Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

SEPTEMBER 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 nine months ended September 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 nine months ended September 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 November 11, 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.

OVERVIEW

Results at a Glance

(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 third quarter of 2025 was 4,254 BOEPD, an increase of 40% compared to third quarter 2024 production of 3,032 BOEPD. 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 increases are due to production from the wells that were drilled and completed in the first nine months of 2025.

Net revenues for the third quarter of 2025 increased by 15% compared to the third quarter of 2024. The increase was due to a 40% increase in production, partially offset by an 18% decrease in average prices. Net revenues for the first nine months of 2025 increased by 2% compared to the same period of 2024. The increase was due to a 22% increase in production, partially offset by a 16% decrease in average prices.

Net income in the third quarter of 2025 was $3.6 million, compared to net income of $5.1 million 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. Net income in the first nine months of 2025 was $12.2 million, compared to net income of $12.5 million in the same period of 2024. The decrease was due to higher depreciation expense and operating expenses from the increase in production in 2025, partially offset by higher revenues.

Adjusted EBITDA⁽¹⁾ was $11.1 million for the third quarter of 2025 compared to $10.1 million for the same period in 2024, an increase of 9%. Adjusted EBITDA⁽¹⁾ was $31.6 million for the nine months ended September 30, 2025 compared to $30.5 million for the prior year period, an increase of 3%. The increases were primarily due to higher revenues partially offset by higher 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. 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.

Netback from operations⁽²⁾ decreased to $30.84 per BOE in the third quarter of 2025 compared to $40.01 per BOE in the same period of 2024, a decrease of 23%. Netback from operations⁽²⁾ decreased to $32.86 per BOE in the nine months ending September 30, 2025 compared to $39.78 per BOE in the nine months ending September 30, 2024, a decrease of 17%. Netback including commodity contracts⁽²⁾ for the third quarter of 2025 was $30.89 per BOE compared to $39.95 in the third quarter of 2024, a decrease of 23%. Netback including commodity contracts⁽²⁾ for the nine months ended September 30, 2025 was $32.91 per BOE, compared to $39.09 for the nine months ended September 30, 2024, a decrease of 16%. These decreases were due to lower average prices.

At September 30, 2025, the Company had $18.5 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 third quarter of 2025 was 4,254 BOEPD, an increase of 40% compared to third quarter 2024 production of 3,032 BOEPD. 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 increases are due to production from the wells that were drilled and completed in the first nine months of 2025.

During the third quarter of 2025, the Company finished completion operations on the Lovina 9-16-1H, 9-16-2H, 9-16-3H and 9-16-4H wells (100% working interest). The four Lovina wells are still producing at a higher oil rate and declining at lower rates than our other wells. The Company also completed the Forguson 17-20-3H well (46% working interest) in the third quarter of 2025 on its east side acreage with a large integrated oil company participating in the well. The well 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.

The Company also finished drilling the 1.5 mile lateral Barnes 6-31-2H well during the third quarter. As previously disclosed, the Barnes 6-31-3H well had to be redrilled due to the failure of the drill pipe in the original wellbore. The Company decided to redrill the well to a 1-mile lateral to ensure it was successfully drilled due to stability issues caused by the original wellbore. Completion operations for the two Barnes wells, along with the two previously drilled Velin wells, are underway with production expected to begin in December.

DISCUSSION OF OPERATING RESULTS

Oil production for the third quarter of 2025 was 2,809 BOPD compared to 2,247 BOPD for the same period of 2024, an increase of 25% due to production from the new wells in 2025. Oil production for the first nine months of 2025 was 2,589 BOPD compared to 2,326 BOPD for the same period of 2024, an increase of 11%. The increase was due to production from the 2025 wells. Oil revenue increased by 7% in the third quarter of 2025 compared to the same period of 2024 due to an increase in oil production of 25%, partially offset by lower oil prices which decreased by 14%. Oil revenue decreased by 4% in the first nine months of 2025 compared to the same period of 2024 due to a decrease in oil prices of 14%, partially offset by the 11% production increase.

For the third quarter of 2025, average natural gas production was 3,861 MCFPD compared to 1,948 MCFPD for the same period of 2024, an increase of 98%. Average natural gas production for the first nine months of 2025 was 3,515 MCFPD compared to 2,078 MCFPD for the first nine months of 2024, an increase of 69%. The increases are due to production from the wells that were drilled and completed in 2025. Natural gas revenue increased by 345% in the third quarter of 2025 compared to the same period in 2024 due to an increase in natural gas prices of 124% and the production increase. Natural gas revenue increased by 282% in the first nine months of 2025 versus the same period in 2024 due to an increase in natural gas prices of 127% and the production increase.

Natural gas liquids (NGL) production in the third quarter of 2025 increased to 801 BOEPD from 460 BOEPD in the same period of 2024, an increase of 74%. NGL production in the first nine months of 2025 increased to 676 BOEPD from 482 BOEPD in the same period of 2024, an increase of 40%. The increases are due to production from the wells that were drilled and completed in 2025. NGL revenue increased by 67% in the third 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 39% in the first nine months of 2025 compared to the same period in 2024 due to the 40% production increase.

Average production on a per BOE basis was 4,254 BOEPD in the third quarter of 2025 compared to 3,032 BOEPD in the same period of 2024, an increase of 40%. Average production on a per BOE basis was 3,851 BOEPD in the first nine months of 2025 compared to 3,154 BOEPD in the same period of 2024, an increase of 22%. The increase is due to the factors discussed above. Gross revenue for the third quarter of 2025 increased by 15% compared to the third quarter of 2024 due to the production increase, partially offset by lower average prices. Gross revenue for the first nine months of 2025 increased by 3% compared to the same period of 2024 due to the increase in production, partially offset by lower average prices.

Royalties, Operating Expenses and Netback

(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 third quarter of 2025 and $1.1 million in the first nine months of 2025 and compressor costs of $0.3 million in the third quarter of 2024 and $0.9 million in the first nine months of 2024 that are accounted for as a lease under IFRS Accounting Standards 16.

Average prices decreased by 18% in the third 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 third quarter of 2025 compared to 74% for the same period in 2024. In September 2025 the oil production mix increased to 71% after the four Lovina wells started producing. Average prices decreased by 16% in the first nine months of 2025, compared to the same period in the prior year due to the price decrease in oil, partially offset by an increase in natural gas prices as discussed above. Oil made up 67% of the production mix in the first nine months of 2025 compared to 74% for the same period in 2024.

Royalties on Tishomingo production averaged approximately 21.0% for the third quarter of 2025 versus 21.1% in the third quarter of 2024. Royalties on Tishomingo production averaged approximately 21.6% for the first nine months of 2025 versus 21.5% in the first nine 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. 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. 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.

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, deferred put 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 September 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 $0.3 million asset as of September 30, 2025 (December 31, 2024: $0.3 million asset) for the financial oil and gas contracts 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 $0.3 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 $2.5 million for the third quarter of 2025 versus $1.5 million for the third quarter of 2024. The increase was primarily due to the increase in production in the third quarter of 2025 and reassessed production tax adjustments related to prior periods that were recorded in September 2025. Production and operating expenses were at $6.5 million for the first nine months of 2025 versus $5.8 million for the first nine months of 2024. The increase was due to the increase in production during the first nine months of 2025.

General and Administrative Expenses

G&A expense for the third quarter of 2025 was $1.4 million compared to $1.3 million for the same period of 2024, an increase of 6%. The increase was due to costs related to a special shareholder meeting. G&A expense for the first nine months of 2025 was $4.1 million compared to $4.1 million for the same period of 2024.

Depletion and Depreciation

Depletion and depreciation expense for the third quarter of 2025 was $4.6 million compared to $3.6 million in the same period of 2024. Depletion and depreciation expense on a per barrel basis was $11.64 for the third quarter of 2025 compared to $12.94 for the third quarter of 2024. Depletion and depreciation expense for the first nine months of 2025 was $12.1 million compared to $11.2 million in the same period of 2024. Depletion and depreciation expense on a per barrel basis was $11.54 for the first nine months of 2025 compared to $12.96 for the first nine months of 2024.

Interest on loans and borrowings

Interest on loans and borrowings increased from $0.8 million in the third quarter of 2024 to $0.9 million for the same period of 2025. The increase was due to a higher loan balance, partially offset by a decrease in interest rates in 2025. Interest on loans and borrowings decreased from $2.6 million in the first nine months of 2024 to $2.2 million for the same period of 2025. The decrease was due to lower interest rates in 2025.

Income tax expense

Income tax expense was $1.2 million in the third quarter of 2025 versus $1.6 million in the same period of 2024 due to lower income before taxes in the third quarter of 2025. Income tax expense was $4.1 million in the first nine months of 2025 versus $4.3 million in the same period of 2024.

Net income for the period

The Company had net income of $3.6 million ($0.10 per basic share) in the third quarter of 2025 compared to net income of $5.1 million ($0.14 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 loss in realized and unrealized financial commodity contracts in the third quarter of 2025 totaling $0.4 million versus a net gain of $1.3 million in the same period of 2024, an increase in operating expenses of $1.0 million, an increase in depletion, depreciation and accretion of $0.9 million, partially offset by an increase in revenue net of royalties of $1.9 million and a decrease in income tax expense of $0.4 million.

The Company had net income of $12.2 million ($0.34 per basic share) in the first nine months of 2025 compared to net income of $12.5 million ($0.35 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 increase in depletion, depreciation and accretion of $0.9 million, an increase in operating expenses of $0.6 million, an increase in stock based compensation of $0.4 million, and a net gain in realized and unrealized financial commodity contracts in the third quarter of 2025 totaling $0.1 million, partially offset by an increase in revenue net of royalties of $1.0 million, an increase in other income of $0.5 million, and a decrease in interest expense on long term debt of $0.3 million.

Cash from operating activities

Cash flows from operating activities for the first nine months of 2025 were $29.2 million compared to cash flows from continuing operating activities of $28.8 million in the same period of 2024. The increase is due to higher revenue, partially offset by higher operating expenses as well as the difference in timing of working capital changes between 2025 and 2024.

Cash flows from financing activities

Cash flows provided by financing activities for the first nine months of 2025 were $9.7 million compared to $0.1 million in the same period of 2024. The increase is due to an increase in net proceeds from loans and borrowings of $13.0 million in 2025 compared to net proceeds of loans and borrowings of $1.0 million in 2024. The Company also repurchased common shares in the first nine months of 2025 totaling $1.8 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.

LIQUIDITY AND CAPITAL RESOURCES

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 used 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 $18.5 million at September 30, 2025. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The credit facility was redetermined in October 2025 at the same $65 million borrowing capacity and the next redetermination will be in the second quarter of 2026. 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 and 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 September 30, 2025. At September 30, 2025, the Current Ratio of the US Subsidiary was 1.57 to 1.0 and the Maximum Leverage Ratio was 1.06 to 1.0 for the three months ended September 30, 2025.

At September 30, 2025, loans and borrowings of $46.5 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 September 30, 2025, the Company had a working capital deficit of $6.1 million compared to a working capital deficit of $0.7 million at December 31, 2024. The Company had available borrowing capacity of $18.5 million at September 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 undiscounted contractual maturities of financial liabilities at September 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 third quarter of 2025 and $1.1 million in the first nine months of 2025 and compressor costs of $0.4 million in the third quarter of 2024 and $0.6 million in the first nine 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 2,842 BOEPD in the fourth quarter of 2023 to 4,254 BOEPD in the third 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 $63.93 in the third quarter of 2025 from a high of $79.48 in the second quarter of 2024. Oil prices have decreased 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 although lower oil prices have impacted some quarters more than the production increase. Adjusted EBITDA was $10.5 million in the fourth quarter of 2023 and has generally increased or remained constant in subsequent quarters. The third quarter of 2025 adjusted EBITDA was $10.1 million as lower prices during the quarter offset the increase in production.

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 $4.8 million in the fourth quarter of 2023 and has generally either continued to grow or remain constant over the last eight quarters. Lower commodity prices during the third quarter of 2025 reduced net income to $3.6 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 $29.6 million to $45.7 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 around 1.0 or below.

(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 35,357,258, 35,369,693 and 35,460,309 common shares outstanding as of November 11, 2025, September 30, 2025 and December 31, 2024, respectively. The Company had 977,621, 977,621, and 1,073,924 stock options outstanding as of November 11, 2025, September 30, 2025 and December 31, 2024, respectively. The Company had 509,959, 509,959, and 232,125 restricted share units (RSUs) outstanding as of November 11, 2025, September 30, 2025 and December 31, 2024, respectively.

NORMAL COURSE ISSUER BID

On September 19, 2025, 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 1,768,841 common shares, being approximately 5% of the total number of 35,376,833 common shares issued and outstanding as at September 10, 2025, 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. The Company has purchased 19,575 common shares at an average price of US5.28 per share under the Bid.

During its previous normal course issuer bid which began in September 2024 and ended in September 2025, the Company repurchased 548,293 common shares at an average price of US$5.27 per share, which included 274,777 common shares purchased in 2025.

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 September 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 September 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 within a favorable economic environment. 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: