984	45,278	191,037	171,392
Adjusted Infrastructure Operating Costs ⁽¹⁾	(17,871)	(13,794)	(61,814)	(50,346)
Adjusted Infrastructure General and Administrative ⁽¹⁾	(3,572)	(3,952)	(12,578)	(13,823)
Adjusted Infrastructure EBITDA	30,541	27,532	116,645	107,223

⁽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 December 31		Year ended December 31
	2025	2024	2025	2024
Produced crude oil and products sales ($M) ⁽¹⁾	184,045	219,070	764,855	854,111
Purchased crude net margin ($M) ⁽²⁾⁽³⁾	(7,007)	(11,552)	(37,311)	(38,118)
Oil and gas sales, net of purchases ($M) ⁽²⁾	177,038	207,518	727,544	815,993
Sales volumes, net of purchases - (boe)	3,092,304	3,254,592	11,976,745	11,707,608
Produced crude oil and gas sales ($/boe)	59.52	67.31	63.86	72.95
Oil and gas sales, net of purchases ($/boe) ⁽²⁾	57.25	63.76	60.74	69.70

⁽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 24 of the MD&A f or further details .

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

⁽³⁾ Purchased crude net margin is a non-IFRS financial measure calculated using purchased crude oil and product sales, less the cost of those volumes purchased from third parties including transportation and refining costs. Please see the calculation below.

Distributable Cash Flow is a non- IFRS financial measure used to assess the cash available to the Company from its operations and equity investments to support capital expenditures, debt service and dividends.

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 December 31		Year ended December 31
	2025	2024	2025	2024
Oil and gas sales, net of purchases ($M) ⁽¹⁾⁽²⁾	177,038	207,518	727,544	815,993
Crude oil sales volumes, net of purchases - (bbl)	3,008,810	3,213,578	11,742,389	11,500,286
Conventional natural gas sales volumes - (mcf)	475,857	234,321	1,335,483	1,183,171
Realized oil price, net of purchases ($/bbl) ⁽²⁾	57.19	64.08	61.00	70.30
Realized conventional natural gas price ($/mcf)	10.42	6.78	8.45	6.37

* Figures from previous reporting periods were changed due to the re-presentation of continuing operations following the divestment of non-core assets in Ecuador. Refer to the "Discontinued Operations" section on page 19 for further details.

⁽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 December 31		Year ended December 31
	2025	2024	2025	2024
Oil and gas sales, net of purchases ($M) ⁽¹⁾⁽²⁾	177,038	207,518	727,544	815,993
(Loss) gain on oil price risk management contracts, net ($M) ⁽³⁾	(1,186)	253	(8,680)	(8,457)
(-) Royalties ($M)	(2,241)	(2,599)	(9,448)	(14,704)
Net sales ($M)	173,611	205,172	709,416	792,832
Sales volumes, net of purchases - (boe)	3,092,304	3,254,592	11,976,745	11,707,608
Oil and gas sales, net of purchases ($/boe) ⁽²⁾	57.25	63.76	60.74	69.70
Premiums received (paid) on oil price risk management contracts ⁽³⁾⁽⁴⁾	(0.38)	0.08	(0.72)	(0.72)
Royalties ($/boe) ⁽⁴⁾	(0.73)	(0.80)	(0.79)	(1.26)
Net sales realized price ($/boe) ⁽²⁾	56.14	63.04	59.23	67.72

⁽¹⁾ Non-IFRS financial measure.

⁽³⁾ Includes the net amount of put premiums paid for expired positions and the positive cash settlement received from oil price contracts during the period. Refer to the "Gain (Loss) on Risk Management Contracts" section on page 18 of the MD&A for further details.

⁽⁴⁾ Supplementary financial measure.

Purchased crude net margin

Purchased 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. Purchased crude net margin per boe is a non-IFRS ratio that is calculated using the Purchased crude net margin, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below:

	Three months ended December 31		Year ended December 31
	2025	2024	2025	2024
Purchased crude oil and products sales ($M)	43,141	54,469	194,015	202,752
(-) Cost of diluent and oil purchased ($M) ⁽¹⁾	(49,375)	(65,375)	(229,094)	(235,944)
Puerto Bahía inter-segment costs ⁽²⁾	(773)	(646)	(2,232)	(4,926)
Purchased crude net margin ($M) ⁽²⁾	(7,007)	(11,552)	(37,311)	(38,118)
Sales volumes, net of purchases - (boe)	3,092,304	3,254,592	11,976,745	11,707,608
Purchased crude net margin ($/boe) ⁽²⁾	(2.27)	(3.55)	(3.12)	(3.25)

⁽¹⁾ Cost of third-party volumes purchased for use and resale in the Company's oil operations, including associated transportation and refining 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 December 31		Year ended December 31
	2025	2024	2025	2024
Production costs (excluding energy costs) ($M)	33,493	27,628	128,296	134,694
(-) Realized gain on FX hedge attributable to production costs (excluding energy costs) ($M) ⁽¹⁾	(1,367)	—	(2,615)	(3,358)
SAARA inter-segment costs	1,872	783	5,783	1,370
Production costs (excluding energy costs), net of realized FX hedge impact ($M) ⁽²⁾	33,998	28,411	131,464	132,706
Production Colombia (boe)	3,526,544	3,740,352	14,239,015	14,136,018
Production costs (excluding energy costs), net of realized FX hedge impact ($/boe)	9.64	7.60	9.23	9.39

⁽¹⁾ See "Gain (Loss) on Risk Management Contracts" on page 18 of the MD&A for further details.

⁽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 December 31		Year ended December 31
	2025	2024	2025	2024
Energy costs ($M)	22,595	20,439	79,546	75,622
(-) Realized gain on FX hedge attributable to energy costs ($M) ⁽¹⁾	(677)	—	(1,366)	(1,267)
Energy costs, net of realized FX hedge impact ($M) ⁽²⁾	21,918	20,439	78,180	74,355
Production Colombia (boe)	3,526,544	3,740,352	14,239,015	14,136,018
Energy costs, net of realized FX hedge impact ($/boe)	6.22	5.46	5.49	5.26

* Figures from previous reporting periods were changed due to the re-presentation of continuing operations following the divestment of non-core assets in Ecuador.

⁽¹⁾ See "Gain (Loss) on Risk Management Contracts" on page 18 of the MD&A for further details.

⁽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 December 31		Year ended December 31
	2025	2024	2025	2024
Transportation costs ($M)	38,544	38,645	154,426	146,741
(-) Realized gain on FX hedge attributable to transportation costs ($M) ⁽¹⁾	(761)	—	(1,628)	(982)
Puerto Bahía inter-segment costs ⁽²⁾	887	507	2,991	2,021
Transportation costs, net of realized FX hedge impact ($M) ⁽²⁾⁽³⁾	38,670	39,152	155,789	147,780
Net production Colombia (boe)	3,245,024	3,377,136	12,984,510	12,524,154
Transportation costs, net of realized FX hedge impact ($/boe) ⁽²⁾	11.92	11.59	12.00	11.80

⁽¹⁾ See "Gain (Loss) on Risk Management Contracts" on page 18 of the MD&A for further details.

⁽²⁾ 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahia inter-segment costs related to transportation costs.

⁽³⁾ Non-IFRS financial measure.

Supplementary Financial Measures

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.

About Frontera's 2025 Year-End Estimated Reserves

The Company's 2025 year-end estimated reserves were evaluated by D&M in their report dated February 6, 2026, with an effective date of December 31, 2025 (the "Reserves Report"), in accordance with the definitions, standards and procedures contained in the COGE Handbook, NI 51-101 and CSA Staff Notice 51-324. D&M is an independent qualified reserves evaluator as defined in NI 51-101.

Additional reserves information as required under NI 51-101 will be included in the Company's statement of reserves data and other oil and gas information on Form 51-101F1, which is expected to be filed on SEDAR on March 17, 2026. See "Advisory Note Regarding Oil and Gas Information" section in the "Advisories", at the end of this news release.

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
MMboe	Millions of barrels of oil equivalent
MMcf/d	Millions of cubic feet per day
$M	Thousands of U.S. dollars
$MM	Millions of U.S. dollars
Net Production	Net production represents the Company's working interest volumes, net of royalties and internal consumption
PDP	Proved developed producing reserves
PDNP	Proved developed non-producing reserves
PUD	Proved undeveloped reserves
1P	Proved reserves
2P	Proved reserves + probable reserves

"Proved Developed Producing Reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been in production, and the date of resumption of production must be known with reasonable certainty.
"Proved Developed Non-Producing Reserves" are those reserves that either have not been on production or have previously been on production but are shut-in and the date of resumption of production is unknown.
"Proved Undeveloped Reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g. when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.
"Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
"Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.
"Possible" reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

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SOURCE Frontera Energy Corporation