All amounts are in U.S. Dollars unless otherwise indicated:
THIRD QUARTER 2025 HIGHLIGHTS
* Average production for the third quarter of 2025 was 4,254 BOEPD, an increase of 40% from the third quarter of 2024 average production of 3,032 BOEPD. The increase was due to production from the wells that were drilled and completed in the first nine months of 2025
* Revenue, net of royalties was $15.0 million in the third quarter of 2025 compared to $13.0 million for the third quarter of 2024, which was an increase of 15% due to a 40% increase in production partially offset by a decrease in average prices of 18%
* Net income in the third quarter of 2025 was $3.6 million and Basic EPS was $0.10/share, compared to net income of $5.1 million and Basic EPS of $0.14/share, in the same period of 2024. Net income in the third quarter of 2025 included a $0.5 million unrealized loss on commodity contracts compared to a $1.3 million unrealized gain on commodity contracts in the third quarter of 2024. The decrease was also due to higher depreciation expense and higher operating expenses from increased production in the third quarter of 2025 which offset the increase in revenues
* Adjusted EBITDA was $11.1 million in the third quarter of 2025 compared to $10.1 million in the third quarter of 2024, an increase of 9%. The increase was primarily due to an increase in revenues, partially offset by an increase in operating expenses due to the increase in production
* Production and operating expense per barrel averaged $7.37 per BOE in the third quarter of 2025 compared to $6.63 per BOE in the third quarter of 2024, an increase of 11%. The increase was due to reassessed production tax adjustments related to prior periods that were recorded in September 2025 totaling $0.3 million, or $0.80 per BOE. Excluding those costs, production and operating costs would have been $6.57 per BOE, a 1% decrease from the prior year
* Average netback from operations for the third quarter of 2025 was $30.84/boe, a decrease of 23% from the prior year third quarter due to lower prices in 2025. Average netback including commodity contracts for the third quarter of 2025 was $30.89 per boe, a decrease of 23% from the prior year third quarter
* In October 2025, the credit facility was redetermined with the same $65 million borrowing base. At September 30, 2025, the Company had $18.5 million of available borrowing capacity on its credit agreement.
KEI’s President and Chief Executive Officer, Wolf Regener commented:
“We are pleased that the Company continues to increase production, revenue and adjusted EBITDA as we execute our 2025 drilling program. Our production increased by 40% during the quarter and our adjusted EBITDA increased by 9% as compared to the third quarter of 2024. Our product mix was 66% oil during the third quarter and it increased to 71% in September due to the contribution of the higher percentage oil production from the Lovina wells. We are currently in completion operations on our last four wells for 2025 which we expect will start production in December. As we shifted the completion operations of our last four wells closer to the end of the year, we expect to exit the year with production at an all-time high. These latest wells will have the biggest impact in the first quarter of 2026 by increasing production and generating continued growth for the Company.
“The Forguson 17-20-3H well (46% working interest), which was completed in the 3 quarter of 2025 on its east side acreage, has still only recovered 4.5% of the frack fluid, with the well producing about 192 BOEPD, about 94 BOPD for the last week in October.”
Third Quarter 2025 versus Third Quarter 2024
Oil and gas gross revenues totaled $18.9 million in the third quarter of 2025 versus $16.5 million in the third quarter of 2024. Oil gross revenues totaled $16.5 million in the third quarter of 2025 versus $15.4 million in the third quarter of 2024. Oil revenues increased 7% as oil production increases of 25% were offset by average oil price decreases of 14%. Natural gas revenues increased by $0.7 million or 345% as natural gas prices increased 124% and production increased 98%. Natural gas liquids (NGLs) revenues increased by $0.6 million or 67% as NGL production increased 74% partially offset by price decreases of 4%.
Average third quarter 2025 production per day increased 1,222 BOEPD or 40% from the third quarter of 2024. The increase is due to production from the wells that were drilled and completed in the first nine months of 2025.
Production and operating expenses increased to $2.5 million in the third quarter of 2025, an increase of 64% due to higher production during the quarter. Operating expense per barrel averaged $7.37 per BOE in the third quarter of 2025 compared to $6.63 per BOE in the third quarter of 2024, an increase of 11%. The increase was due to reassessed production tax adjustments related to prior periods that were recorded in September 2025 totaling $0.3 million, or $0.80 per BOE.
General and administrative expenses increased by $0.1 million or 6% in the third quarter of 2025 due to costs related to the special shareholder meeting.
Finance income decreased by $1.3 million in the third quarter of 2025 compared to the prior year third quarter due to realized gains on commodity contracts in the third quarter of the prior year.
Finance expense increased by $0.5 million in the third quarter of 2025 due to unrealized losses on commodity contracts of $0.5 million in the third quarter of 2025.
FIRST NINE MONTHS 2025 HIGHLIGHTS
* Average production for the nine months ended September 30, 2025 was 3,851 BOEPD, an increase of 22% from the average production of 3,154 BOEPD in the same period of 2024. The increase is due to production from the wells that were drilled and completed in the first nine months of 2025
* Revenue, net of royalties was $42.1 million in the first nine months of 2025 compared to $41.2 million for the first nine months of 2023, which was an increase of 2%, as production increased by 22% partially offset by a decrease in average prices of 16%
* Net income for the first nine months of 2025 was $12.2 million and Basic EPS was $0.34/share compared to net income of $12.5 million and Basic EPS of $0.38/share for the first nine months of 2024 primarily due to an increase in depreciation expense and operating expense from the increase in production, partially offset by higher revenues
* Adjusted EBITDA was $31.6 million for the nine months ended September 30, 2025 compared to $30.5 million for the comparable prior year period, an increase of 3%. The increase was due to an increase in revenue partially offset by higher operating expenses due to the increase in production
* Production and operating expense per barrel averaged $7.20 per BOE in the first nine months of 2025 compared to $7.84 per BOE for the same period of 2024, a decrease of 8%
* Average netback from operations for the first nine months of 2025 was $32.86/boe, a decrease of 17% from the prior year period due to lower prices. Netback including commodity contracts for the first nine months of 2025 was $32.91/boe which was 16% lower than the comparable prior year period
First Nine Months of 2025 versus First Nine Months of 2024
Oil and gas gross revenues totaled $53.7 million in the first nine months of 2025 versus $52.4 million in the first nine months of 2024, an increase of 3%. Oil revenues were $46.5 million in the first nine months of 2025 versus $48.6 million in the same period of 2024, a decrease of 4%, as average oil prices decreased by 14% partially offset by production increases of 11%. Natural gas revenues increased by $2.2 million or 282% due to an average natural gas price increase of 127% and a 69% increase in natural gas production. NGL revenue increased by $1.2 million or 39% due to an increase in NGL production of 40% as the average NGL price was flat between the two periods.
Average production per day for the first nine months of 2025 increased 22% to 3,851 boepd from the prior year comparable period. The increase is due to production from the wells that were drilled and completed in the first nine months of 2025.
Production and operating expenses increased to $6.5 million or 10% in the first nine months of 2025 compared to the prior year period. Production and operating expense per barrel averaged $7.20 per BOE in the first nine months of 2025 compared to $7.84 per BOE for the same period of 2024, a decrease of 8%. The first nine months of 2025 amount includes reassessed production tax adjustments related to prior periods that were recorded in September 2025 totaling $0.3 million, or $0.30 per BOE. The first nine months of 2024 amount includes purchaser reassessed prior year gathering and processing costs, which were $0.8 million, or $0.83 per BOE. Excluding these adjustments, production and operating expenses per barrel were $6.90 per BOE in the nine months ended September 30, 2025 and $7.01 per BOE in the nine months ended September 30, 2024.
General and administrative expenses were $4.1 million in the first nine months of 2025 compared to $4.1 million in the comparable prior year period.
Finance income decreased by $0.8 million in the first nine months of 2025 due to unrealized gains on financial commodity contracts in the comparable prior year period.
Finance expense decreased by $0.9 million in the first nine months of 2025 due to lower realized losses on commodity contracts and lower interest expense compared to the comparable prior year period.
The information outlined above is extracted from and should be read in conjunction with the Company’s unaudited financial statements for the three and nine months ended September 30, 2025 and the related management’s discussion and analysis thereof, copies of which are available under the Company’s profile at http://www.sedarplus.ca.
NON-GAAP MEASURES
Netback from operations, netback including commodity contracts and adjusted EBITDA (collectively, the “Company’s Non-GAAP Measures”) are not measures or ratios recognized under Canadian generally accepted accounting principles (“GAAP”) and do not have any standardized meanings prescribed by IFRS. Management of the Company believes that such measures and ratios are relevant for evaluating returns on each of the Company’s projects as well as the performance of the enterprise as a whole. The Company’s Non-GAAP Measures may differ from similar computations as reported by other similar organizations and, accordingly, may not be comparable to similar non-GAAP measures and ratios as reported by such organizations. The Company’s Non-GAAP Measures should not be construed as alternatives to net income, cash flows related to operating activities, working capital or other financial measures and ratios determined in accordance with IFRS, as an indicator of the Company’s performance.
An explanation of the composition of the Company’s Non-GAAP Measures, how the Company’s Non-GAAP Measures provide useful information to an investor and the purposes for which the Company’s management uses the Non-GAAP Measures is set out in the management’s discussion and analysis under the heading “Non-GAAP Measures” which is available under the Company’s profile at http://www.sedarplus.ca and is incorporated by reference into this earnings release.
The following is the reconciliation of the non-GAAP ratio netback from operations to net income, which the Company considers to be the most directly comparable financial measure that is disclosed in the Company’s financial statements:
Adjusted EBITDA is calculated as net income before interest, taxes, depletion and depreciation and other non-cash and non-operating gains and losses. The Company considers this a key measure as it demonstrates its ability to generate cash from operations necessary for future growth excluding non-cash items, gains and losses that are not part of the normal operations of the Company and financing costs. The following is the reconciliation of the non-GAAP measure adjusted EBITDA:
PRODUCT TYPE DISCLOSURE
This news release includes references to sales volumes of “oil”, “natural gas”, and “barrels of oil equivalent” or “BOEs”. “Oil” refers to light crude oil and medium crude oil combined, and “natural gas” refers to shale gas, in each case as defined by NI 51-101. Production from our wells, primarily disclosed in this news release in BOEs, consists of mainly oil and associated wet gas. The wet gas is delivered via gathering system and then pipelines to processing plants where it is treated and sold as natural gas and NGLs.
CAUTIONARY STATEMENTS
In this news release and the Company’s other public disclosure:
Caution Regarding Forward-Looking Information
This release contains forward-looking information including information regarding the proposed timing and expected results of exploratory and development work including production from the Company’s Tishomingo field, Oklahoma acreage, expectations regarding cash flow and continued growth in the fourth quarter, the Company’s reserves based loan facility, including scheduled repayments, expected hedging levels and the Company’s strategy and objectives. The use of any of the words “target”, “plans”, “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “believe” and similar expressions are intended to identify forward-looking statements.
Such forward-looking information is based on management’s expectations and assumptions, including that the Company’s geologic and reservoir models and analysis will be validated, that indications of early results are reasonably accurate predictors of the prospectiveness of the shale intervals, that previous exploration results are indicative of future results and success, that expected production from future wells can be achieved as modeled and that declines will match the modeling, that future well production rates will be improved over existing wells, that rates of return as modeled can be achieved, that recoveries are consistent with management’s expectations, that additional wells are actually drilled and completed, that design and performance improvements will reduce development time and expense and improve productivity, that discoveries will prove to be economic, that anticipated results and estimated costs will be consistent with management’s expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the Company will continue to be able to access sufficient capital through financings, credit facilities, farm-ins or other participation arrangements to maintain its projects, that the Company will continue in compliance with the covenants under its reserves-based loan facility and that the borrowing base will not be reduced, that funds will be available from the Company’s reserves based loan facility when required to fund planned operations, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company’s business and its ability to advance its business strategy.
Forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: any of the assumptions on which such forward-looking information is based vary or prove to be invalid, including that the Company’s geologic and reservoir models or analysis are not validated, anticipated results and estimated costs will not be consistent with management’s expectations, the risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration and development projects or capital expenditures; the uncertainty of reserve and resource estimates and projections relating to production, costs and expenses, and health, safety and environmental risks including flooding and extended interruptions due to inclement or hazardous weather), the risk of commodity price and foreign exchange rate fluctuations, risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with continued development of the Tishomingo Field, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company’s assumptions, that very low or no production rates are achieved, that the Company will cease to be in compliance with the covenants under its reserves-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base re-determination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that funding is not available from the Company’s reserves based loan facility at the times or in the amounts required for planned operations, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve and the other risks identified in the Company’s most recent Annual Information Form under the “Risk Factors” section, the Company’s most recent management’s discussion and analysis and the Company’s other public disclosure, available under the Company’s profile on SEDAR+ at http://www.sedarplus.ca.
With respect to estimated reserves, the evaluation of the Company’s reserves is based on a limited number of wells with limited production history and includes a number of assumptions relating to factors such as availability of capital to fund required infrastructure, commodity prices, production performance of the wells drilled, successful drilling of infill wells, the assumed effects of regulation by government agencies and future capital and operating costs. All of these estimates will vary from actual results. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, may vary. The Company’s actual production, revenues, taxes, development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. In addition to the foregoing, other significant factors or uncertainties that may affect either the Company’s reserves or the future net revenue associated with such reserves include material changes to existing taxation or royalty rates and/or regulations, and changes to environmental laws and regulations.
Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking information included in this release is expressly qualified in its entirety by this cautionary statement. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.
About Kolibri Global Energy Inc.
Kolibri Global Energy Inc. is a North American energy company focused on finding and exploiting energy projects in oil and gas. Through various subsidiaries, the Company owns and operates energy properties in the United States. The Company continues to utilize its technical and operational expertise to identify and acquire additional projects in oil, gas and clean and sustainable energy. The Company’s shares are traded on the Toronto Stock Exchange under the stock symbol KEI and on the NASDAQ under the stock symbol KGEI.
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Contact
For further information, contact:
Wolf E. Regener, President and Chief Executive Officer +1 (805) 484-3613
Email: [email protected]
Website: http://www.kolibrienergy.com
