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 Year-to-Date, Revised Production Guidance to 39,000 -- 39,500 Boe/d
Declared Quarterly Dividend of C$0.0625 Per Share, or $3.1 Million in Aggregate, Payable On or Around January 19, 2026
Accelerated Puerto Bahia LPG FID: Phase 1 Expected To Be Operational in the First Half of 2026
FEC Equity Qualified to Trade in OTCQX$(R)$ Best Market, Providing Improved Investor Visibility and Trading Liquidity
CALGARY, AB, Nov. 13, 2025 /PRNewswire/ - 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, generated 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 cash (including restricted cash), underscoring its strong balance sheet.
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(R) 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.
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 $10 and 15 million in yearly project EBITDA once it reaches its target capacity."
Third Quarter 2025 Operational and Financial Summary:
Nine months ended
September 30
---------- ---------- ---------- ----------------------
Q3 2025 Q2 2025 Q3 2024 2025 2024
------------------------ -------- ---------- ---------- ---------- ---------- ----------
Operational Results from
Continuing Operations
------------------------
Heavy crude oil
production (1) (bbl/d) 27,078 27,535 25,312 27,259 24,520
Light and medium crude
oil combined
production (1) (bbl/d) 9,235 9,850 11,018 9,538 11,016
Total crude oil
production (bbl/d) 36,313 37,385 36,330 36,797 35,536
Conventional natural
gas production (1) (mcf/d) 4,406 3,118 3,192 3,272 3,494
Natural gas liquids (boe/d)
production (1) (3) 1,848 1,846 1,950 1,869 1,792
Total production (boe/d)
Colombia (2) (3) 38,934 39,778 38,840 39,240 37,941
Total inventory balance
of Colombia and Peru (bbl) 919,914 1,109,347 1,257,358 919,914 1,257,358
Brent price reference ($/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
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
Number
Outstanding Common of
Shares 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.
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 continuing 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
resolved. 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.
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.
-- 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.
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 12, 2025, the Company had 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, representing 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.
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:
2025 August 2025 Updated
Guidance Metrics Unit Guidance 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
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
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 $27.1 million during the second quarter of 2025. ODL saw strong quarter over quarter volume increase and EBITDA, led by an increase in production associated with Ecopetrol's Caño Sur block.
Puerto Bahía's operating EBITDA was relatively flat quarter over quarter despite a reduction in liquids associated to a third-part trader's exit from the country. The financial impact of the reduced liquids throughput volumes was offset entirely by a strong performance from general cargo operations, which saw strong growth in container volumes, that surpassed 3,000 TEUs in September.
On the SAARA side, the Company continued to increase water management volumes reaching an average of 156,767 barrels of water per day for the quarter. The Company achieved maximum throughput capacity of 230,000 barrels of water per day, gaining momentum towards its goal of 250,000 barrels per day.
Three months ended Nine months ended
September 30 September 30
-------------------- -------------------
($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
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) $4.6 million towards the connection project between Puerto Bahia's port facility and the Cartagena refinery, (ii) tank maintenance, and (iii) general cargo terminal facilities. The third quarter also includes investment in the SAARA project and palm oil plantation.
Three months ended Nine months ended
September 30 September 30
--------------------------- -------------------
($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:
Nine months
ended September
30
------------------------ ----------------
Q3
($M) Q3 2025 Q2 2025 2024 2025 2024
------------------ --------------- ------- ------- ------ ------- -------
Fresh fruit
bunches for palm
oil (produced -
sold) (Tons) 6,214 7,039 5,184 20,937 19,174
Production per
hectare per year
(1) (Tons/ha/year) 9.35 8.86 7.71 9.35 7.71
Palm oil fruit
price ($/Ton) 198 189 172 200 165
Volumes of reverse
osmosis water
treated (bwpd) 156,767 119,409 49,589 119,495 32,505
Volumes 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 Venture jointly holds 100% working interest in the Corentyne block, located offshore Guyana. Frontera Guyana and CGX Resources have agreed that their respective participating interests are 72.52% and 27.48%, which includes a 4.52% interest that CGX Resources agreed to assign to Frontera Guyana in 2023. This assignment remains subject to the approval of the 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.
The following table summarizes Frontera's hedging position as of November 13, 2025.
Type of Positions Strike Prices
Term Instrument (bbl/d) 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:
Open Interest Strike Prices
Term Type of Instrument (US$ MM) 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.
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
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Advisories:
Cautionary Note Concerning Forward-Looking Statements
This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future including, without limitation, statements regarding the 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(R) 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 structure, 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, future 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, 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 Petroleum Exporting Countries; uncertainties associated with estimating and establishing oil and natural gas reserves and resources; liabilities inherent with the exploration, development, exploitation and reclamation of oil and natural gas; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; increases or changes to transportation costs; expectations regarding the Company's ability to raise capital and to continually add reserves through acquisition and development; the Company's ability to complete strategic initiatives or transactions to enhance the value of its common shares and the timing thereof; the Company's ability to access additional financing; the ability of the Company to maintain its credit ratings; the ability of the Company to: meet its financial obligations and minimum commitments, fund capital expenditures and comply with covenants contained in the agreements that govern indebtedness; 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 Venture 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 they are therefore unlikely to be comparable to similar measures presented by other companies. Furthermore, these financial measures should not be considered in isolation or as a substitute for measures of performance or cash flows as prepared in accordance with IFRS. These financial measures do not replace or supersede any standardized measure under IFRS. Other companies in our industry may calculate these measures differently than we do, limiting their usefulness as comparative measures.
The Company discloses these financial measures, together with measures prepared in accordance with IFRS, because management believes they provide useful information to investors and shareholders, as management uses them to evaluate the operating performance of the Company. These financial measures highlight trends in the Company's core business that may not otherwise be apparent when relying solely on IFRS financial measures. Further, management also uses non-IFRS measures to exclude the impact of certain expenses and income that management does not believe reflect the Company's underlying operating performance. The Company's management also uses non-IFRS measures in order to facilitate operating performance comparisons from period to period and to prepare annual operating budgets and as a measure of the Company's ability to finance its ongoing operations and obligations.
Set forth below is a description of the non-IFRS financial measures, non-IFRS ratios, supplementary financial measures and capital management measures used in the MD&A.
Operating EBITDA from Continuing Operations *
EBITDA is a commonly used non-IFRS financial measure that adjusts net income (loss) as reported under IFRS to exclude the effects of income taxes, finance income and expenses, and DD&A. Operating EBITDA from continuing operations is a non-IFRS financial measure that represents the operating results of the Company's primary business, excluding the following items: restructuring, severance and other costs, post-termination obligation, trunkline costs, temporal taxes, payments of minimum work commitments and, certain non-cash items (such as impairments, foreign exchange, unrealized risk management contracts, share-based compensation and debt extinguishment cost) and gains or losses arising from the disposal of capital assets. In addition, other unusual or non-recurring items are excluded from operating EBITDA from continuing operations, as they are not indicative of the underlying core operating performance of the Company.
The following table provides a reconciliation of net income (loss) to Operating EBITDA from continuing operations:
Three months ended Nine months ended
September 30 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 Nine months ended
September 30 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
Infrastructure Colombia Calculations
Each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative, is a non-IFRS financial measure, and each is used to evaluate the performance of the Infrastructure Colombia Segment operations. Adjusted Infrastructure Revenue includes revenues of the Infrastructure Colombia Segment including ODL's revenue direct participation interest. Adjusted Infrastructure Operating Costs includes costs of the Infrastructure Colombia Segment including ODL's cost direct participation interest. Adjusted Infrastructure General and Administrative includes general and administrative costs of the Infrastructure Colombia Segment including ODL's general and administrative direct participation interest.
A reconciliation of each of Adjusted Infrastructure Revenue, Adjusted Infrastructure Operating Costs and Adjusted Infrastructure General and Administrative is provided below.
Three months ended Nine months ended
September 30 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 Nine months ended
September 30 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
Net Sales
Net sales is a non-IFRS financial measure that adjusts revenue to include realized gains and losses from oil risk management contracts while removing the cost of any volumes purchased from third parties. This is a useful indicator for management, as the Company hedges a portion of its oil production using derivative instruments to manage exposure to oil price volatility. This metric allows the Company to report its realized net sales after factoring in these oil risk management activities. The deduction of cost of purchases is helpful to understand the Company's sales performance based on the net realized proceeds from its own production, the cost of which is partially recovered when the blended product is sold. Net sales also exclude sales from port services, as it is not considered part of the oil and gas segment. Refer to the reconciliation in the "Sales" section on page 10 of the MD&A.
Operating Netback and Oil and Gas Sales, Net of Purchases
Operating netback is a non-IFRS financial measure and operating netback per boe is a non-IFRS ratio. Operating netback per boe is used to assess the net margin of the Company's production after subtracting all costs associated with bringing one barrel of oil to the market. It is also commonly used by the oil and gas industry to analyze financial and operating performance expressed as profit per barrel and is an indicator of how efficient the Company is at extracting and selling its product. For netback purposes, the Company removes the effects of any trading activities and results from its Infrastructure Colombia Segment from the per barrel metrics and adds the effects attributable to transportation and operating costs of any realized gain or loss on foreign exchange risk management contracts. Refer to the reconciliation in the "Operating Netback" section on page 9 of the MD&A.
The following is a description of each component of the Company's operating netback and how it is calculated. Oil and gas sales, net of purchases, is a non-IFRS financial measure that is calculated using oil and gas sales less the cost of volumes purchased from third parties including its transportation and refining costs. Oil and gas sales, net of purchases per boe, is a non-IFRS ratio that is calculated using oil and gas sales, net of purchases, divided by the total sales volumes, net of purchases. A reconciliation of this calculation is provided below:
Three months ended Nine months ended
September 30 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.
Non-IFRS Ratios
Realized oil price, net of purchases, and realized gas price per boe
Realized oil price, net of purchases, and realized gas price per boe are both non-IFRS ratios. Realized oil price, net of purchases, per boe is calculated using oil sales net of purchases, divided by total sales volumes, net of purchases. Realized gas price is calculated using sales from gas production divided by the conventional natural gas sales volumes.
Three months ended Nine months ended
September 30 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 ($/mcf) 8.98 6.77 7.35 6.27
---------------------------------- --------- --------- --------- ---------
* Figures from previous reporting periods were changed due to the
re-presentation of continuing operations following the divestment of non-core
assets in Ecuador. Refer to the "Discontinued Operations" section on page 18
for further details.
(1) Non-IFRS financial measure.
(2) 2024 comparative figures differ from those previously reported due to the
inclusion of Puerto Bahia inter-segment costs related to diluent and oil
purchases as well as transportation costs.
Net sales realized price
Net sales realized price is a non-IFRS ratio that is calculated using net sales (including oil and gas sales net of purchases, realized gains and losses from oil risk management contracts and less royalties). Net sales realized price per boe is a non-IFRS ratio which is calculated dividing each component by total sales volumes, net of purchases. A reconciliation of this calculation is provided below:
Three months ended Nine months ended
September 30 September 30
-------------------- --------------------
2025 2024 2025 2024
---------------------------------- --------- --------- --------- ---------
Oil and gas sales, net of
purchases ($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.
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 Nine months ended
September 30 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 hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:
Three months ended Nine months ended
September 30 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
Energy costs, net of realized FX hedge impact is a non-IFRS financial measure that describes the electricity consumption and the costs of localized energy generation and the realized gain or loss on foreign exchange risk management contracts attributable to energy costs. Energy cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using energy cost, net of realized FX hedge impact divided by production (before royalties). A reconciliation of this calculation is provided below:
Three months ended Nine months ended
September 30 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 or loss on foreign exchange risk management contracts attributable to transportation costs. Transportation cost, net of realized FX hedge impact per boe is a non-IFRS ratio that is calculated using transportation cost, net of realized FX hedge impact divided by net production after royalties. A reconciliation of this calculation is provided below:
Three months ended Nine months ended
September 30 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 PAP. Royalties per boe is a supplementary financial measure that is calculated using the royalties divided by total sales volumes, net of purchases.
Capital Management Measures
Restricted cash short- and long-term
Restricted cash (short- and long-term) is a capital management measure, that sums the short-term portion and long-term portion of the cash that the Company has in term deposits that have been escrowed to cover future commitments and future abandonment obligations, or insurance collateral for certain contingencies and other matters that are not available for immediate disbursement.
Total cash
Total cash is a capital management measure to describe the total cash and cash equivalents restricted and unrestricted available, is comprised by the cash and cash equivalents and the restricted cash short and long-term.
Total debt and lease liabilities
Total debt and lease liabilities are capital management measures to describe the total financial liabilities of the Company and is comprised of the debt of the 2028 Unsecured Notes, loans, and liabilities from leases of various properties, power generation supply, vehicles and other assets.
Definitions:
bbl(s) Barrel(s) of oil
-------------- --------------------------------------------------------------
bbl/d Barrel of oil per day
-------------- --------------------------------------------------------------
boe Refer to "Boe Conversion" disclosure above
-------------- --------------------------------------------------------------
boe/d Barrel of oil equivalent per day
-------------- --------------------------------------------------------------
Mcf Thousand cubic feet
-------------- --------------------------------------------------------------
Net Production Net production represents the Company's working interest
volumes, net of royalties and internal consumption
-------------- --------------------------------------------------------------
View original content:https://www.prnewswire.com/news-releases/frontera-announces-third-quarter-2025-results-302615239.html
SOURCE Frontera Energy Corporation
(END) Dow Jones Newswires
November 13, 2025 23:26 ET (04:26 GMT)