Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

JUNE 30, 2026

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, 2026, 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, 2026 and the audited consolidated financial statements and MD&A for the year ended December 31, 2025. The condensed consolidated interim financial statements have been prepared in accordance with International Financial Reporting Standards and International Accounting Standards as issued by the International Accounting Standards Board (IASB) and Interpretations (collectively “IFRS Accounting Standards”). 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, as an indicator of the Company’s performance.

This report is prepared as of August 12, 2026. 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 second quarter of 2026 was 4,690 BOEPD, an increase of 46% compared to second quarter 2025 production of 3,220 BOEPD. Average production for the six months ended June 30, 2026 was 4,688 BOEPD, an increase of 29% from the average production of 3,646 BOEPD in the same period of 2025. The increases were primarily due to production from the wells that were drilled and completed during 2025.

Net revenues for the second quarter of 2026 increased by 109% compared to the second quarter of 2025. The increase was due to a 46% increase in production and a 41% increase in average prices. Net revenues for the first six months of 2026 increased by 55% compared to the same period of 2025. The increase was due to a 29% increase in production and a 19% increase in average prices.

Net income in the second quarter of 2026 was $8.5 million, compared to net income of $2.9 million in the same period of 2025. Net income in the first six months of 2026 was $12.5 million, compared to net income of $8.6 million in the same period of 2025. The increases were due primarily to higher revenue partially offset by higher operating expense, depletion expense and interest expense and realized losses on commodity contracts in 2026.

Adjusted EBITDA⁽¹⁾ was $16.4 million for the second quarter of 2026 compared to $7.7 million for the second quarter of 2025, an increase of 114%. Adjusted EBITDA⁽¹⁾ was $31.3 million for the six months ended June 30, 2026 compared to $20.5 million for the comparable prior year period. The increases were primarily due to the increase in revenue partially offset by higher operating expenses and realized losses on commodity contracts in 2026.

Production and operating expense per barrel averaged $8.90 per BOE in the second quarter of 2026 compared to $7.15 per BOE in the second quarter of 2025. Production and operating expense per barrel averaged $8.45 per BOE in the first six months of 2026 compared to $7.11 per BOE for the same period of 2025, an increase of 19%. The increase was primarily due to workover costs on a non-operated well, as well as a smaller amount due to the Company’s gas purchaser reassessing prior year gathering and processing fees, which together totaled $0.2 million in the second quarter of 2026 and $0.5 million in the first six months of 2026. The increases were also due to temporary higher water hauling volumes from wells offsetting the wells that were fracked at the end of 2025 and thus resulted in higher water hauling costs compared to the prior year.

Netback from operations⁽²⁾ increased to $43.92 per BOE in the second quarter of 2026 compared to $29.66 per BOE in the same period of 2025, an increase of 48%. Netback including commodity contracts⁽²⁾ for the second quarter of 2026 was $41.21 per BOE compared to $29.79 per BOE in 2025, an increase of 38%. Netback from operations⁽²⁾ increased to $41.18 per BOE in the six months ended June 30, 2026 compared to $34.05 per BOE in the six months ended June 30, 2025, an increase of 21%. Netback including commodity contracts⁽²⁾ for the six months ended June 30, 2026 was $39.48 per BOE, compared to $34.11, an increase of 16% from the prior year period. The increases were due to higher prices in 2026 compared to the prior year partially offset by higher operating expense.

At June 30, 2026, the Company had $30.5 million of available borrowing capacity on the credit facility and was in compliance with both of its debt covenants. In May 2026, the credit facility was redetermined and the borrowing capacity was increased from $65 million to $75 million.

(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 2026 was 4,690 BOEPD, an increase of 46% compared to second quarter 2025 production of 3,220 BOEPD. The average production for the six months ended June 30, 2026 was 4,688 BOEPD, an increase of 29% from the average production of 3,646 BOEPD in the same period of 2025. The increases were due to production from the wells that were drilled and completed in late 2025. Second quarter production also increased by 294 BOEPD from reassessed prior period volume adjustments made by the Company’s gas purchaser which increased NGL production by 355 BOEPD and decreased natural gas production by 61 BOEPD for the second quarter of 2026. Second quarter production was reduced due to the temporary shut-in of the three Alicia Renee wells for approximately 30 days during the quarter. The shut-ins were implemented as a precautionary measure due to the close proximity of the Clifton Mack drilling. Prior to being shut in, the three wells were producing at a combined average rate of approximately 860 BOEPD. The Alicia Renee wells are currently expected to resume production once completion operations on the Clifton Mack wells are complete.

The Company has completed drilling the three 1.5 mile lateral wells, the Clifton Mack 11-14-1H, 11-14-2H and the 11-14-3H wells (96.5% working interest). The Company expects to begin fracture stimulation operations on the wells this month with production currently expected by the end of the third quarter of 2026. The drilling rig will now be moving to the Lovina 5-8-1H well (98.5% working interest) where the Company will be testing the False Caney formation with its first 2-mile lateral well.

DISCUSSION OF OPERATING RESULTS

Oil production for the second quarter of 2026 was 3,002 BOPD compared to 2,115 BOPD for the same period of 2025, an increase of 42%. Oil production for the first six months of 2026 was 3,226 BOPD compared to 2,477 BOPD for the same period of 2025, an increase of 30%. The increases were due to production from the wells that were drilled and completed at the end of 2025. Oil revenue increased by 117% in the second quarter of 2026 compared to the same period of 2025 due to an increase in oil prices of 53%, and the production increase of 42%. Oil revenue increased by 59% in the first six months of 2026 compared to the same period of 2025 due to an increase in oil prices of 22%, and the production increase of 30%.

For the second quarter of 2026, average natural gas production was 2,764 MCFPD compared to 2,880 MCFPD for the same period of 2025, a decrease of 4%. Average natural gas production for the first six months of 2026 was 3,192 MCFPD compared to 3,339 MCFPD for the first six months of 2025. Natural gas revenue decreased by 99% in the second quarter of 2026 compared to the prior year period. Natural gas revenue decreased by 26% in the first six months of 2026 versus the same period in 2025. In the second quarter of 2026, the Company’s gas purchaser reassessed prior period production quantities from natural gas to NGL production which reduced natural gas production by 368 MCFPD and reduced natural gas gross revenue by $0.3 million, which was partially offset by production from the new wells drilled in 2025.

Natural gas liquids (NGL) production in the second quarter of 2026 increased to 1,227 BOEPD from 625 BOEPD in the same period of 2025, an increase of 96%. NGL production in the first six months of 2026 increased to 930 BOEPD from 612 BOEPD in the same period of 2025, an increase of 52%. NGL revenue increased by 139% in the second quarter of 2026 compared to the same period in 2025. NGL revenue increased by 38% in the first six months of 2026 compared to the same period in 2025. In the second quarter of 2026, the Company’s gas purchaser reassessed prior period production quantities from natural gas to NGL production which increased NGL production by 355 BOEPD and increased NGL gross revenue by $0.7 million. The increase was also due to production from the new wells drilled in 2025.

Average production on a per BOE basis was 4,690 BOEPD in the second quarter of 2026 compared to 3,220 BOEPD in the same period of 2025, an increase of 46%. Average production on a per BOE basis was 4,688 BOEPD in the first six months of 2026 compared to 3,646 BOEPD in the same period of 2025, an increase of 29%. The increase is due to the factors discussed above. Gross revenue for the second quarter of 2026 increased by 106% compared to the second quarter of 2025 due to increase in revenue for oil and NGLs partially offset by lower gas revenue. Gross revenue for the first six months of 2026 increased by 52% compared to the same period of 2025 due to increase in revenue for oil and NGLs partially offset by lower gas revenue.

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.  

(3) Operating expenses includes compressor costs of $0.4 million in the second quarter of 2026 and $0.8 million in the first six months of 2026 and compressor costs of $0.4 million in the second quarter of 2025 and $0.7 million in the first six months of 2025 that are accounted for as a lease under IFRS 16.  

Average prices increased by 41% in the second quarter of 2026, compared to the same period in the prior year, due to the price increase in oil and NGLs, partially offset by the decrease in natural gas prices as discussed above. Oil made up 64% of the production mix in the second quarter of 2026 compared to 66% for the same period in 2025. The 64% oil mix in the second quarter was due to the reassessed prior period production quantities, which increased NGL production and reduced natural gas production, that was recorded in April 2026. In May and June 2026, the oil mix was 70%. Average prices increased by 19% in the first six months of 2026, compared to the same period in the prior year due to the price increase in oil and NGLs, partially offset by a decrease in gas prices as discussed above. Oil made up 69% of the production mix in the first six months of 2026 compared to 68% for the same period in 2025.

Royalties on Tishomingo production averaged approximately 20.6% for the second quarter of 2026 versus 21.8% in the second quarter of 2025. Royalties on Tishomingo production averaged approximately 20.6% for the first six months of 2026 versus 22.0% in the first six months of 2025. The percentage differences are due to different royalty burdens on the wells produced 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 expense averaged $8.90 per BOE in the second quarter of 2026 compared to $7.15 per BOE in the second quarter of 2025, an increase of 24%. Production and operating expense per barrel averaged $8.45 per BOE in the first six months of 2026 compared to $7.11 per BOE for the same period of 2025, an increase of 19%. The increase was due to workover costs on a non-operated well, as well as a smaller amount due to the Company’s gas purchaser reassessing prior year gathering and processing fees, which together totaled $0.2 million in the second quarter of 2026 and $0.5 million in the first six months of 2026. The increases were also due to higher water hauling costs compared to the prior year period.

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, fixed price contracts and deferred put 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, 2026 the Company had the financial commodity contracts as discussed in note 3 of the Company’s unaudited condensed consolidated financial statements to meet hedging requirements on its credit facility.

The estimated fair value results in a $0.1 million net liability as of June 30, 2026 (December 31, 2025: $0.4 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 liability of $0.1 million (December 31, 2025: current asset of $0.4 million).

The realized and unrealized gains/losses from the financial commodity contracts are as follows:

Production and Operating Expenses

Production and operating expenses were $3.4 million for the second quarter of 2026 versus $1.7 million for the second quarter of 2025. Production and operating expenses were $6.3 million for the first six months of 2026 versus $4.0 million for the first six months of 2025. Production and operating expenses increased from the prior year period due to the production increases in 2026.

General and Administrative Expenses

General & Administrative (“G&A”) expense for the second quarter of 2026 was $1.6 million compared to $1.4 million for the same period of 2025, an increase of 12%. G&A expense for the first six months of 2026 was $3.1 million compared to $2.7 million for the same period of 2025, an increase of 13%. The increases were primarily due to an increase in consulting and legal costs in 2026 compared to the same periods in 2025.

Depletion and Depreciation

Depletion and depreciation expense for the second quarter of 2026 was $5.1 million compared to $3.5 million in the same period of 2025. Depletion and depreciation expense on a per barrel basis was $11.94 for the second quarter of 2026 compared to $12.00 for the second quarter of 2025. Depletion and depreciation expense for the first six months of 2026 and 2025 was $10.1 million and $7.6 million respectively. Depletion and depreciation expense on a per barrel basis was $11.95 for the first six months of 2026 compared to $11.48 for the first six months of 2025. The increases were primarily due to the increase in production in 2026 compared to the same periods in 2025.

Interest on loans and borrowings

Interest on loans and borrowings increased from $0.6 million in the second quarter of 2025 to $1.2 million for the same period of 2026. Interest on loans and borrowings increased from $1.3 million in the first six months of 2025 to $2.3 million for the same period of 2026. The increases were due to an increase in the outstanding debt balance in 2026 compared to 2025, partially offset by a decrease in interest rates.

Income tax expense

Income tax expense was $2.8 million in the second quarter of 2026 versus $0.9 million in the same period of 2025. Income tax expense was $4.2 million in the first six months of 2026 versus $2.9 million in the same period of 2025. The increases were due to higher income before income taxes for 2026.

Net income for the period

The Company had net income of $8.5 million ($0.24 per basic share) in the second quarter of 2026 compared to net income of $2.9 million ($0.08 per basic share) for the same period of 2025. The change in net income in the second quarter of 2026 compared to the same period in 2025 is due to an increase in revenue net of royalties of $11.8 million and a net gain in realized and unrealized financial commodity contracts in the second quarter of 2026 totaling $1.0 million versus a net gain of $0.5 million in the same period of 2025, partially offset by an increase in income tax expense of $1.9 million, an increase in operating expenses of $1.6 million, an increase in depletion, depreciation and accretion of $1.6 million, and an increase in interest expense on long term debt of $0.6 million.

The Company had net income of $12.5 million ($0.35 per basic share) in the first six months of 2026 compared to net income of $8.6 million ($0.24 per basic share) for the same period of 2025. The change in net income in 2026 compared to the same period in 2025 is due to an increase in revenue net of royalties of $15.0 million partially offset by an increase in operating expenses of $2.3 million, an increase in depletion, depreciation and accretion of $2.6 million, an increase in income tax expense of $1.3 million, an increase in interest expense on long term debt of $0.6 million and a net loss on realized and unrealized financial commodity contracts in the first six months of 2026 totaling $2.2 million versus a net gain of $0.5 million in the same period of 2025.

Cash from operating activities

Cash flows from operating activities for the first six months of 2026 was $28.0 million compared to cash flows from operating activities of $22.5 million in the same period of 2025. The increase in 2026 is due to higher net income from higher production and higher average prices compared to the same period in 2025.

Cash used in investing activities

Cash flows used in investing activities for the first six months of 2026 was $23.0 million compared to cash flows used in investing activities of $18.8 million in the same period of 2025. The increase was due to the difference in timing of working capital changes between 2026 and 2025 partially offset by lower capital expenditures in the first six months of 2026 compared to 2025.

Cash flows from financing activities

Cash flows used in financing activities for the first six months of 2026 was $6.1 million compared to cash flows used in financing activities of $4.9 million in the first six months of 2025. The increase is due to a net repayment of $5.0 million on loans and borrowings in 2026 compared to net repayments on loans and borrowings of $3.6 million in 2025.

CAPITAL EXPENDITURES

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

LIQUIDITY AND CAPITAL RESOURCES

The borrowing base of the credit facility is $75.0 million and the Company has an available borrowing capacity of $30.5 million at June 30, 2026. The credit facility is subject to a semi-annual review and redetermination of the borrowing base.

In May 2026, the credit facility was redetermined with an increase in borrowing capacity to $75 million. 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 EBITDAX amount (the “Maximum Leverage Ratio”) be no greater than 3 to 1 at any quarter end. Adjusted EBITDAX 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, 2026. At June 30, 2026, the Current Ratio of the US Subsidiary was 1.65 to 1.0 and the Maximum Leverage Ratio was 0.88 to 1.0 for the three months ended June 30, 2026.

At June 30, 2026, loans and borrowings of $44.5 million (December 31, 2025: $49.5 million) are presented net of loan acquisition costs of $0.8 million (December 31, 2025: $0.7 million).

At June 30, 2026, the Company had a working capital deficit of $14.1 million compared to a working capital deficit of $12.6 million at December 31, 2025. The Company had available borrowing capacity of $30.5 million at June 30, 2026. 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 June 30, 2026:

*The Credit Facility provides for interest only payments until the June 2029 maturity date which are included in the table. The average interest rate at June 30, 2026 was 7.6%. 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 $0.8 million in 2026, $1.5 million in 2025 and $0.8 million in 2024 that are accounted for as a lease under IFRS Accounting Standards 16.  

Quarterly Variability

The results of the previous eight quarters reflect the Company’s development of the Tishomingo field with production increasing from 3,032 BOEPD in the third quarter of 2024 to 4,690 BOEPD in the second quarter of 2026. 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 decreased throughout 2025 but increased significantly during the first and second quarter of 2026. Oil prices decreased from $74.48 in the third quarter of 2024 down to $57.11 in the fourth quarter of 2025 before recovering to $95.08 in the second quarter of 2026.

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 2024, adjusted EBITDA has reflected this increase, although lower oil prices have impacted some quarters more than the production increase. Adjusted EBITDA was $10.1 million in the third quarter of 2024 and has generally increased or remained constant in subsequent quarters. The second quarter of 2026 adjusted EBITDA increased to $16.4 million due to higher production as well as higher prices during the quarter.

Net income, as well as basic earnings per share, is impacted by the Company’s production and average prices, but it is also impacted by quarterly unrealized gains or losses on the Company’s commodity contracts, which fluctuate from quarter to quarter, as well as increases in depletion expense. Net income was generally higher in 2024 due to higher oil prices. In 2025, net income fluctuated as the increase in production was offset by the decrease in average prices throughout the year. In the first quarter of 2026, net income was $4.0 million primarily due to an unrealized loss on commodity contracts of $2.9 million. In the second quarter of 2026, net income increased to $8.5 million due to higher average prices and production and an unrealized gain on commodity contracts of $2.2 million which were partially offset by realized losses on commodity contracts and higher operating and depletion expense.

Total assets have increased over this period as the Company has continued to incur capital expenditures to develop the field and increase production since 2024. Total assets increased from $237.4 million in the third quarter of 2024 to $308.1 million in the second quarter of 2026.

The Company’s net bank debt has increased from $30.7 million to $43.7 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 low leverage ratio. The second quarter 2026 leverage ratio was 0.88 to 1.

(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 consolidated 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 unaudited 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 the 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 35,869,698, 35,774,198 and 35,471,833 common shares outstanding as of August 13, 2026, June 30, 2026 and December 31, 2025, respectively. The Company had 914,454, 1,009,954 and 882,621 stock options outstanding as of August 13, 2026, June 30, 2026 and December 31, 2025, respectively. The Company had 671,848, 671,848, and 509,959 restricted share units (RSUs) outstanding as of August 13, 2026, June 30, 2026 and December 31, 2025, 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. Since September 19, 2025, the Company has purchased 112,759 common shares at an average price of US$4.21 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.

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 (“ICFR”) 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 ICFR are effective at June 30, 2026 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 ICFR 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 ICFR. No changes in ICFR and DC&P were identified during such period that have materially affected, or are reasonably likely to materially affect, the Company’s ICFR during the quarter ended June 30, 2026.

It should be noted that a control system, including the Company’s DC&P and ICFR, 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 ICFR 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 field as it generates sufficient cash flow, 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 and gas 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. Current global conflicts, including the war in Iran, have caused volatility in the energy markets and a significant short term increase in oil prices but these factors have not impacted the Company’s current development plan for the field.

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 2026, 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