Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

JUNE 30, 2025

MANAGEMENT’S DISCUSSION AND ANALYSIS

The following is management’s discussion and analysis (“MD&A”) of Kolibri Global Energy Inc.’s (“KEI” or the “Company”) operating and financial results for the six months ended June 30, 2025, compared to the corresponding period in the prior year, as well as information and expectations concerning the Company’s outlook based on currently available information. The MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements for the six months ended June 30, 2025 and the audited consolidated financial statements and MD&A for the year ended December 31, 2024. The condensed consolidated interim financial statements have been prepared in accordance with International Accounting Standard 34 “Interim Financial Reporting”. The reporting and measurement currency is the United States dollar. Additional information relating to KEI including its Annual Information Form is filed on SEDAR at www.sedarplus.ca and on the Company’s website at www.kolibrienergy.com.

Netback from operations, netback including commodity contracts, net operating income and adjusted EBITDA (collectively, the “Company’s Non-GAAP Measures”) are not measures or ratios recognized under International Financial Reporting Standards and International Accounting Standards as issued by the International Accounting Standards Board (IASB) and Interpretations (collectively “IFRS Accounting Standards”) and do not have any standardized meanings prescribed by IFRS Accounting Standards. 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 from operating activities, working capital or other financial measures and ratios determined in accordance with IFRS Accounting Standards, as an indicator of the Company’s performance.

This report is prepared as of August 8, 2025. Please read carefully the important cautionary notes regarding technical information, forward-looking statements and other matters set out in this report.

Description of Business

KEI 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 and gas. The common shares of the Company trade on the Toronto Stock Exchange (“TSX”) under the symbol “KEI” and on the NASDAQ under the symbol “KGEI”.

Operating Summary

The Company’s results of operations are dependent on production volumes of natural gas, crude oil and natural gas liquids and the prices received for the production. Prices for these commodities have shown significant volatility during recent years and are determined by supply and demand factors, including weather and general economic conditions.

(1) Net operating income is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

(2) Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

(3) Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

Highlights

The average production for the second quarter of 2025 was 3,220 BOEPD, an increase of 3% compared to second quarter 2024 production of 3,128 BOEPD. Average production for the six months ended June 30, 2025 was 3,646 BOEPD, an increase of 13% from the average production of 3,216 BOEPD in the same period of 2024. The increases are due to production from the wells that were drilled and completed in the last six months of 2024 partially offset by decreased production from wells that were shut-in during the completion operations for the four Lovina wells.

Net income in the second quarter of 2025 was $2.9 million, compared to net income of $4.1 million in the same period of 2024. The decrease was primarily due to lower net revenues due to a 24% decrease in average prices. Net income in the first six months of 2025 was $8.6 million, compared to net income of $7.4 million in the same period of 2024. The increase was due to realized and unrealized gains on commodity contracts in 2025 versus losses in 2024 and a decrease in operating and interest expense partially offset by lower revenues.

Adjusted EBITDA⁽¹⁾ was $7.7 million for the second quarter of 2025 compared to $10.0 million for the same period in 2024, a decrease of 23%. The decrease was primarily due to lower revenue due to a 24% decrease in average prices. Adjusted EBITDA⁽¹⁾ was $20.5 million for the six months ended June 30, 2025 compared to $20.4 million for the prior year period, as a decrease in revenue for the six months ended June 30, 2025 was offset by lower operating expenses and a realized loss on commodity contracts in the prior year period.

Net revenues for the second quarter of 2025 decreased by 22% compared to the second quarter of 2024. Net revenues for the first six months of 2025 decreased by 3% compared to the same period of 2024. The decrease was due to decreases in average prices and an 8% decrease in oil production.

Production and operating expense per barrel averaged $7.15 per BOE in the second quarter of 2025 compared to $8.48 per BOE in the second quarter of 2024, a decrease of 16%. Production and operating expense per barrel averaged $7.11 per BOE in the first six months of 2025 compared to $8.42 per BOE for the same period of 2024, a decrease of 16%. The decreases were due to natural gas and NGL processing costs adjustments in 2024 related to prior years as the purchaser reassessed prior year gathering and processing costs, which were $0.2 million, or $0.50 per BOE in the second quarter of 2024 and $0.8 million, or $1.23 per BOE in the six months ended June 30, 2024. The decreases were also due to lower water hauling costs in 2025 compared to the prior year periods.

Netback from operations⁽²⁾ decreased to $29.66 per BOE in the second quarter of 2025 compared to $40.40 per BOE in in the same period of 2024, a decrease of 27%. Netback from operations⁽²⁾ decreased to $34.05 per BOE in the six months ending June 30, 2025 compared to $39.66 per BOE in the six months ending June 30, 2024, a decrease of 14%. These decreases were due to lower average prices partially offset by lower operating costs per BOE. Netback including commodity contracts⁽²⁾ for the second quarter of 2025 was $29.79 per BOE compared to $39.56 in 2024, a decrease of 25% from the prior year period. Netback including commodity contracts⁽²⁾ for the six months ended June 30, 2025 was $34.11 per BOE, compared to $38.67, a decrease of 11% from the prior year period.

At June 30, 2025, the Company had $34.5 million of available borrowing capacity on the credit facility and was in compliance with both of its debt covenants.

(1) Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

(2) Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

OPERATIONS UPDATE

Tishomingo Field, Ardmore Basin, Oklahoma

The average production for the second quarter of 2025 was 3,220 BOEPD, an increase of 3% compared to second quarter 2024 production of 3,128 BOEPD. The average production for the first six months of 2025 was 3,646 BOEPD, an increase of 13% compared to the same period of 2024 production of 3,216 BOEPD. The increases are due to production from the wells that were drilled and completed in the last six months of 2024 partially offset by decreased production from wells that were shut-in during the completion operations for the four Lovina wells.

During the second quarter of 2025, the Company drilled the first four wells in the 2025 drilling program, the Lovina 9-16-1H, 9-16-2H, 9-16-3H and 9-16-4H wells (100% working interest), under budget and quicker than forecasted. Completion operations on the Lovina wells were completed in July and the average 4-day production from the four wells ranged from 322 BOEPD to 643 BOEPD. while still cleaning up from the fracture stimulations. The wells are producing a higher percentage of oil than many of the Company’s previous wells and production tubing strings are currently being installed which has led to higher production based on past experience. During the second quarter, the Company shut in several existing wells during the completion operations of the Lovina wells which reduced quarterly production by approximately 540 BOEPD. All of the shut-in wells were brought back into production in July.

The Company also drilled the Forguson 17-20-3H well (46% working interest) in the second quarter of 2025 on its east side acreage with a large integrated oil company participating in the well. Completion operations have been completed on the well and it is currently starting flowback operations. The Company will also start drilling the 1.5 mile lateral Barnes 6-31-2H and Barnes 6-31-3H wells in August, which will then be completed along with the two previously drilled Velin wells.

DISCUSSION OF OPERATING RESULTS

Oil production for the second quarter of 2025 was 2,115 BOPD compared to 2,309 BOPD for the same period of 2024, a decrease of 8% due to the wells that were shut-in during the second quarter of 2025 for the completion operations of the Lovina wells. Oil production for the first six months of 2025 was 2,477 BOPD compared to 2,366 BOPD for the same period of 2024, an increase of 5%. The increase was due to production from the wells that were drilled and completed at the end of 2024 partially offset by the decrease in production from the shut-in wells. Oil revenue decreased by 28% in the second quarter of 2025 compared to the same period of 2024 due to a decrease in oil prices of 22%, and the production decrease from the shut-in wells. Oil revenue decreased by 10% in the first six months of 2025 compared to the same period of 2024 due to a decrease in oil prices of 13% partially offset by the production increase.

For the second quarter of 2025, average natural gas production was 2,880 MCFPD compared to 1,916 MCFPD for the same period of 2024, an increase of 50%. Average natural gas production for the first six months of 2025 was 3,339 MCFPD compared to 2,143 MCFPD for the first six months of 2024. The increases are due to production from the wells that were drilled and completed at the end of 2024 partially offset by the shut-in wells. Natural gas revenue increased by 450% in the second quarter of 2025 compared to the same period in 2024 due to an increase in natural gas prices of 268% and the production increase. Natural gas revenue increased by 259% in the first six months of 2025 versus the same period in 2024 due to an increase in natural gas prices of 132% and the production increase.

Natural gas liquids (NGL) production in the second quarter of 2025 increased to 625 BOEPD from 500 BOEPD in the same period of 2024, an increase of 25%. NGL production in the first six months of 2025 increased to 612 BOEPD from 493 BOEPD in the same period of 2024, an increase of 24%. The increases are due to production from the wells that were drilled and completed at the end of 2024 partially offset by the shut-in wells. NGL revenue increased by 21% in the second quarter of 2025 compared to the same period in 2024 due to the production increase partially offset by lower NGL prices. NGL revenue increased by 28% in the first six months of 2025 compared to the same period in 2024 due to an increase in NGL prices of 3% and the production increase.

Average production on a per BOE basis was 3,220 BOEPD in the second quarter of 2025 compared to 3,128 BOEPD in the same period of 2024, an increase of 3%. Average production on a per BOE basis was 3,646 BOEPD in the first six months of 2025 compared to 3,216 BOEPD in the same period of 2024, an increase of 13%. The increase is due to the factors discussed above. Gross revenue for the second quarter of 2025 decreased by 22% compared to the second quarter of 2024 due to decrease in average prices and an 8% decrease in oil production. Gross revenue for the first six months of 2025 decreased by 3% compared to the same period of 2024 due to a decrease in average prices, partially offset by an increase in production.

(1) Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

(2) Price adjustment from commodity contracts includes the positive or negative adjustment to the average price per barrel that the Company realized from its commodity contracts.  See the listing of commodity contracts below.

(3) Operating expenses includes compressor costs of $0.4 million in the second quarter of 2025 and $0.7 million in the first six months of 2025 and compressor costs of $0.4 million in the second quarter of 2024 and $0.6 million in the first six months of 2024 that are accounted for as a lease under IFRS 16.

Average prices decreased by 24% in the second quarter of 2025, compared to the same period in the prior year, due to the price decreases in oil and NGLs, partially offset by an increase in natural gas prices as discussed above. Oil made up 66% of the production mix in the second quarter of 2025 compared to 74% for the same period in 2024, partially due to the shut-in wells that produce a higher oil percentage. Average prices decreased by 14% in the first six months of 2024, compared to the same period in the prior year due to the price decrease in oil, partially offset by increases in gas and NGL prices as discussed above. Oil made up 68% of the production mix in the first six months of 2025 compared to 74% for the same period in 2024.

Royalties on Tishomingo production averaged approximately 21.8% for the second quarter of 2025 versus 21.3% in the second quarter of 2024. Royalties on Tishomingo production averaged approximately 22.0% for the first six months of 2025 versus 21.7% in the first six months of 2024. The differences in percentages in both periods are due to different royalty burdens on the various leases drilled by the Company.

Major production and operating expenses are related to the gathering and processing of natural gas and NGLs as well as periodic well repairs and maintenance. Operating expenses averaged $7.15 per BOE for the second quarter of 2025 compared to $8.48 per BOE for the same period in 2024. The decrease was partially due to natural gas and NGL processing costs of $0.2 million, or $0.50 per BOE, in 2024 related to prior years as the purchaser reassessed prior year gathering and processing costs. Operating expenses averaged $7.11 per BOE for the first six months of 2025 compared to $8.42 per BOE for the same period in 2024. The increase was due to natural gas and NGL processing costs of $0.8 million, or $1.23 per BOE in 2024, related to prior years as the purchaser reassessed prior year gathering and processing costs.

Realized and Unrealized Gains and Losses from Risk Management Contracts

As part of our normal operations, the Company is exposed to movements in commodity prices. In an effort to manage this exposure, the Company utilizes financial commodity contracts. The Company’s strategy focuses on the use of costless collars and fixed price contracts to limit exposure to fluctuations in commodity prices, while allowing for participation in spot commodity prices. Contracts settled in the period result in realized gains or losses based on the market price compared to the contract price and volume. Changes in the fair value of unsettled contracts are reported as unrealized gains or losses in the period as the forward markets fluctuate and as new contracts are executed.

At June 30, 2025 the Company had the financial commodity contracts as discussed in note 3 of the Company’s condensed consolidated interim financial statements to meet hedging requirements on its credit facility.

The estimated fair value results in a $0.7 million asset as of June 30, 2025 (December 31, 2024: $0.3 million asset) which has been determined based on the prospective amounts that the Company would receive or pay to terminate the contracts, consisting of a current asset of $0.8 million and a long-term liability if $0.1 million. (December 31, 2024: current asset of $0.2 million and a long-term asset of $0.1 million).

Production and Operating Expenses

Production and operating expenses were $1.7 million for the second quarter of 2025 versus $2.1 million for the second quarter of 2024. The second quarter of 2024 included natural gas and NGL processing costs of $0.2 million related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024. Production and operating expenses were at $4.0 million for the first six months of 2025 versus $4.4 million for the first six months of 2024. The first six months of 2024 included natural gas and NGL processing costs of $0.8 million related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024. Production and operating expenses for the first six months of 2025 increased from the prior year period due to the 13% production increase.

General and Administrative Expenses

G&A expense for the second quarter of 2025 was $1.4 million compared to $1.5 million for the same period of 2024, a decrease of 9%. G&A expense for the first six months of 2025 was $2.7 million compared to $2.8 million for the same period of 2024, a decrease of 4%. The decreases were primarily due to higher accounting fees in 2024 due to the NASDAQ listing at the end of 2023.

Depletion and Depreciation

Depletion and depreciation expense for the second quarter of 2025 was $3.5 million compared to $3.7 million in the same period of 2024. Depletion and depreciation expense on a per barrel basis was $12.00 for the second quarter of 2025 compared to $12.99 for the second quarter of 2024. Depletion and depreciation expense for the first six months of 2025 and 2024 was $7.6 million. Depletion and depreciation expense on a per barrel basis was $11.48 for the first six months of 2025 compared to $12.97 for the first six months of 2024.

Interest on loans and borrowings

Interest on loans and borrowings decreased from $0.8 million in the second quarter of 2024 to $0.6 million for the same period of 2025. Interest on loans and borrowings decreased from $1.7 million in the first six months of 2024 to $1.3 million for the same period of 2024. The decreases were due to a decrease in interest rates in 2025 and a decrease in the outstanding balance in 2025 compared to 2024.

Income tax expense

Income tax expense was $0.9 million in the second quarter of 2025 versus $1.5 million in the same period of 2024 due to lower revenues in the second quarter of 2025. Income tax expense was $2.9 million in the first six months of 2025 versus $2.6 million in the same period of 2024 due to realized and unrealized gains on commodity contracts in 2025 versus losses in 2024 and a decrease in operating and interest expense partially offset by lower revenues.

Net income for the period

The Company had net income of $2.9 million ($0.08 per basic share) in the second quarter of 2025 compared to net income of $4.1 million ($0.11 per basic share) for the same period of 2024. The change in net income in 2025 compared to the same period in 2024 is due to an decrease in revenue net of royalties of $3.1 million and a decrease in income tax expense of $0.5 million, partially offset by a net gain in realized and unrealized financial commodity contracts in the second quarter of 2025 totaling $0.5 million versus a net gain of $0.2 million in the same period of 2024, a decrease in operating expenses of $0.4 million, an increase in other income of $0.3 million, a decrease in depletion, depreciation and accretion of $0.2 million, and a decrease in interest expense on long term debt of $0.2 million.

The Company had net income of $8.6 million ($0.24 per basic share) in the first six months of 2025 compared to net income of $7.4 million ($0.21 per basic share) for the same period of 2024. The change in net income in 2025 compared to the same period in 2024 is due to a net gain in realized and unrealized financial commodity contracts in the first six month of 2025 totaling $0.5 million versus a net loss of $1.0 million in the same period of 2024, a decrease in interest expense on long term debt of $0.4 million, a decrease in operating expenses of $0.4 million, an increase in other income of $0.3 million, partially offset by a decrease in revenue net of royalties of $1.0 million, an increase in income tax expense of $0.3, and an increase in stock based compensation of $0.2 million.

Cash from operating activities

Cash flows from operating activities for the first six months of 2025 was $22.5 million compared to cash flows from continuing operating activities of $17.0 million in the same period of 2024. The increase is due to lower operating expenses and a realized gain from commodity contracts in 2025 as well as the difference in timing of working capital changes between 2025 and 2024.

Cash flows from financing activities

Cash flows used in financing activities for the first six months of 2025 was $4.9 million compared to cash flows from financing activities of $3.4 million in the same period of 2024. The decrease is due to net proceeds from loans and borrowings of $3.6 million in 2025 compared to net repayments of loans and borrowings of $4.0 million in 2024. The company also repurchased common shares in the first six months of 2025 totaling $0.7 million pursuant to the Bid (as defined below). See “Normal Course Issuer Bid”.

CAPITAL EXPENDITURES

Capital expenditures were for the wells drilled and completed in the Tishomingo field located in Oklahoma.

In June 2025, the Company’s US subsidiary amended the credit facility, which is secured by the US subsidiary’s interests in the Tishomingo Field. The credit facility, which is now held by a bank syndicate that includes both BOK Financial and Arvest Bank, expires in June 2029 and is being utilized to fund the drilling of the Caney wells in the Tishomingo Field.

The borrowing base of the credit facility was increased from $50.0 million to $65.0 million and the Company has an available borrowing capacity of $34.5 million at June 30, 2025. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The next redetermination will be in the third quarter of 2025. Future commitment amounts will be subject to new reserve evaluations and there is no guarantee that the size and terms of the credit facility will remain the same after the borrowing base redetermination. Any redetermination of the borrowing base is effective immediately and if the borrowing base is reduced, the Company has six months to repay any shortfall.

The credit facility has two primary debt covenants. One covenant requires the US subsidiary to maintain a positive working capital balance which includes any unused excess borrowing capacity and excludes the fair value of commodity contracts, the current portion of long-term debt (the “Current Ratio”). The second covenant ensures the ratio of outstanding debt and long-term liabilities to a trailing twelve month adjusted EBITDA amount (the “Maximum Leverage Ratio”) be no greater than 3 to 1 at any quarter end. Adjusted EBITDA is defined as net income excluding interest expense, depreciation, depletion and amortization expense, and other non-cash and non-recurring charges including severance, stock based compensation expense and unrealized gains or losses on commodity contracts.

The Company was in compliance with both covenants for the quarter ended June 30, 2025. At June 30, 2025, the Current Ratio of the US Subsidiary was 1.90 to 1.0 and the Maximum Leverage Ratio was 0.73 to 1.0 for the three months ended June 30, 2025.

At June 30, 2025, loans and borrowings of $30.5 million (December 31, 2024: $33.5 million) are presented net of loan acquisition costs of $0.8 million (December 31, 2024: $0.2 million).

At June 30, 2025, the Company had a working capital deficit of $12.9 million compared to a working capital deficit of $0.7 million at December 31, 2024. The Company had available borrowing capacity of $34.5 million at June 30, 2025. The Company closely monitors its working capital and borrowing capacity to ensure adequate funds are available to finance its administrative and operating requirements. Planned drilling activity can be adjusted if adequate funds are not available, and the Company has available borrowing capacity to manage its working capital requirements.

The Company has entered into financial commodity contracts as part of its risk management strategy to manage its cash flows for future activity and to offset commodity price fluctuations. Other potential sources of cash flows include proceeds from additional debt or equity offerings but there is no guarantee that additional financing will be available when needed.

The Company’s approach to managing liquidity is to ensure, as far as possible, that it will always have sufficient liquidity to meet its liabilities when due, under both normal and stressed conditions, without incurring unacceptable losses or risking damage to the Company’s reputation.

Typically, the Company ensures that it has sufficient cash on demand and cash flows from operating activities to meet expected operational expenses for a one-year period, including the servicing of financial obligations; this excludes the potential impact of extreme circumstances that cannot reasonably be predicted, such as natural disasters. To achieve this objective, the Company prepares annual capital expenditure budgets, which are regularly monitored and updated as considered necessary. Further, the Company utilizes authorizations for expenditures on both operated and non-operated projects to further manage capital expenditure. The Company also attempts to match its payment cycle with collection of oil revenue on the 20th of each month.

The Company monitors its expected cash inflows from trade and other receivables and its expected cash outflows on trade and other payables and principal debt payments. The current volatile economic climate may lead to adverse changes in cash flows and working capital levels, which may also have a direct impact on the Company’s results and financial position and which may adversely affect the Company’s liquidity.

CONTRACTUAL OBLIGATIONS

The following are the contractual maturities of financial liabilities at June 30, 2025:

*The Credit Facility provides for interest only payments until the June 2029 maturity date. The Company is required to repay amounts owing under the Credit Facility in full on the June 2029 maturity date. See “Liquidity and Capital Resources” and “Principal Business Risks” for discussion of events that would require early repayment of the Credit Facility.

QUARTERLY SUMMARY

Below is a summary of the Company’s performance over the last eight quarters:

(1) Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

(2) Net operating income is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

(3) Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

(4) Operating expenses includes compressor costs of $0.4 million in the second quarter of 2025 and $0.7 million in the first six months of 2025 and compressor costs of $0.4 million in the second quarter of 2024 and $0.6 million in the first six months of 2024 that are accounted for as a lease under IFRS 16.

Quarterly Variability

The results of the previous eight quarters reflect the Company’s development of the Tishomingo field with production increasing from 2,737 BOEPD in the third quarter of 2023 to 3,220 BOEPD in the second quarter of 2025. Changes in production have occurred between quarters due to the timing of drilling and completion operations and the temporary shut-in of wells.

Commodity prices have been relatively steady over the last 8 quarters but the price of oil did decrease to $62.25 in the second quarter of 2025 from a high of $79.70 in the third quarter of 2023. Oil prices have increased slightly subsequent to the end of the quarter through the date of this report.

Adjusted EBITDA⁽¹⁾ is impacted by the Company’s quarterly production and the changes in commodity prices. As our field development has resulted in increased production since 2023, adjusted EBITDA has reflected this increase, Adjusted EBITDA was $9.5 million in the third quarter of 2023 and has generally increased in subsequent quarters. The second quarter of 2025 adjusted EBITDA decreased to $7.6 million due to lower prices during the quarter and a temporary shut-in of wells during completion operations.

Net income, as well as basic earnings per share, is impacted by the Company’s operations and production, but it is also impacted by quarterly unrealized gains or losses on the Company’s commodity contracts, which fluctuate from quarter to quarter. Net income was $2.3 million in the third quarter of 2023 and has generally continued to grow over the last eight quarters. The lower commodity prices and temporary shut-in of wells during the second quarter of 2025 reduced net income to $2.9 million.

Total assets have increased over this period as the Company has continued to incur capital expenditures to develop the field and increase production since 2023.

The Company’s net bank debt has increased from $23.8 million to $29.7 million to fund capital expenditures and has fluctuated depending on the timing of field development activities between quarters. Although debt has increased over the last eight quarters, the Company has consistently maintained a leverage ratio below 1.0.

(1) Adjusted EBITDA is considered a Non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” at the end of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the condensed consolidated interim financial statements requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities, the disclosures of contingencies at the date of the condensed consolidated interim financial statements and the reported amounts of revenues and expenses during the period. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future years could require a material change in the financial statements. Accordingly, actual results may differ from the estimated amounts. Significant estimates and judgments made by management in the preparation of the condensed consolidated interim financial statements are as follows:

Oil and gas assets

Development and production assets are assessed for recoverability at cash generating unit (“CGU”) level. The determination of CGUs is subject to management judgments. Recoverability is assessed by comparing the carrying value of the asset to its estimated recoverable amount, which is based on the higher of fair value of the assets less the cost to sell (“FVLCS”) or value in use (“VIU”). The significant estimates used in the determination of the estimated recoverable amount include the following:

Depletion of oil and gas assets

Depletion of development and production assets is determined based on proved and probable oil and gas reserves and includes forecasted future development costs as estimated by the Company’s independent third-party reserve evaluators. By their nature, the estimates of proved and probable oil and gas reserves are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.

Asset retirement obligations

The provision for site restoration and abandonment is based on current legal requirements, technology, price levels and expected plans and are based on significant assumptions such as inflation rate and discount rate. Actual costs and cash outflows can differ from estimates because of changes in laws or regulations, market conditions and changes in technology.

Income taxes

Tax interpretations, regulations and legislation in the various jurisdictions in which the Company operates are subject to change. As such income taxes are subject to measurement uncertainty. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

OUTSTANDING SHARE DATA

There were 35,420,833, 35,555,133 and 35,460,309 common shares outstanding as of August 8, 2025, June 30, 2025 and December 31, 2024, respectively. The Company had 977,621, 977,621, and 1,073,924 stock options outstanding as of August 8, 2025, June 30, 2025 and December 31, 2024, respectively. The Company had 509,959, 509,959, and 232,125 restricted share units (RSUs) outstanding as of August 8, 2025, June 30, 2025 and December 31, 2024, respectively.

NORMAL COURSE ISSUER BID

On September 16, 2024, the Company announced that the Toronto Stock Exchange (TSX) accepted a notice filed by the Company of its intention to make a normal course issuer bid (the “Bid”) to purchase up to an aggregate of 1,786,798 common shares, being approximately 5% of the total number of 35,735,965 common shares issued and outstanding as at September 10, 2024, through the facilities of the TSX and the Nasdaq Capital Market or through alternative Canadian trading platforms. The actual number of shares which may be purchased pursuant to the Bid will be determined by management of the Company. The price the Company will pay for any such common shares will be the prevailing market price at the time of purchase, and any such repurchased shares will be cancelled.

During the first six months of 2025, the Company repurchased 89,337 common shares at an average price of US$7.31 per share.

PRINCIPAL BUSINESS RISKS

KEI’s business and results of operations are subject to a number of risks and uncertainties, including but not limited to the following:

The Company seeks to mitigate these risks by:

DISCLOSURE CONTROLS AND PROCEDURES

The Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision, disclosure controls and procedures (“DC&P”) and internal controls over financial reporting (“ICOFR”) as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements in accordance with IFRS Accounting Standards.

The DC&P have been designed to provide reasonable assurance that material information relating to KEI is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by KEI under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company’s CEO and CFO have concluded, based on their evaluation that the Company’s DC&P and ICOFR are effective at June 30, 2025 to provide reasonable assurance that material information related to the Company is made known to them by others within the Company.

The CEO and CFO are required to cause the Company to disclose any change in the Company’s ICOFR and DC&P that occurred during the most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company’s ICOFR. No changes in ICOFR and DC&P were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company’s ICOFR during the quarter ended June 30, 2025.

It should be noted that a control system, including the Company’s DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.

OUTLOOK

In the United States, the Company intends to drill and complete additional wells in the Caney/Sycamore formations on its Oklahoma lands as financing becomes available and the economic environment changes. In addition, the Company continues to utilize its technical and operational expertise to identify and acquire additional oil, gas and clean energy projects. The Company expects to continue drilling additional wells utilizing cash flows from operating activities and potentially its available borrowing capacity under its credit facility.

NON-GAAP MEASURES

The Company’s Non-GAAP Measures are not measures or ratios recognized under IFRS Accounting Standards and do not have any standardized meanings prescribed by IFRS Accounting Standards. 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 from operating activities, working capital or other financial measures and ratios determined in accordance with IFRS Accounting Standards, as an indicator of the Company’s performance.

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 flows 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 Accounting Standards 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 from continuing operations:

Net operating income is similarly a non-GAAP measure that represents revenue net of royalties and operating expenses. The Company believes that net operating income is a useful supplemental measure to analyze operating performance and provides an indication of the results generated by the Company’s principal business activities prior to the consideration of other income and expenses.

The following is the reconciliation of the non-GAAP measure net operating income:

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 MD&A 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 MD&A 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

CAUTION REGARDING FORWARD-LOOKING INFORMATION

This MD&A contains forward-looking information including expectations regarding proposed timing and expected results of development work in the Company’s Tishomingo Field, expected productivity from current and future wells, planned capital expenditure programs and cost estimates, the effect of design and performance improvements on future productivity, planned use and sufficiency of proceeds from the Company’s debt and equity financings, compliance with debt covenants under the Company’s credit facility, cash on hand and cash flows from operating activities 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”, “intend” 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, declines will match the modeling, 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 well shut-ins will not materially reduce production or adversely affect future productivity, that anticipated results and estimated costs will be consistent with managements’ 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 combination of cash on hand and cash flows from operating activities will be sufficient to finance the Company’s cash requirements through 2025, 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 reserve-based loan facility and that the borrowing base will not be reduced, 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 managements’ expectations, that the Company will not achieve a comparable level of hedging going forward in respect of its existing production, that the Company will not achieve the results anticipated by management from the Company’s cost reduction measures, 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 conditions), well shut-ins and the potential for damage to the affected wells, 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 reserve-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base redetermination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, 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 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 MD&A 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.

CORPORATE INFORMATION