Earnings release
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FRONTERA ENERGY CORPORATION NEWS RELEASE FRONTERA ANNOUNCES THIRD QUARTER 2025 RESULTS Recorded Net Income of $25.4 million, Including $15 Million in Insurance Recoveries Related to Sabanero Block Generated Quarterly Operating EBITDA from Continuing Operations of $86.6 Million Generated Adjusted Infrastructure EBITDA of $30.4 million and Segment Income of $15.5 Million, Led by Strong ODL Performance Streamlined Organization Resulting in Leaner, More Efficient Structure Generating $10 - $15 Million in Expected Overhead Savings Going Forward Reduced Production Costs 5% and Transportation Costs 1% Through Operational Improvements Averaged 39,240 Boe/d Y ear-to-Date, Revised Production Guidance to 39,000 – 39,500 Boe/d Declared Quarterly Dividend of C$0.0625 Per Share, or $3.1 Million in Aggregate, Payable On or Around January 19, 2026 Accelerated Puerto Bahia LPG FID: Phase 1 Expected To Be Operational in the First Half of 2026 FEC Equity Qualified to Trade in OTCQX® Best Market, Providing Improved Investor Visibility and Trading Liquidity CALGARY, November 13, 2025 /CNW/ - Frontera Energy Corporation (TSX: FEC) (“Frontera” or the “Company”) today reported financial and operational results for the third quarter ended September 30, 2025. All financial amounts in this news release and in the Company’s financial disclosures are in United States dollars, unless otherwise stated. Figures from previous reporting periods were revised due to the re-presentation of continuing operations following the divestment of non-core assets in Ecuador. For more information, refer to the “Discontinued Operations” section of the interim management's discussion and analysis for the three and nine months ended September 30, 2025, dated November 13, 2025 (the "MD&A"). Gabriel de Alba, Chairman of the Board of Directors, commented: “In the third quarter, Frontera remained focused on enforcing capital discipline, driving savings and efficiency to navigate lower commodity prices. During the quarter, the Company generated $86.6 million in Operating EBITDA from continuing operations, gene rated Adjusted Infrastructure EBITDA of $30.4 million and $115.0 million in cash provided by operating activities, extended its crude oil hedges through the first half of 2026 and ended the quarter with $172.1 million of total c ash (including restricted cash), underscoring its strong balance sheet.
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Regarding the Company’ s Guyana Exploration business, the Government of Guyana, through its counsel, communicated its willingness to participate in a final “Without Prejudice” meeting with Frontera and its partner CGX Energy Inc (“CGX” and together the “Joint Venture”) to discuss the matters in dispute. The Government proposed November 25 or December 2, 2025, as possible dates for this meeting. The Joint Venture remains open to engaging in good faith discussions with the government. Frontera continues to prioritize initiatives that drive stakeholder value. Today, the Board declared a quarterly dividend of C$0.0625 per share, or approximately $3.1 million in aggregate, and year to date, the Company has repurchased 385,200 shares via its Normal-Course Issuer Bid (“NCIB”) program. Over the last twelve months, Frontera has returned over $112 million to shareholders via dividends and share repurchases, including $66.5 million paid to shareholders during the third quarter through a Substantial Issuer Bid (“SIB”), reducing its shares outstanding by 14% since the end of 2024, and the Company successfully repurchased over $80 million of its senior unsecured notes due 2028 reducing the balance outstanding to $314 million , underscoring the Company's commitment to return capital to all its stakeholders. Frontera is pleased to announce its qualification for the OTCQX® Best Market, an important milestone that increases the Company’ s visibility in the United States and reinforces its commitment to strong financial disclosure and corporate governance. Trading on OTCQX enhances access to a broader U.S. investor base, including the U.S. retail market, offering shareholders improved liquidity and more efficient participation under the Company’ s existing TSX reporting framework. Notably, OTC market activity has represented over 30% of FEC’ s total share trading over the past five years, highlighting the relevance of the U.S. market to Frontera’ s investor community. Access to this highest tier of the U.S. OTC markets further strengthens Frontera’ s ability to reach a broader investor base and enhance long-term value creation. Trading will commence tomorrow, November 14th, under the symbol “FECCF”.” Orlando Cabrales, Chief Executive Officer (CEO), Frontera, commented: “Frontera's third quarter financial and operating results highlight the decisive steps we are taking to deliver stakeholder value, maintain operational flexibility, drive cost efficiencies and maintain a strong balance sheet. During the quarter, we continued to prioritize operational improvements, reducing our production costs quarter-over-quarter by 5%, driven by the implementation of new field production technologies, continuous optimization, cost reduction in O&M contracts and digital process implementation. We also reduced our transportation costs by 1% quarter-over-quarter driven by optimizing our transportation routes and pipeline agreements, including the expiry of our long term Ocensa P-135 Take or Pay agreement. These improvements were partially offset by increasing energy costs as we processed higher liquids volumes during the quarter. We also simplified our corporate structure during the third quarter, through targeted reorganization initiatives that will improve organizational and operational efficiencies, generating between $10 and 15 million in expected savings in overhead going forward. Production during the quarter decreased 2%, mainly due to adverse weather conditions as well as related operational and logistical challenges, which have since been resolved. The 2025 rainy season stands among the most severe in a decade, with well above historical rainfall averages impacting operations. For the nine months ending September 30, Frontera averaged 39,240 boe/d of production, an increase of over 3% compared with the same periods of 2024.
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Considering these factors, we have adjusted our 2025 annual Colombia production guidance slightly to 39,000 - 39,500 boe/d. We have also tightened our 2025 capital expenditures guidance, reducing the higher end by around $25 million, to reflect the disciplined approach to capital spending and ability to identify ongoing operational efficiencies. Subsequent to the quarter, Frontera spudded the high -impact Guapo-1 well at the VIM -1 block, targeting natural gas and condensate. Drilling is expected to be completed by December 2025. The Guapo-1 well has the potential to significantly improve the Company’ s natural gas reserves, including to potentially provide much needed supply to the Colombian market in the short to medium term and help de-risk nearby contingent prospects. On our infrastructure business, we continue to see strong momentum supporting all areas of this business unit. ODL saw strong quarter over quarter volumes and EBITDA growth led by an increase in production associated with Ecopetrol’ s Caño Sur block. In Puerto Bahía, the port’ s operating EBITDA was relatively flat quarter over quarter despite a reduction in liquids throughput volumes associated to a trader’ s exit from the country. The financial impact of the reduced liquids throughput volumes was offset entirely by a strong performance from our general cargo operations, which saw strong growth in container volumes, that surpassed 3,600 twenty-foot equivalent units (“TEUs”) in October. On SAARA, water management volumes continue to increase and stabilize, reaching an average of approximately 157,000 barrels of water per day processed during the quarter, including reaching a maximum throughput of 230,000 barrels per day, and gaining momentum towards our goal of 250,000 barrels per day. The Company’ s standalone and growing Colombian infrastructure business, which includes interests in ODL and Puerto Bahía, together with its partner GASCO, has reached final investment decision (“ FID”) on the planned liquified petroleum gas (“LPG”) project. The initial phase is being fast -tracked and is expected to be operational in the first half of 2026, helping address supply constraints in Colombia’ s domestic LPG market. The LPG project is expected to generate between $10 and 15 million in yearly project EBITDA once it reaches its target capacity.” Third Quarter 2025 Operational and Financial Summary: Nine months ended September 30 Q3 2025 Q2 2025 Q3 2024 2025 2024 Operational Results from Continuing Operations Heavy crude oil production (1) (bbl/d) 27,078 27,535 25,312 27,259 24,520 Light and medium crude oil combined production (1) (bbl/d) 9,235 9,850 11,018 9,538 11,016 Total crude oil production (bbl/d) 36,313 37,385 36,330 36,797 35,536 Conventional natural gas production (1) (mcf/d) 4,406 3,118 3,192 3,272 3,494 Natural gas liquids production (1) (boe/d) (3) 1,848 1,846 1,950 1,869 1,792 Total production Colombia (2) (boe/d) (3) 38,934 39,778 38,840 39,240 37,941 Total inventory balance of Colombia and Peru (bbl) 919,914 1,109,347 1,257,358 919,914 1,257,358 Brent price reference ($/bbl) 68.17 66.71 78.71 69.91 81.82 Produced crude oil and gas sales (4) ($/boe) 64.40 63.18 71.13 65.37 75.12 Purchased crude net margin (4)(5) ($/boe) (2.70) (3.65) (3.59) (3.41) (3.14) Oil and gas sales, net of purchases (4)(5) ($/boe) 61.70 59.53 67.54 61.96 71.98 (Loss) gain on oil price risk management contracts (6)(7) ($/boe) (1.20) 0.16 (0.47) (0.84) (1.03) Royalties (6) ($/boe) (0.78) (0.71) (0.80) (0.81) (1.43) Net sales realized price (4)(5) ($/boe) 59.72 58.98 66.27 60.31 69.52
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Production costs (excluding energy costs), net of realized FX hedge impact (4) ($/boe) (8.46) (8.89) (8.89) (9.10) (10.03) Energy costs, net of realized FX hedge impact (4) ($/boe) (5.56) (4.75) (5.25) (5.25) (5.19) Transportation costs, net of realized FX hedge impact (4)(5) ($/boe) (11.72) (11.81) (12.59) (12.02) (11.88) Operating netback from Continuing Operations per boe (4)(5) ($/boe) 33.98 33.53 39.54 33.94 42.42 Financial Results Oil & gas sales, net of purchases (8) ($M) 194,153 165,439 203,017 550,506 608,475 (Loss) gain on oil price risk management contracts (7) ($M) (3,784) 431 (1,425) (7,494) (8,710) Royalties ($M) (2,454) (1,965) (2,412) (7,207) (12,105) Net sales (8) ($M) 187,915 163,905 199,180 535,805 587,660 Net income (loss) for the period from continuing operations (9) ($M) 28,235 (410,857) 16,923 (357,007) 1,857 Net (loss) income for the period from discontinued operations ($M) (2,818) (44,355) (335) (45,264) 3,382 Net income (loss) for the period (9) ($M) 25,417 (455,212) 16,588 (402,271) 5,239 Per share – diluted from continuing operations ($) 0.38 (5.32) 0.19 (4.73) 0.02 Per share – diluted from discontinued operations ($) (0.04) (0.57) — (0.60) 0.04 General and administrative ($M) 14,877 14,021 12,473 42,276 38,472 Outstanding Common Shares Number of Shares 69,833,514 77,295,478 84,167,856 69,833,514 84,167,856 Operating EBITDA from continuing operations (8) ($M) 86,585 73,489 96,494 239,122 295,498 Cash provided by operating activities ($M) 115,034 41,786 124,058 226,957 339,461 Capital expenditures (8) ($M) 50,859 58,967 74,872 155,946 206,140 Cash and cash equivalents – unrestricted ($M) 158,614 184,860 205,572 158,614 205,572 Restricted cash short and long-term (10) ($M) 13,437 12,679 34,752 13,437 34,752 Total cash (10) ($M) 172,051 197,539 240,324 172,051 240,324 Total debt and lease liabilities (10) ($M) 532,789 535,346 531,235 532,789 531,235 Consolidated total indebtedness (excluding Unrestricted Subsidiaries) (11) ($M) 357,228 353,764 415,387 357,228 415,387 Net debt (excluding Unrestricted Subsidiaries) (11) ($M) 252,640 204,671 267,043 252,640 267,043 * 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 18 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 43 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 43 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 26 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 measure (as defined in NI 52-112). Refer to the “Non-IFRS and Other Financial Measures” section on page 26 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 17 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 26 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 26 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 33 of the MD&A for further details.
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Executive Changes and Restructuring In the third quarter, as part of Frontera’s ongoing focus on cost-savings, the company simplified its corporate structure, through targeted reorganization initiatives that are designed to improve organizational and operational efficiencies , resulting in $10 - $15 million in expected savings in overhead going forward. Effective September 29, 2025, Mr. Ivan Arevalo, Vice President Operations assumed responsibility for Reservoir and Reserves. This adjustment is aligned with the Company’s vision to enhance synergies, optimize processes, and ensures a comprehensive approach to managing all aspects of our operations. Mr. Arevalo has more than 30 years of experience in the oil and gas industry and has been with the Company for more than 17 years. On September 29, 2025, Mr. Andrés Sarmiento was promoted to Vice -President of Corporate Sustainability & People. Mr. Sarmiento is an Economist with a Master’s degree in Economics from the Universidad de los Andes and a master’s degree in Energy, Mining, and Finance from Imperial College London. Prior to joining Frontera, Mr. Sarmiento previously was secretary general of the Colombian Association of Natural Gas, was a senior investment advisor in the London Office of ProColombia and an advisor to several ministers and vice ministers in the Colombian Ministry of Mines and Energy. The Company congratulates Mr. Arevalo and Mr. Sarmiento on their expanded roles. With these organizational changes, Frontera aims to strengthen operational efficiency, align capabilities to address future challenges, and establish a more agile structure while building a more sustainable future. Third Quarter 2025 Operational and Financial Results: • The Company recorded net income, attributable to equity holders of the Company, from continuing operations of $28.2 million ($0.38/share), in the third quarter of 2025, compared with a net loss, attributable to equity holders of the Company, from continuin g operations of $410.9 million, net of a non -cash impairment expenses of $431.9 million ($5.32/share) in the prior quarter and net income from continuing operations of $16.9 million ($0.19/share) in the third quarter of 2024. Net income from continuing operations included a loss from operations of $13.9 million (net of a non- cash impairment expense of $9.7 million), finance expenses of $18.9 million and $4.9 million related to loss on risk management contracts, partially offset by an income tax recovery of $20.6 million (including $20.9 million of deferred income tax recovery), $15.9 million from share of income from associates, other income by $12.0 million mainly related to insurance recoveries for the Sabanero block by $14.7 million, and foreign exchange income of $2.1 million. • Total Colombian production averaged 38,934 boe/d in the third quarter of 2025, compared with 39,778 boe/d in the prior quarter and 38,840 boe/d in the third quarter of 2024. Heavy crude oil production declined by 2% during the quarter, mainly due to adverse weather conditions as well as related operational and logistical challenges , which have since been resolve d. Offset by increases in conventional natural gas production driven by the commercialization of volumes from the VIM-1 block. Additionally, Colombian light and medium crude oil combined production decrease by 6%, primarily due to natural declines.
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Production Nine months ended September 30 Production from Continuing Operations: Q3 2025 Q2 2025 Q3 2024 2025 2024 Producing blocks in Colombia Heavy crude oil (bbl/d) 27,078 27,535 25,312 27,259 24,520 Light and medium crude oil combined (bbl/d) 9,235 9,850 11,018 9,538 11,016 Conventional natural gas (mcf/d) 4,406 3,118 3,192 3,272 3,494 Natural gas liquids (boe/d) 1,848 1,846 1,950 1,869 1,792 Total production Colombia (boe/d) 38,934 39,778 38,840 39,240 37,941 Production from Discontinued Operations (1): Producing blocks in Ecuador Light and medium crude oil combined (bbl/d) 940 1,277 1,776 1,226 1,637 Total production Ecuador (bbl/d) 940 1,277 1,776 1,226 1,637 (1) Refer to the “Discontinued Operations” section on page 18 of the MD&A for further details. • Operating EBITDA from continuing operations was $86.6 million in the third quarter of 2025 , compared with $73.5 million in the prior quarter and $96.5 million in the third quarter of 2024. The quarter over quarter increase was mainly due to higher volumes sold during the quarter, higher Brent oil prices and lower production costs and transportation cost (net of realized FX hedge impact), partially offset by higher energy costs. • Cash provided by operating activities was $115.0 million in the third quarter of 2025, compared with $41.8 million in the prior quarter, and $124.1 million in the third quarter of 2024. During the quarter, the Company invested $50.9 million in capital expenditures, paid $66.5 million to shareholders through its substantial issuer bid, received $14.7 million in insurance compensation for the Sabanero block and received $18.5 million in cash dividends from ODL. • The Company reported a total cash position of $172.1 million at September 30, 2025, compared with $197.5 million at June 30, 2025, and $240.3 million at September 30, 2024. • As at September 30, 2025, the Company had a total crude oil inventory balance of 919,914 barrels compared to 1,109,347 barrels at June 30, 2025. The Company had a total inventory balance in Colombia of 439,714 barrels, including 348,544 crude oil barrels and 91,170 barrels of diluent and others. This compared to 629,147 barrels as at June 30, 2025, and 777,158 barrels as at September 30, 2024. The decrease in inventory levels quarter over quarter was associated with higher volumes of oil inventory sold during the quarter. • Capital expenditures were $50.9 million in the third quarter of 2025, compared with $59.0 million in the prior quarter and $74.9 million in the third quarter of 2024. During the third quarter the Company drilled 16 wells primarily in the Quifa and CPE-6 blocks. • The Company's net sales realized price was $59.72/boe in the third quarter of 2025, compared to $58.98/boe in the prior quarter and $66.27/boe in the third quarter of 2024. The quarter over quarter increase was primarily driven by a higher Brent benchmark oil price, stronger oil price differentials, partially offset by premiums paid on oil price risk management contracts.
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• The Company's operating netback from continuing operations was $ 33.98/boe in the third quarter of 2025, compared with $33.53/boe in the prior quarter and $39.54/boe in the third quarter of 2024. The increase in the Company's operating netback quarter-over-quarter was mainly due to higher net sales realized price, lower production costs and transportation cost, (net of realized FX hedge impacts), partially offset by higher energy costs • Production costs (excluding energy costs), net of realized FX hedge impact, averaged $8.46/boe in the third quarter of 2025, compared with $ 8.89/boe in the prior quarter and $ 8.89/boe in the third quarter of 2024 . The decrease in production costs was primarily due to new field production technologies, continuous optimization, cost reduction in O&M contracts and digital process implementation. • Energy costs, net of realized FX hedging impacts, averaged $ 5.56/boe in the third quarter of 2025 , compared to $4.75/boe in the prior quarter and up from $5.25/boe in the third quarter of 2024. The increase quarter over quarter was mainly due to higher fuel consumption resulting from higher processed production liquid volumes. • Transportation costs, net of realized FX hedging impacts averaged $ 11.72/boe in the third quarter of 2025, compared with $11.81/boe in the prior quarter and $ 12.59/boe in the third quarter of 2024 . The decrease in transportation costs during the quarter was mainly driven by the optimization of the transportation routes and pipeline agreements including the termination of the Ocensa P-135 long-term Take-or-Pay agreement. • Restructuring costs during the quarter were $8.3 million, driven by targeted reorganization initiatives, resulting in expected savings of 20% in corporate overhead going forward. • ODL volumes transported were 241,958 bbl/d during the third quarter of 2025, up slightly led by an increase in volumes from Ecopetrol’s Caño Sur block, compared with the previous quarter, which saw 235,804 bbl/d in volumes transported. • Total Puerto Bahia liquids volumes were 39,560 bbl/d during the quarter compared to 53,280 bbl/d the previous quarter, the reduction in liquids volumes was due to a third-party trader’s exit from the country. The Company is actively seeking to replace the lost volumes. The financial impact of the reduced liquids throughput volumes was offset entirely by a strong performance from the general cargo operations, which saw strong growth in container volumes, that surpassed 3,000 TEUs in September. • Adjusted Infrastructure EBITDA in the quarter was $30.4 million, compared to $27.1 million in the prior quarter. The quarter over quarter increase was mainly a result of higher revenues from the ODL business due to higher volumes transported through the pipeline. Frontera’s Sustainability Strategy During the quarter, the Company continued to make progress towards its 2028 sustainability goals and achieved 81% of its 2025 plan year to date. In line with its supply chain sustainability strategy, the Company strengthened its Business Network for Responsible Business Conduct — a collaborative platform that fosters human rights due diligence, shared policies, and best practices — ensuring a consistent and responsible approach across suppliers and key subsidiaries, including Puerto Bahía and ProAgrollanos.
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In the third quarter of 2025, local suppliers accounted for 11.58% 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 a Total Recordable Incident Rate ("TRIR") of 0.57. The Company also attained a water reuse rate of 36% within its operational activities. In addition, Frontera achieved the “Level of Excellence” certified by Great Place to Work. Enhancing Shareholder Returns The Company continues to consider investor -focused initiatives for the remainder 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 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: On July 18, 2025, the Company initiated a Normal Course Issuer Bid (“ NCIB”), through which the Company may purchase up to 3,502,962 shares for cancellation, representing approximately 5% of the issued and outstanding shares as at July 15, 2025. As at November 1 2, 2025, the Company ha d repurchased approximately 385,200 Common Shares for cancellation for approximately $1.6 million. The NCIB will expire on July 17, 2026. SIB: On July 15, 2025, the Company announced that, it had taken up and paid for 7,583,333 common shares (approximately 9.77% of the total number of Frontera's issued and outstanding common shares as at July 10, 2025) at a price of CAD$12.00 per common share, r epresenting an aggregate purchase price of approximately CAD $91.0 million pursuant to a substantial issuer bid. The July 2025 substantial issuer bid had a 92.6% participation, and the tendered shares were purchased on a pro rata basis. Shareholders who tendered to the substantial issuer bid had approximately 10.54% of their tendered shares purchased by the Company. With an over 90% consistent participation rate in its recent SIBs, the Company's capital distribution strategy has proven effective and well received by shareholders. Dividend: Pursuant to Frontera's dividend policy, Frontera's Board of Directors declared a dividend of C$0.0625 per common share to be paid on or around January 19, 2026, to shareholders of record at the close of business on January 5, 2026. This dividend payment to shareholders is designated as an "eligible dividend" for purposes of the Income Tax Act (Canada). This dividend is eligible for the Company's Dividend Reinvestment Plan which provides Canadian resident shareholders of Frontera the option to automatically reinvest the cash dividends on their common shares into additional common shares, without paying brokerage commissions or services charges. Frontera's Three Core Businesses Frontera's three core businesses include: (1) its Colombia Upstream Onshore business, (2) its standalone and growing Colombian Infrastructure business, and (3) its potentially transformational Guyana Exploration business offshore Guyana.
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2025 Guidance Update Frontera’s average production was 39,240 boe/d for the nine -month period ended September 30, 2025. The Company has adjusted production guidance for 2025 to 39,000 - 39,500 boe/d. The Company has also tightened its 2025 capital expenditures guidance to reflect its disciplined approach to capital spending and ability to identify ongoing operational efficiencies and updated its EBITDA guidance range to reflect the lower oil price environment. The following table reports the Company’s 2025 updated guidance as well as its actual results for the nine months ended September 30, 2025: Guidance Metrics Unit 2025 August Guidance 2025 Updated Guidance Actual * Average Daily Production (1) boe/d 39,500 - 41,000 39,000 - 39,500 39,240 Production Costs (2)(4) $/boe 8.75 - 9.25 9.03 Energy Costs (2)(4) $/boe 5.25 - 5.75 5.32 Transportation Costs (3)(4) $/boe 12.50 - 13.00 12.02 Operating EBITDA from Continuing Operations (5) at $70/bbl (6) $MM 320 - 360 239.1 Operating EBITDA from Continuing Operations (5) at $65/bbl (6) $MM 270 – 315 239.1 Adjusted Infrastructure EBITDA (5) $MM 110 – 125 86.1 Development Drilling $MM 100 - 110 95 - 100 83.7 Development Facilities $MM 45 - 65 60 – 65 42.5 Colombia Development $MM 145 - 175 155 - 165 126.2 Colombia Exploration $MM 25 - 35 30 - 35 14.6 Other (7) $MM 10 - 15 2 - 5 1.9 Total Colombia Capex $MM 180 - 225 187 - 205 142.7 Guyana Exploration $MM 1 - 3 1 - 3 0.4 Colombia Infrastructure $MM 15 - 20 12 - 15 12.9 Total Capital Expenditures from Continuing Operations (5) $MM 196 - 248 200 - 223 156 * The figures correspond only to continuing operations, following the divestment of non -core assets in Ecuador. Refer to the “Discontinued Operations” section for further details. (1)The Company's 2025 updated average production guidance range reflects its gross working interest production before royalties and does not include in-kind royalties, operational consumption, quality volumetric compensation or potential production from successful exploration activities planned in 2025. (2)Per-bbl/boe metric on a share before royalties' basis. (3)Calculated using net production after royalties. (4)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 for further details. (5)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 for further details. (6)2025 Updated Guidance Operating EBITDA from continuing operations calculated at Brent between $70/bbl and $65/bbl, and COP/USD exchange rate of 4,150:1 (7)Other includes HSEQ activities and new field production technologies. Colombia Upstream Onshore Colombia
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Frontera produced 38,934 boe/d from its Colombian operations in the third quarter (consisting of 27,078 bbl/d of heavy crude oil, 9,235 bbl/d of light and medium crude oil, 4,406 mcf/d of conventional natural gas and 1,848 boe/d of natural gas liquids). The Company drilled 16 development wells primarily at the Quifa and CPE -6 blocks and completed well interventions at 7 others during the quarter. Currently, the Company has 1 drilling rig and 1 well intervention rigs active in Colombia. Quifa Block: Quifa SW and Cajua At Quifa, production averaged 17,586 bbl/d of heavy crude oil (including both Quifa and Cajua) in the third quarter compared to 17,576 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 quarter, the Company processed approximately 1.78 million barrels of water per day in Quifa including SAARA. CPE-6 At CPE-6, production averaged approximately 7,710 bbl/d of heavy crude oil during the third quarter, compared to 7,771 bbl/d during the second quarter of 2025. During the quarter, the Company invested in the expansion of crude oil storage capacity and the implementation of new field production technologies. The Company processed approximately 357 thousand barrels of water per day in CPE -6 in the third quarter of 2025. The Company’s current water handling capacity in CPE-6 is approximately 380 thousand barrels of water per day. Other Colombia Developments At Guatiquia, production during the quarter averaged 5,145 bbl/d of light and medium crude compared with 5,385bbl/d in the second quarter of 2025. In the Cubiro block production averaged 981 bbl/d of light and medium crude oil during quarter compared with 1,057 bbl/d in the second quarter of 2025. At VIM-1 (Frontera 50% W.I., non-operator), production averaged 2,187 boe/d of light and medium crude oil during the third quarter compared to 1,960 boe/d of light and medium crude oil in the second quarter of 2025. At the Sabanero block, production averaged 1,781 boe/d of heavy oil crude production during the third quarter compared to 2,189 boe/d in the second quarter of 2025. Colombia Exploration Assets
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The Company’s exploration focus during the third quarter remained on the Lower Magdalena Valley and Llanos Basins in Colombia. At the VIM-1 block, activities related to the Guapo-1 exploration well are ongoing. Civil works have been completed, and the well was spudded in October 16, 2025. At the Llanos -119 block, the Colombian National Hydrocarbon Agency (“ ANH”) approved the request to transfer commitments to VIM -46 block to acquire a 3D seismic survey. 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. 2. Infrastructure Colombia Frontera's Infrastructure Colombia Segment includes the Company's 35% equity interest in the ODL pipeline through Frontera's wholly owned subsidiary, 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). Frontera’s and its partner GASCO, announced that the partners had reached a final investment decision on its planned LPG project. The initial phase of the project is being fast-tracked and expected to be operational in the first half of 2026. supporting the challenges in Colombia’s domestic LPG market. The LPG project will generate between $10 and 15 million in yearly project EBITDA once it reaches its target capacity. The Company continues to pursue strategic investment opportunities to maximize the port’s infrastructure and drive long-term value creation. The Reficar connection's construction was completed, and the Port's efforts have shifted to working together with Ecopetrol to start utilizing the connection and establishing Puerto Bahia as a strategic partner for the Reficar Refinery. Infrastructure Colombia Segment Results Adjusted Infrastructure EBITDA in the third quarter of 2025 was $30.4 million, compared with $27.1 million during the second quarter of 2025. ODL saw strong quarter over quarter volume increase and EBITDA, led by an increase in production associated with Ecopetrol’s Caño Sur block. Puerto Bahía’s operating EBITDA was relatively flat quarter over quarter despite a reduction in liquids associated to a third- part trader’s exit from the country . The financial impact of the reduced liquids throughput volumes was offset entirely by a strong performance from general cargo operations, which saw strong growth in container volumes, that surpassed 3,000 TEUs in September. On the SAARA side, the Company continued to increase water management volumes reaching an average of 156,767 barrels of water per day for the quarter. The Company achieved maximum throughput capacity of 230,000 barrels of water per day, gaining momentum towards its goal of 250,000 barrels per day. Three months ended September 30 Nine months ended September 30 ($M) 2025 2024 2025 2024 Adjusted Infrastructure Revenue 49,172 42,152 139,053 126,114 Adjusted Infrastructure Operating Costs (15,800) (12,416) (43,943) (36,552) Adjusted Infrastructure General and Administrative (2,928) (3,555) (9,006) (9,871) Adjusted Infrastructure EBITDA 30,444 26,181 86,104 79,691 (1) Non-IFRS financial measure
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Segment capital expenditures for the three months ended September 30, 2025, totaled $4.8 million primarily driven by Puerto Bahia investments of $3.9 million, including: (i) $4.6 million towards the connection project between Puerto Bahia’s port facility and the Cartagena refinery, (ii) tank maintenance, and (iii) general cargo terminal facilities. The third quarter also includ es investment in the SAARA project and palm oil plantation. Three months ended September 30 Nine months ended September 30 ($M) Q3 2025 Q2 2025 Q3 2024 2025 2024 Revenue 15,647 14,479 11,247 42,990 34,669 Costs (11,244) (10,493) (7,592) (30,667) (23,339) General and administrative expenses (1,429) (1,180) (1,528) (4,116) (4,396) Depletion, depreciation and amortization (2,815) (2,100) (1,921) (6,941) (5,699) Other operating costs (472) (552) (495) (1,238) (1,653) Infrastructure Colombia (loss) income from operations (313) 154 (289) 28 (418) Share of income from associates - ODL 15,857 14,124 13,411 45,090 40,712 Infrastructure Colombia segment income 15,544 14,278 13,122 45,118 40,294 Infrastructure Colombia segment cash flow from operating activities 22,062 1,594 12,679 49,236 43,246 Capital Expenditures Infrastructure Colombia Segment (1) 5,344 4,834 13,860 12,878 21,883 (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 26 of the MD&A. The following table shows the volumes pumped per injection point in ODL: Nine months ended September 30 (bbl/d) Q3 2025 Q2 2025 Q3 2024 2025 2024 At Rubiales Station 131,536 133,187 172,745 145,752 170,768 At Caño Sur Station 50,484 59,435 — 31,743 — At Jagüey and Palmeras Stations 59,938 43,182 71,252 60,575 75,634 Total 241,958 235,804 243,997 238,070 246,402 The following table shows throughput for the liquids port facility at Puerto Bahia: Nine months ended September 30 (bbl/d) Q3 2025 Q2 2025 Q3 2024 2025 2024 FEC volumes 10,286 10,914 12,459 9,870 14,147 Third party 29,274 42,366 34,505 28,361 39,868 Total 39,560 53,280 46,964 38,231 54,015 The following table shows the barrels of water per day treated and irrigated in SAARA and field performance indicators for Proagrollanos:
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Nine months ended September 30 ($M) Q3 2025 Q2 2025 Q3 2024 2025 2024 Fresh fruit bunches for palm oil (produced - sold) (Tons) 6,214 7,039 5,184 20,937 19,174 Production per hectare per year (1) (Tons/ha/year) 9.35 8.86 7.71 9.35 7.71 Palm oil fruit price ($/Ton) 198 189 172 200 165 V olumes of reverse osmosis water treated (bwpd) 156,767 119,409 49,589 119,495 32,505 V olumes of water irrigated for palm oil cultivation (2) (bwpd) 150,125 118,831 44,585 117,106 27,594 (1)Tons per hectare per year for the three months ended September 30, are calculated using the total production for the last twelve months ended September 30. 3. Guyana - Arbitration 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. The parties have been unable to reach a mutual resolution to date. On November 4, 2025, the GoG, through its counsel, communicated its willingness to participate in a final “Without Prejudice” meeting with the Joint Venture to discuss the matters in dispute. The Government proposed November 25 or December 2, 2025, as possible dates for this meeting. The Joint Venture remains open to engaging in good faith discussions with the Government. 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 Government of Guyana reaffirmed 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. As previously disclosed, the Company evaluated the recoverability of the Corentyne E&E asset in light of the GoG’s conduct and unwillingness to recognize the Joint Venture’s rights during the consultation period. This resulted in an impairment of $432.2 million, reducing the carrying value of the Corentyne E&E asset to $Nil as of June 30, 2025 (December 31, 2024: $431.9 million). The Joint V enture jointly holds 100% working interest in the Corentyne block, located offshore Guyana. Frontera Guyana and CGX Resources have agreed that their respective participating interests are 72.52% and 27.48%, which includes a 4.52% interest that CGX Resources agreed to assign to Frontera Guyana in 2023. This assignment remains subject to the approval of the Government of Guyana but is enforceable between Frontera Guyana and CGX Resources. Hedging Update As part of its risk management strategy, Frontera uses derivative commodity instruments to manage exposure to price volatility by hedging a portion of its oil production. The Company's strategy aims to protect 40 -60% of its estimated net after royalties' production using a combination of instruments, capped and non-capped, to protect the revenue generation and cash position of the Company, while maximizing the upside, thereby allowing the Company to take a more dynamic approach to the management of its hedging portfolio.
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The following table summarizes Frontera's hedging position as of November 13, 2025. Term Type of Instrument Positions (bbl/d) Strike Prices Put/Call Oct 25 Put Spread 15,161 65/55 Nov 25 Put Spread 15,000 65/55 Dec 25 Put Spread 14,516 65/55 4Q-2025 Total Average 14,891 Jan 26 Put Spread 8,097 65/55 Feb 26 Put Spread 14,500 65/55 Mar 26 Put Spread 20,613 64.3/55 1Q-2026 Total Average 14,400 Apr 26 Put Spread 8,073 62.7/55 May 26 Put Spread 21,258 62.7/55 Jun 26 Put Spread 14,633 62.7/55 2Q-2026 Total Average 14,727 The Company is exposed to foreign currency fluctuations primarily arising from expenditures that are incurred in COP and its fluctuation against the USD. As of November 13, 2025 the Company had the following foreign currency derivatives contracts: Term Type of Instrument Open Interest (US$ MM) Strike Prices Put/Call Hedging Ratio 4Q-2025 Zero-Cost Collars 30 4,295/4,787 20% Third Quarter 2025 Financial Results Conference Call Details A conference call for investors and analysts will be held on Friday, November 14th, 2025, at 11:00 a.m. Eastern Time. Participants will include Gabriel de Alba, Chairman of the Board of Directors, Orlando Cabrales, Chief Executive Officer, Rene Burgos, Chief Financial Officer, and other members of the senior management team. Analysts and investors are invited to participate using the following dial-in numbers: RapidConnect URL: https://emportal.ink/4m3hn0f Participant Number (Toll Free North America): 1-888-510-2154 Participant Number (Toll Free Colombia): +57-601-489-8375 Participant Number (International): 1-437-900-0527 Conference ID: 20437 Webcast URL: www.fronteraenergy.ca A replay of the conference call will be available until 11:59 p.m. Eastern Time on November 21st, 2025.
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Encore Toll free Dial-in Number: 1-888-660-6345 International Dial-in Number: 1-289-819-1450 Encore ID: 20437 About Frontera: Frontera Energy Corporation is a Canadian public company involved in the exploration, development, production, transportation, storage and sale of oil and natural gas in South America, including related investments in both upstream and midstream facilities. The Company has a diversified portfolio of assets with interests in 22 exploration and production blocks in Colombia, Ecuador and Guyana, and pipeline and port facilities in Colombia. Frontera is committed to conducting business safely and in a socially, environmentally and ethically responsible manner. If you would like to receive News Releases via e -mail as soon as they are published, please subscribe here: http://fronteraenergy.mediaroom.com/subscribe. Social Media Follow Frontera Energy social media channels at the following links: Twitter: https://twitter.com/fronteraenergy?lang=en Facebook: https://es-la.facebook.com/FronteraEnergy/ LinkedIn: https://co.linkedin.com/company/frontera-energy-corp. Advisories: Cautionary Note Concerning Forward-Looking Statements This news release contains forward -looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future includin g, without limitation, statements regarding the Company's goal of enhancing shareholder value by returning capital to shareholders, among other initiatives, the expected completion date of the LPG Project and its impact on Colombia's domestic LPG market, the Company's intent to consider future shareholder initiatives including a potential future separation of interest in one or more subsidiaries or in assets of the Company, whether in on or a series of transactions , the expected impact of the Company's qualification for the OTCQX® Best Market marks and the commencement of trading thereunder, the expected production for November and the rest of 2025, the expected benefits of the reorganization to simplify corporate st ructure, the Company's consideration of investor focused initiatives, the potential outcome of the dispute with the GoG over the Corentyne block, the Company's exploration and development plans and objectives, production levels, profitability, costs, futur e income generation capacity, cash levels (including the timing and ability to release restricted cash), regulatory approval, and the Company's hedging program and its ability to mitigate the impact of changes in oil prices 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,
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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 and sanctions imposed on numerous countries; the impact of international conflicts including the Russia -Ukraine conflict and the conflict in the Middle East and other escalating geopolitical tensions; actions of the Organization of P etroleum Exporting Countries; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; the Company’ s ability to complete strategic initiatives or transactions to enhance the value of its common shares and the timing thereof; the Company's ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants con tained 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 on receipt of government approvals; fluctuations in foreign exchange or interest rates and stock market volatility, the ability of the Joint V enture to reach an agreement with the GoG in respect of the Joint Venture’ s interest in the agreements relating to the Corentyne block, and the other risks disclosed under the heading "Risk Factors" and elsewhere in the Company's annual information form dated March 10, 2025 filed on SEDAR+ at www.sedarplus.ca. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward -looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward -looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein. This news release contains future oriented financial information and financial outlook information (collectively, "FOFI") (including, without limitation, statements regarding expected average production), and are subject to the same assumptions, risk factors, limitations and qualifications as set forth in the above paragraph. The FOFI has been prepared by management to provide an outlook of the Company's activities and results, and such information may not be appropriate for other purposes. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management's reasonable estimates and judgments, however, actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein. Any FOFI speaks only as of the date on which it is made, and the Company disclaims any intent or obligation to update any FOFI, whether as a result of new information, future events or results or otherwise, unless required by applicable laws. Non-IFRS Financial Measures This press release contains various "non-IFRS financial measures" (equivalent to "non-GAAP financial measures", as such term is defined in NI 52 -112), "non-IFRS ratios" (equivalent to " non-GAAP ratios", as such term is defined in NI 52 -112), "supplementary financial measures" (as such term is defined in NI 52-112) and "capital management measures" (as such term is defined in NI 52-112), which are described in further detail below. Such measures do not have standardized IFRS definitions. The Company's determination of these non -IFRS financial measures may differ from other reporting issuers and the y are
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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 e xpenses 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 a nnual 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:
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Three months ended September 30 Nine months ended September 30 ($M) 2025 2024 2025 2024 Net income (loss) for the period from continuing operations (1) 28,235 16,923 (357,007) 1,857 Finance income (1,745) (3,123) (5,285) (6,512) Finance expenses 18,899 17,570 52,445 51,779 Income tax (recovery) expense (20,600) 6,329 (44,079) 63,730 Depletion, depreciation and amortization 75,472 65,581 200,304 192,054 Colombian temporary taxes (2) 2,392 — 5,250 — Expense of asset retirement obligation 3,283 5,546 3,809 4,549 Impairment expense 9,706 361 442,733 1,780 Trunkline costs (3) — 3,829 2,000 3,829 Post-termination obligation 2,708 (314) 2,599 (128) Share-based compensation (779) (143) 1,683 858 Restructuring, severance and other costs 8,278 361 18,805 3,216 Share of income from associates (15,857) (13,411) (45,090) (40,712) Foreign exchange (income) loss (2,076) 631 (1,762) 9,246 Other (income) loss (12,013) 4,203 (13,367) 7,368 Unrealized loss (gain) on risk management contracts 3,130 (7,644) (5,212) 3,941 Realized gain on risk management contract for ODL dividends received 1,221 288 1,221 288 Non-controlling interests (13,669) (201) (13,964) (644) Gain on repurchase of senior unsecured notes net of consent solicitation — (292) (11,925) (1,001) Debt extinguishment cost — — 5,964 — Operating EBITDA from continuing operations 86,585 96,494 239,122 295,498 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 September 30 Nine months ended September 30 2025 2024 2025 2024 Consolidated Statements of Cash Flows Additions to oil and gas properties, infrastructure port, and plant and equipment 48,031 83,258 151,090 218,685 Additions to exploration and evaluation assets 1,154 1,301 3,677 10,278 Total additions in Consolidated Statements of Cash Flows 49,185 84,559 154,767 228,963 Non-cash adjustments (1) 1,674 (7,206) 1,222 (20,342) Cash adjustments (2) — (2,481) (43) (2,481) Total Capital Expenditures from Continuing Operations 50,859 74,872 155,946 206,140 Capital Expenditures attributable to Infrastructure Colombia Segment 5,344 13,860 12,878 21,883 Capital Expenditures attributable to other segments different to Infrastructure Colombia Segment 45,515 61,012 143,068 184,257 Total Capital Expenditure from Continuing Operations 50,859 74,872 155,946 206,140 (1) Related to materials inventory movements, capitalized non-cash items and other adjustments
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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 op erations. 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 includin g 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 September 30 Nine months ended September 30 ($M) (1) 2025 2024 2025 2024 Revenue Infrastructure Colombia Segment 15,647 11,247 42,990 34,669 Revenue from ODL 95,786 88,301 274,466 261,272 Direct participation interest in the ODL 35 % 35 % 35 % 35 % Equity adjustment participation of ODL (1) 33,525 30,905 96,063 91,445 Adjusted Infrastructure Revenues 49,172 42,152 139,053 126,114 Operating cost Infrastructure Colombia Segment (11,244) (7,592) (30,667) (23,339) Operating Cost from ODL (13,017) (13,782) (37,931) (37,750) Direct participation interest in the ODL 35 % 35 % 35 % 35 % Equity adjustment participation of ODL (1) (4,556) (4,824) (13,276) (13,213) Adjusted Infrastructure Operating Costs (15,800) (12,416) (43,943) (36,552) General and administrative Infrastructure Colombia Segment (1,429) (1,528) (4,116) (4,396) General and administrative from ODL (4,284) (5,792) (13,974) (15,643) Direct participation interest in the ODL 35 % 35 % 35 % 35 % Equity adjustment participation of ODL (1) (1,499) (2,027) (4,890) (5,475) Adjusted Infrastructure General and Administrative (2,928) (3,555) (9,006) (9,871) (1) Revenues and expenses related to ODL are accounted for using the equity method, as described in Note 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 September 30 Nine months ended September 30 ($M) 2025 2024 2025 2024 Adjusted Infrastructure Revenue (1) 49,172 42,152 139,053 126,114 Adjusted Infrastructure Operating Costs (1) (15,800) (12,416) (43,943) (36,552) Adjusted Infrastructure General and Administrative (1) (2,928) (3,555) (9,006) (9,871) Adjusted Infrastructure EBITDA 30,444 26,181 86,104 79,691 (1) Non-IFRS financial measure
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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 purp oses, 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 September 30 Nine months ended September 30 2025 2024 2025 2024 Produced crude oil and products sales ($M) (1) 202,667 213,798 580,810 635,041 Purchased crude net margin ($M) (2)(3) (8,514) (10,781) (30,304) (26,566) Oil and gas sales, net of purchases ($M) (2) 194,153 203,017 550,506 608,475 Sales volumes, net of purchases - (boe) 3,146,860 3,005,640 8,884,239 8,453,174 Produced crude oil and gas sales ($/boe) 64.40 71.13 65.37 75.12 Oil and gas sales, net of purchases ($/boe) (2) 61.70 67.54 61.96 71.98 * 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 18 of the MD&A for further details. (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 21 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 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.
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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 pric e is calculated using sales from gas production divided by the conventional natural gas sales volumes. Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 Oil and gas sales, net of purchases ($M) (1)(2) 194,153 203,017 550,506 608,475 Crude oil sales volumes, net of purchases - (bbl) 3,073,301 2,955,899 8,733,579 8,286,708 Conventional natural gas sales volumes - (mcf) 419,241 283,837 859,626 948,850 Realized oil price, net of purchases ($/bbl) (2) 61.95 68.03 62.31 72.71 Realized conventional natural gas price ($/mcf) 8.98 6.77 7.35 6.27 * Figures from previous reporting periods were changed due to the re-presentation of continuing operations following the divestment of non-core assets in Ecuador. Refer to the “Discontinued Operations” section on page 18 for further details. (1) Non-IFRS financial measure. (2) 2024 comparative figures differ from those previously reported due to the inclusion of Puerto Bahia inter-segment costs related to diluent and oil purchases as well as transportation costs. Net sales realized price Net sales realized price is a non -IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts and less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below: Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 Oil and gas sales, net of purchases ($M) (1)(2) 194,153 203,017 550,506 608,475 Loss (gain) on oil price risk management contracts, net ($M) (3) (3,784) (1,425) (7,494) (8,710) (-) Royalties ($M) (2,454) (2,412) (7,207) (12,105) Net sales ($M) 187,915 199,180 535,805 587,660 Sales volumes, net of purchases - (boe) 3,146,860 3,005,640 8,884,239 8,453,174 Oil and gas sales, net of purchases ($/boe) (2) 61.70 67.54 61.96 71.98 Premiums received (paid) on oil price risk management contracts (3)(4) (1.20) (0.47) (0.84) (1.03) Royalties ($/boe) (4) (0.78) (0.80) (0.81) (1.43) Net sales realized price ($/boe) (2) 59.72 66.27 60.31 69.52 * 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 18 of the MD&A for further details. (1) Non-IFRS financial measure. (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) 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 16 of the MD&A for further details. (4) Supplementary financial measure.
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Purchase crude net margin Purchase crude net margin is a non-IFRS financial measure that is calculated using the purchased crude oil and products sales, less the cost of those volumes purchased from third parties including its transportation and refining costs. Purchase crude net margin per boe is a non-IFRS ratio that is calculated using the Purchase crude net margin, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below: Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 Purchased crude oil and products sales ($M) 44,372 47,963 150,874 148,283 (-) Cost of diluent and oil purchased ($M) (1) (52,250) (57,557) (179,719) (170,569) Puerto Bahía inter-segment costs (2) (636) (1,187) (1,459) (4,280) Purchased crude net margin ($M) (2) (8,514) (10,781) (30,304) (26,566) Sales volumes, net of purchases - (boe) 3,146,860 3,005,640 8,884,239 8,453,174 Purchased crude net margin ($/boe) (2) (2.70) (3.59) (3.41) (3.14) * 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 18 of the MD&A for further details. (1) Cost of third-party volumes purchased for use and resale in the Company's oil operations, including associated transportation and refining costs. (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. 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 hedg e impact divided by production (before royalties). A reconciliation of this calculation is provided below: Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 Production costs (excluding energy costs) ($M) 29,831 31,007 94,803 107,066 (-) Realized (gain) loss on FX hedge attributable to production costs (excluding energy costs) ($M) (1) (1,205) 182 (1,248) (3,358) SAARA inter-segment costs 1,675 587 3,911 587 Production costs (excluding energy costs), net of realized FX hedge impact ($M) (2) 30,301 31,776 97,466 104,295 Production Colombia (boe) 3,581,928 3,573,280 10,712,520 10,395,834 Production costs (excluding energy costs), net of realized FX hedge impact ($/boe) 8.46 8.89 9.10 10.03 * 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 18 of the MD&A for further details. (1) See “Gain (Loss) on Risk Management Contracts” on page 16 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
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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 i s provided below: Three months ended September 30 Nine months ended September 30 2025 2024 2025 2024 Energy costs ($M) 20,589 18,664 56,951 55,183 (-) Realized loss (gain) on FX hedge attributable to energy costs ($M) (1) (689) 84 (689) (1,267) Energy costs, net of realized FX hedge impact ($M) (2) 19,900 18,748 56,262 53,916 Production Colombia (boe) 3,581,928 3,573,280 10,712,520 10,395,834 Energy costs, net of realized FX hedge impact ($/boe) 5.56 5.25 5.25 5.19 * 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 16 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 o r 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 September 30 Nine months ended September 30 2025 2024 2025 2024 Transportation costs ($M) 38,407 38,779 115,882 108,096 (-) Realized (gain) loss on FX hedge attributable to transportation costs ($M) (1) (867) 61 (867) (982) Puerto Bahía inter-segment costs (2) 776 613 2,104 1,514 Transportation costs, net of realized FX hedge impact ($M) (2)(3) 38,316 39,453 117,119 108,628 Net production Colombia (boe) 3,267,932 3,132,784 9,739,821 9,146,942 Transportation costs, net of realized FX hedge impact ($/boe) (2) 11.72 12.59 12.02 11.88 * 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 18 of the MD&A for further details. (1) See “Gain (Loss) on Risk Management Contracts” on page 16 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 P AP . Royalties per boe is a supplementary financial measure that is calculated using the royalties divided by total sales volumes, net of purchases.
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Capital Management Measures Restricted cash short- and long-term Restricted cash (short- and long-term) is a capital management measure, that sums the short-term portion and long-term portion of the cash that the Company has in term deposits that have been escrowed to cover future commitments and future abandonment obligations, or insurance collateral for certain contingencies and other matters that are not available for immediate disbursement. Total cash Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available, is comprised by the cash and cash equivalents and the restricted cash short and long-term. Total debt and lease liabilities Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company and is comprised of the debt of the 2028 Unsecured Notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets. Definitions: bbl(s) Barrel(s) of oil bbl/d Barrel of oil per day boe Refer to "Boe Conversion" disclosure above boe/d Barrel of oil equivalent per day Mcf Thousand cubic feet Net Production Net production represents the Company's working interest volumes, net of royalties and internal consumption FOR FURTHER INFORMATION: ir@fronteraenergy.ca www.fronteraenergy.ca