All amounts are in U.S. Dollars unless otherwise indicated:

SECOND QUARTER HIGHLIGHTS

• Average production for the second quarter of 2024 was 3,128 BOEPD, an increase of 30% compared to the second quarter of 2023 average production of 2,415 BOEPD. The increase is due to production from the wells that were drilled and completed in the last six months of 2023 and the first six months of 2024.
• Adjusted EBITDA⁽¹⁾ was $10.0 million in the second quarter of 2024 compared to $7.6 million in the second quarter of 2023, an increase of 31%. The increase was due to the production increase and an increase in average prices of 7%
• Revenue, net of royalties was $13.9 million in the second quarter of 2024 compared to $10.1 million for second quarter of 2023, an increase of 38%, due to higher average production and prices
• Net income in the second quarter of 2024 was $4.1 million and EPS was $0.11/share compared to $4.3 million and EPS of $0.12/share in the second quarter of 2023. The decrease was due to higher income tax expense and higher operating expense partially offset by higher average prices and higher production
• Average netback from operations⁽²⁾ for the second quarter of 2024 was $40.40/boe, an increase of 1% from the prior year second quarter. Netback including commodity contracts⁽²⁾ for the second quarter of 2024 was $39.56/boe which was 2% higher than the prior year second quarter
• At June 30, 2024, the Company had $16.0 million of available borrowing capacity on its credit agreement

Kolibri’s President and Chief Executive Officer, Wolf Regener commented:

“We are pleased that the Company continues to increase production and Adjusted EBITDA as we demonstrate the growth potential of the Tishomingo field. Average production increased by 30% and Adjusted EBITDA increased 31% in the second quarter of 2024 compared to the second quarter of 2023 demonstrating our continued growth. We are excited to enter into a new phase of the Company’s development where we believe the most economic and efficient strategy is to drill longer laterals. We just started drilling the three Alicia Renee wells (all 100% working interest) that will each have a 1.5 mile lateral and we expect to bring those wells on production early in the fourth quarter of 2024.”

Second Quarter 2024 versus Second Quarter 2023

Oil and gas gross revenues totaled $17.7 million in the quarter versus $12.7 million in the second quarter of 2023, an increase of 39%. Oil revenues increased $4.7 million or 39% as average oil prices increased by $7.15 per barrel or 10% and oil production increased by 27% to 2,309 bopd. Natural gas revenues decreased $0.1 million or 37% to $0.1 million as average natural gas prices decreased by $0.99/mcf or 54% to $0.84/mcf partially offset by a natural gas production increase of 37% to 1,916 mcfpd. Natural gas liquids (NGLs) revenues increased $0.3 million or 58% as average NGL prices increased 14% to $18.24/boe and NGL production increased 39% to 500 boepd.

Average production for the second quarter of 2024 was 3,128 BOEPD, an increase of 30% compared to the second quarter of 2023 average production of 2,415 BOEPD due to production from the wells that were drilled and completed in the last six months of 2023 and the first six months of 2024.

Production and operating expenses for the second quarter of 2024 were $2.1 million compared to $1.1 million in the prior year comparable period. The increase was partially due to natural gas and NGL processing costs of $0.2 million, or $0.50 per BOE, related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024. Under the terms of the Company’s contract with the purchaser, adjustments to fee billings over the last 24 months are permissible. The adjustments received to date cover 2022 and 2023. In addition, the second quarter of 2024 included rework costs for wells that were impacted by offset fracture stimulations at the end of 2023 which totaled $0.31 per BOE. Without these fees and costs, operating expense per barrel would be $7.67 per BOE for the second quarter of 2024, an increase of 27% due to higher water hauling costs.

General and administrative expenses for the second quarter of 2024 was $1.5 million compared to $1.0 million for the second quarter of 2023, an increase of 50%. The increase was due to higher accounting fees and public company costs that resulted from listing on the NASDAQ stock market at the end of 2023 which increased by $0.4 million in the second quarter of 2024 as well as higher payroll and director fees mainly related to additional personnel and higher investor relations and marketing costs.

Finance expense increased $0.4 million in the second quarter of 2024 compared to the prior year second quarter due to higher interest expense as a result of higher interest rates and an increase in the outstanding bank loan balance in 2024.

FIRST SIX MONTHS 2024 HIGHLIGHTS

• Average production for the first six months of 2024 was 3,216 BOEPD, an increase of 15% compared to the first six months 2023 average production of 2,803 BOEPD. The increases are due to production from the wells that were drilled and completed in the last six months of 2023 and the first six months of 2024
• Adjusted EBITDA⁽¹⁾ was $20.4 million in the first six months of 2024 compared to $19.0 million in the first six months of 2023, an increase of 7%. The increase was due to the 15% increase in production and a 1% increase in average prices
• Revenue, net of royalties was $28.1 million in the first six months of 2024 compared to $24.4 million for first six months of 2023, an increase of 15%, as production increased by 15% and average prices increased by 1%
• Net income in the first six months of 2024 was $7.4 million compared to $12.2 million in the first six months of 2023. The decrease was due to higher income tax expense of $2.6 million and a $2.1 million unrealized gain on commodity contracts in the comparable prior year period partially offset by the increase in production and average prices
• Average netback from operations⁽²⁾ for the first six months of 2024 was $39.66/boe, a decrease of 6% from the prior year period. Netback including commodity contracts⁽²⁾ for the first six months of 2024 was $38.67/boe which was a decrease of 5% compared to the comparable prior year period

First Six Months of 2024 versus First Six Months of 2023

Oil and gas gross revenues totaled $35.9 million in the first six months of 2024 versus $30.8 million in the first six months of 2023, an increase of 17%. Oil revenues increased $5.0 million or 18% as oil production increased by 11% to 2,366 boepd and average oil prices increased by $3.69 per barrel or 5%. Natural gas revenues decreased $0.5 million or 43% to $0.6 million as average natural gas prices decreased by $1.76/mcf or 54% to $1.52/mcf partially offset by a natural gas production increase of 21% to 2,143 mcfpd. Natural gas liquids (NGLs) revenues increased $0.6 million or 38% as average NGL prices increased 7% to $23.18/boe and NGL production increased by 28% to 493 boepd.

Average production for the first six months of 2024 was 3,216 BOEPD, an increase of 15% compared to the first six months 2023 average production of 2,803 BOEPD. The increases are due to production from the wells that were drilled and completed in the last six months of 2023 and the first six months of 2024.

Production and operating expenses per barrel averaged $8.42 per BOE in the fix six months of 2024 compared to $6.04 per BOE in the prior year period. The increase was due to natural gas and NGL processing costs of $0.8 million, or $1.23 per BOE, related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024. Under the terms of the Company’s contract with the purchaser, adjustments to fee billings over the last 24 months are permissible. The adjustments received to date cover 2022 and 2023. In addition, the first six months of 2024 included rework costs for wells that were impacted by offset fracture stimulations at the end of 2023 which totaled $0.23 per BOE. Without these fees and costs, operating expense per barrel would be $6.96 per BOE for the first six months of 2024, an increase of 15% due to higher water hauling costs in 2024.

General and administrative expenses for the first six months of 2024 was $2.8 million compared to $2.0 million for the same period of 2023, an increase of 43%. The increase was due to higher accounting fees and public company costs that resulted from listing on the NASDAQ stock market at the end of 2023 which increased by $0.6 million in 2024 as well as higher payroll and director fees mainly related to additional personnel and higher investor relations and marketing costs.

Finance income decreased by $2.2 million for the first six months of 2024 due to an unrealized gain on commodity contracts in the comparable prior year period.

Finance expense increased $1.2 million in the first six months of 2024 compared to the prior year comparable period due to an unrealized loss on commodity contracts in 2024 and higher interest expense as a result of higher interest rates and an increase in the outstanding bank loan balance in 2024.

The information outlined above is extracted from and should be read in conjunction with the Company's unaudited financial statements for the three and six months ended June 30, 2024 and the related management's discussion and analysis thereof, copies of which are available under the Company's profile at 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 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 www.sedarplus.ca and is incorporated by reference into this earnings release.

Netback from operations per barrel and its components are calculated by dividing revenue, less royalties and operating expenses by the Company’s sales volume during the period. Netback including commodity contracts is calculated by adjusting netback from operations by the realized gains or losses received from commodity contracts during the period. Netback is a non-GAAP ratio but it is commonly used by oil and gas companies to illustrate the unit contribution of each barrel produced. The Company believes that the netback is a useful supplemental measure of the cash flow generated on each barrel of oil equivalent that is produced in its operations. However, non-GAAP measures and non-GAAP ratios do not have any standardized meaning prescribed by IFRS and therefore, may not be comparable to similar measures or ratios used by other companies and should not be used to make comparisons.

The following is the reconciliation of the non-GAAP ratio netback from operations to net income (loss) from continuing operations, 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, projected increases in production and cash flow, adjusted EBITDA and net debt, 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, 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 or increase, 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: the risk that 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, that 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 risk that 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 www.sedarplus.ca.

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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