FRONTERA ANNOUNCES SECOND QUARTER 2025 RESULTS
Recorded $455.2 million in Net Loss Mainly due to Non-Cash Impairment Charges Related to its Interest in the Corentyne License and Ecuadorian Assets
Increased Total Production 1% Quarter over Quarter
Generated Quarterly Operating EBITDA of $76.1 Million
Generated Adjusted Infrastructure EBITDA of $27.1 million and $14.3 million Segment Income
Executed C$91 million Substantial Issuer Bid, its Largest to Date, with Over 92.6% Shareholder Participation
Successfully Completed $80 million Capped Tender Offer and Consent Solicitation of Outstanding 2028 Senior Unsecured Notes
Declared Quarterly Dividend of C$0.0625 Per Share, or $3.5 Million in Aggregate, Payable on or around October 16, 2025
CALGARY, AB, Aug. 13, 2025 /PRNewswire/ - Frontera Energy Corporation (TSX:FEC) ("Frontera" or the "Company") today reported financial and operational results for the second quarter ended June 30, 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:
"Despite a volatile global macro-economic and oil market backdrop, Frontera continued to execute on its strategic goals and priorities across its businesses in the second quarter delivering strong operating results and completing significant value-generating initiatives for its shareholders and bondholders. The Company generated $76.1 million in Operating EBITDA, produced $27.1 million of Adjusted Infrastructure EBITDA, and maintained a strong balance sheet, finishing the quarter with a total cash balance of $197.5 million while reducing its upstream net debt by 30%.
Following the expiry of the 90‑day consultation and negotiation period arising from the Notice of Intent -and in view of the uncertainty introduced by the Government of Guyana—we have recognized an impairment of over $430 million related to our investment in the Corentyne block, in accordance with prudent accounting standards. The Joint Venture remains firmly of the view that its interests in, and the license for, the Corentyne block remain in place and in good standing and that the Petroleum Agreement has not been terminated. We remain committed to working with the Government of Guyana to resolve these issues amicably, while preparing to assert and protect our legal and contractual rights through all available legal remedies, as necessary.
The Company prioritized returning capital to all investors via its successful $80 million tender offer and consent solicitation of its senior unsecured notes due in 2028 and, subsequent to the quarter, the completion of a C$91 million substantial issuer bid, the largest in the Company's history.
The Company also declared a quarterly dividend of C$0.0625 per share, or approximately $3.5 million in aggregate, and initiated a non-course issuer bid program.
Over the last twelve-months, Frontera has returned over $144 million to shareholders via dividends and share repurchases while also reducing the outstanding aggregate principal amount of its senior unsecured notes by over 20%. These efforts underscore the success of the Company's return of capital focus to its stakeholders.
The Company will continue to consider similar investor-focused initiatives in 2025 and beyond, including additional dividends, distributions, and 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, and in so doing may consider other strategic initiatives or transactions."
Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented:
"Frontera's second quarter financial and operating results demonstrate the decisive steps we are taking to deliver stakeholder value, maintain financial and operational flexibility, and reduce leverage over the long-term. We increased our total production quarter over quarter driven by increased processing capacity at SAARA, investments in new flow lines in our heavy oil fields, a successful well intervention program within our light and medium blocks and new commercialized volumes of natural gas production from the VIM-1 block.
During the quarter, we continued to prioritize operational improvements, reducing capital spending and cost and process efficiencies across our business, delivering a 10.3% decrease in production costs quarter-over-quarter driven by fewer well interventions and the implementation of new production technologies. We also reduced our transportation costs by 5.7% quarter-over-quarter driven by higher domestic wellhead sales.
Our standalone and growing Colombia infrastructure business, which includes the Company's interest in ODL, generated an Adjusted Infrastructure EBITDA of $27.1 million. At Puerto Bahia, the Reficar connection was completed by the end of the quarter and now the efforts shift to the first transported volumes which are expected during the third quarter of 2025. Strategic investments in the port, including the LPG JV with Empresas Gasco, are progressing on schedule. The port is also pursuing additional investment opportunities that leverage its facilities and infrastructure for sustainable long-term growth.
Consistent with our strategy, following the end of the quarter, the Company announced it had reached an agreement to divest its interest in the Company's non-core Perico and Espejo fields in Ecuador. This transaction is consistent with our strategy of maximizing value over volumes and supports a stronger focus on our higher-impact Colombian upstream operations.
As a result, we are adjusting our 2025 production guidance to account for the impact of Ecuador sale to 39,500 to 41,000 boed. In light of the current oil price environment, we are also adjusting our capital expenditures guidance downwards, by approximately $20 million, reducing development facilities capex to $45 - 65 million and exploration capex to $25 - 35 million, reflecting our disciplined approach to capital spending and ability to identify ongoing operational efficiencies. Additionally, we are providing Operating EBITDA Guidance at a $70/bbl Brent Price with a target of between $320 - $360 million and revising our Adjusted Infrastructure EBITDA Guidance to between $110 - 125 million."
Second Quarter 2025 Operational and Financial Summary:
Six months ended June 30
Q2 2025
Q1 2025
Q2 2024
2025
2024
Operational Results
Heavy crude oil production (1)
(bbl/d)
27,535
27,167
24,839
27,352
24,119
Light and medium crude oil production (1)
(bbl/d)
11,127
10,998
12,583
11,062
12,582
Total crude oil production
(bbl/d)
38,662
38,165
37,422
38,414
36,701
Conventional natural gas production (1)
(mcf/d)
3,118
2,274
4,019
2,696
3,654
Natural gas liquids production (1)
(boe/d)
1,846
1,913
1,785
1,879
1,711
Total production (2)
(boe/d) (3)
41,055
40,477
39,912
40,766
39,053
Inventory Balance
Colombia
(bbl)
629,147
392,821
758,794
629,147
758,794
Peru
(bbl)
480,200
480,200
480,200
480,200
480,200
Ecuador
(bbl)
33,189
38,865
80,195
33,189
80,195
Total Inventory
(bbl)
1,142,536
911,886
1,319,189
1,142,536
1,319,189
Brent price Reference
($/bbl)
66.71
74.98
85.03
70.81
83.42
Produced crude oil and gas sales (4)
($/boe)
63.04
68.42
78.31
65.81
77.23
Purchase crude net margin (4)(5)
($/boe)
(3.53)
(3.81)
(2.62)
(3.67)
(2.81)
Oil and gas sales, net of purchases (4)(5)
($/boe)
59.51
64.61
75.69
62.14
74.42
Gain (loss) on oil price risk management contracts (6)(7)
($/boe)
0.15
(1.35)
(1.32)
(0.62)
(1.30)
Royalties (6)
($/boe)
(0.80)
(1.00)
(2.01)
(0.90)
(1.83)
Net sales realized price (4)(5)
($/boe)
58.86
62.26
72.36
60.62
71.29
Production costs (excluding energy cost), net of realized FX hedge impact (4)
($/boe)
(9.01)
(10.04)
(10.79)
(9.52)
(10.51)
Energy costs, net of realized FX hedge impact (4)
($/boe)
(4.71)
(5.38)
(4.74)
(5.04)
(5.01)
Transportation costs, net of realized FX hedge impact (4)(5)
($/boe)
(11.62)
(12.32)
(11.07)
(11.96)
(11.27)
Operating netback per boe (4)(5)
($/boe)
33.52
34.52
45.76
34.10
44.50
Financial Results
Oil & gas sales, net of purchases (8)
($M)
170,943
197,975
217,130
368,918
417,904
Gain (loss) on oil price risk management contracts (7)
($M)
431
(4,141)
(3,796)
(3,710)
(7,285)
Royalties
($M)
(2,304)
(3,060)
(5,774)
(5,364)
(10,280)
Net sales (8)
($M)
169,070
190,774
207,560
359,844
400,339
Net (loss) income (9)
($M)
(455,212)
27,524
(2,846)
(427,688)
(11,349)
Per share, basic
($)
(5.89)
0.35
(0.03)
(5.50)
(0.13)
Per share, diluted
($)
(5.89)
0.34
(0.03)
(5.50)
(0.13)
General and administrative
($M)
14,279
13,571
12,928
27,850
26,484
Outstanding Common Shares
Number ofshares
77,295,478
77,294,460
84,253,816
77,295,478
84,253,816
Operating EBITDA (8)
($M)
76,073
83,458
110,321
159,531
207,569
Cash provided by operating activities
($M)
41,786
70,137
149,787
111,923
215,403
Capital expenditures (8)
($M)
59,402
46,711
80,198
106,113
149,579
Cash and cash equivalents - unrestricted
($M)
184,860
170,094
180,659
184,860
180,659
Restricted cash short and long-term (10)
($M)
12,679
29,738
34,419
12,679
34,419
Total cash (10)
($M)
197,539
199,832
215,078
197,539
215,078
Total debt and lease liabilities (10)
($M)
535,346
505,486
523,994
535,346
523,994
Consolidated total indebtedness (Excl. Unrestricted Subsidiaries) (11)
($M)
353,764
409,675
426,004
353,764
426,004
Net Debt (Excluding Unrestricted Subsidiaries) (11)
($M)
204,671
290,732
283,651
204,671
283,651
(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 W.I. production before royalties. Refer to the "Further Disclosures" section on page 40 of the Company's management's discussion and analysis for the three months ended on March 31, 2025 (the "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 40 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 24 of the MD&A.
(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 measure (as defined in NI 52-112). Refer to the "Non-IFRS and Other Financial Measures" section on page 24 of the MD&A.
(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 "Gain (loss) on oil price risk management contracts" section on page 15 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 24 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 24 of the MD&A.
(11) "Unrestricted Subsidiaries" include CGX Energy Inc., 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. ("Frontera Bahia"), including Sociedad Portuaria Puerto Bahia S.A ("Puerto Bahia"). Refer to the "Liquidity and Capital Resources" section on page 31 of the MD&A.
Second Quarter 2025 Operational and Financial Results:
The Company recorded a net loss of $455.2 million or $5.89/share in the second quarter of 2025, compared with a net income of $27.5 million or $0.35/share in the prior quarter and net loss of $2.8 million or $0.03/share in the second quarter of 2024. Net loss from operations for the second quarter included a loss from operations of $474.8 million (net of non-cash impairment expenses of $477.0 million), finance expenses of $18.3 million and foreign exchange expenses of $2.6 million, partially offset by $14.1 million from share of income from associates, an income tax recovery of $13.0 million (including $14.3 million of deferred income tax recovery), $11.7 million of gain on the repurchase of its outstanding 7.875% Senior Unsecured Notes due in 2028 (the "2028 Senior Unsecured Notes") net of the consent solicitation, and $4.0 million related to a gain on risk management contracts. This compares with a net loss, attributable to equity holders of the Company, of $2.8 million, mainly resulting from an income tax expense of $32.7 million (including $31.4 million of deferred income tax expenses), finance expenses of $17.4 million, foreign exchange losses of $7.5 million and $3.6 million related to a loss on risk management contracts, partially offset by an income from operations of $45.2 million and $13.4 million from the share of income from associates.
Production averaged 41,055 boe/d in the second quarter of 2025, up 1% compared to 40,477 boe/d in the prior quarter and up 3% against 39,912 boe/d in the second quarter of 2024. Compared to the first quarter 2025, heavy crude oil production, increased by 1%, mainly due to increased processing capacity at SAARA and investments in new flow lines in the Cajua field; light and medium crude oil production, increased by 3% driven by a successful well intervention program; and conventional natural gas production increase by 37%, as a result of new commercialized volumes of natural gas from the VIM-1 Block. Natural gas liquids production decreased 4%, compared to the prior quarter, primarily as a result of natural decline.
Six months ended
June 30
Q2 2025
Q1 2025
Q2 2024
2025
2024
Heavy crude oil production (bbl/d)
27,535
27,167
24,839
27,352
24,119
Light and medium crude oil production (bbl/d)
11,127
10,998
12,583
11,062
12,582
Conventional natural gas production (mcf/d)
3,118
2,274
4,019
2,696
3,654
Natural gas liquids production(boe/d)
1,846
1,913
1,785
1,879
1,711
Total production
41,055
40,477
39,912
40,766
39,053
Operating EBITDA was $76.1 million in the second quarter of 2025 compared to $83.5 million in the prior quarter and $110.3 million in the second quarter of 2024. The decrease in operating EBITDA compared to the prior quarter was mainly due to lower Brent prices during the quarter, partially offset by lower production and transportation costs during the quarter.
Cash provided by operating activities in the second quarter of 2025 was $41.8 million, compared to $70.1 million in the prior quarter and $149.8 million in the second quarter of 2024.
The Company reported a total cash position of $197.5 million at June 30, 2025, compared to $199.8 million at March 31, 2025 and $215.1 million at June 30, 2024. During the quarter, the Company closed and funded the recapitalization of its interest in Oleoducto de los Llanos Orientales S.A. ("ODL") through a $220 million non-recourse, secured loan and received $115 million in net proceeds. In addition, the Company repurchased $80 million in aggregate principal amount of its outstanding 2028 Senior Unsecured Notes. Subsequent to the quarter, the Company paid $66.5 million to shareholders through its substantial issuer bid (as described further below).
As at June 30, 2025, the Company had a total crude oil inventory balance of 1,142,536 barrels compared to 911,886 barrels at March 31, 2025. The Company had a total inventory balance in Colombia of 629,147 barrels, including 493,510 crude oil barrels and 135,637 bbls of diluent and others. This compared to 392,821 barrels as at March 31, 2025, and 758,794 barrels as at June 30, 2024. The Increase in inventory levels was associated with higher quarter over quarter production levels.
Capital expenditures were approximately $59.4 million in the second quarter of 2025, compared with $46.7 million in the prior quarter and $80.2 million in the second quarter of 2024. During the second quarter, the Company drilled 26 development wells mainly at the Quifa and CPE-6 blocks.
The Company's net sales realized price was $58.86/boe in the second quarter of 2025, compared to $62.26/boe in the prior quarter and $72.36/boe in the second quarter of 2024. The decrease was primarily driven by a lower Brent benchmark oil price, which was partially offset by stronger oil price differentials, the realized gain from oil price risk management contracts and lower royalties paid in cash.
The Company's operating netback was $33.52/boe in the second quarter of 2025, compared with $34.52/boe in the prior quarter and $45.76/boe in the second quarter of 2024. Despite a $8.27/bbl decrease in the Brent benchmark oil price, the Company partially offset the lower netback through: (i) stronger oil price differentials, (ii) a reduction in production costs (excluding energy costs), net of realized FX hedge impact, mainly as a result of a reduction of well intervention activities and the adoption of new field production technologies, (iii) lower energy costs, net of realized FX hedge impact, driven by lower market prices, and (iv) lower transportation costs, due to reduced transported volumes, primarily resulting from improved domestic wellhead sales.
Production costs (excluding energy cost), net of realized FX hedge impact, averaged $9.01/boe in the second quarter of 2025, compared with $10.04/boe in the prior quarter and $10.79/boe in the second quarter of 2024. The decrease in production cost primarily due to lower well services activities and the implementation of new field production technologies.
Energy costs, net of realized FX hedging impacts, averaged $4.71/boe in the second quarter of 2025, compared to $5.38/boe in the prior quarter and up from $4.74/boe in the second quarter of 2024. The decrease quarter over quarter was mainly due to lower market prices.
Transportation costs, net of realized FX hedging impacts averaged $11.62/boe in the second quarter of 2025, compared with $12.32/boe in the prior quarter and $11.07/boe in the second quarter of 2024. The decrease during the quarter was mainly due to reduced transported volumes, primarily resulting from improved domestic wellhead sales.
ODL volumes transported were 235,804 bbl/d during the second quarter of 2025, volumes transported were in line with Q1 2025, which saw 236,387 bbl/d in volumes transported.
Total Puerto Bahia liquids volumes were 53,280 bbl/d during the second quarter 2025 compared to 51,579 bbl/d the first quarter of 2025.
Adjusted Infrastructure EBITDA in the second quarter of 2025 was $27.1 million, compared to $28.6 million in the first quarter of 2025. The decrease was mainly due to higher operating costs in SAARA, offset by positive results in the ODL segment driven by the pipeline tariff increase and lower costs during the quarter.
Frontera's Sustainability Strategy
The Company is advancing towards its 2028 sustainability goals as well as on the 2025 plan, with progress in almost every goal during the second quarter.
On the sustainability front, and in alignment with our supply chain strategy, we launched the Business Network for Responsible Business Conduct to promote best practices in human rights due diligence.
In the second quarter of 2025, local suppliers accounted for 11.37% of total purchases, reflecting the Company's ongoing commitment to support local economic development. Additionally, Frontera maintained strong performance in health and safety indicators, reporting achieved a Total Recordable Incident Rate ("TRIR") of 0.71. The Company also attained a water reuse rate of 37.6% within its operational activities.
Enhancing Shareholder Returns
The Company continues to consider investor-focused initiatives in the second half of 2025 and beyond, including 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, 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, the recapitalization or separation or of interest 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.
NCIB: Subsequent to the quarter, on July 15,2025, the Company announced the initiation of a Normal Course Issuer Bid, commencing July 18, 2025 and ending July 17, 2026, through which the Company may purchase up to 3,502,962 shares for cancellation, representing approximately 5% of the issued and outstanding shares ...
