Exhibit 99-1

UNAUDITED CONDENSED

CONSOLIDATED INTERIM

FINANCIAL STATEMENTS

SEPTEMBER 30, 2024

KOLIBRI GLOBAL ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF FINANCIAL POSITION

(Unaudited, Expressed in Thousands of United States Dollars)

See accompanying notes to unaudited condensed consolidated interim financial statements.

KOLIBRI GLOBAL ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(Unaudited, expressed in Thousands of United States dollars, except per share amounts)

See accompanying notes to the unaudited condensed consolidated interim financial statements.

KOLIBRI GLOBAL ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited, Expressed in Thousands of United States Dollars, except number of common shares)

See accompanying notes to the unaudited condensed consolidated interim financial statements.

KOLIBRI GLOBAL ENERGY INC.

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

NINE MONTHS ENDED SEPTEMBER 30

(Unaudited, Expressed in Thousands of United States Dollars)

See accompanying notes to the unaudited condensed consolidated interim financial statements.

Notes to the Condensed Interim Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2024

(Unaudited, expressed in Thousands of United States dollars except per share information)

Kolibri Global Energy Inc. (the “Company” or “KEI”), was incorporated under the Business Corporations Act (British Columbia) on May 6, 2008. KEI is a North American energy company focused on finding and exploiting energy projects in oil and gas. The Company owns and operates energy properties in the United States. The Company continues to utilize its technical and operational expertise to identify and acquire additional projects in oil, gas and clean and sustainable energy. The Company’s shares are traded on the Toronto Stock Exchange under the stock symbol KEI and on the NASDAQ under the stock symbol KGEI.

The condensed consolidated interim financial statements were approved by the Company’s Board of Directors on November 12, 2024.

These unaudited condensed consolidated interim financial statements have been prepared in accordance with International Accounting Standard (IAS) 34, “Interim Financial Reporting” following the same accounting policies, except as described below, and methods of computation as the annual consolidated financial statements of the Company for the year ended December 31, 2023. The disclosures provided below are incremental to those included with the annual consolidated financial statements and certain disclosures, which are normally required to be included in the notes to the annual consolidated financial statements, have been condensed or omitted. These unaudited condensed consolidated interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto in the Company’s annual filings for the year ended December 31, 2023.

New Standards and Interpretations adopted

The following IFRS standards have been adopted by the Company:

Amendment to IFRS 16 – Leases on sale and leaseback. This amendment specifies how an entity accounts for a sale and leaseback after the date of the transaction. The Company adopted this standard on January 1, 2024 and it did not have a significant impact on the Company.

Amendment to IFRS 1 – Non-current liabilities with covenants. This amendment specifies how an entity must comply within twelve months after the reporting period affecting the classification of a liability. The Company adopted this standard on January 1, 2024 and it did not have a significant impact on the Company.

Amendment to IAS 7 and IFRS 7 – Supplier finance. This amendment requires disclosures of supplier finance arrangements and their impact to a company’s liquidity risk. The Company adopted this standard on January 1, 2024 and it did not have a significant impact on the Company.

Notes to the Condensed Interim Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2024

(Unaudited, expressed in Thousands of United States dollars except per share information)

At September 30, 2024 the following financial commodity contracts were outstanding and recorded at estimated fair value:

The estimated fair value results in a $0.8 million asset as of September 30, 2024 (December 31, 2023: $0.1 million liability) 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 $0.7 million and a long term asset of $0.1 million (December 31, 2023: current liability of $0.1 million and a long term asset of $0.1 million).

Notes to the Condensed Interim Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2024

(Unaudited, expressed in Thousands of United States dollars except per share information)

In October 2024, the Company entered into the following additional financial commodity contracts:

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

Changes in non-cash working capital is comprised of:

Notes to the Condensed Interim Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2024

(Unaudited, expressed in Thousands of United States dollars except per share information)

Notes to the Condensed Interim Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2024

(Unaudited, expressed in Thousands of United States dollars except per share information)

In May 2022, the Company’s US subsidiary amended the credit facility from BOK Financial, which is secured by the US subsidiary’s interests in the Tishomingo Field. The credit facility expires in June 2026 and is intended to fund the drilling of the Caney wells in the Tishomingo Field.

For the May 2024 redetermination, the borrowing base of the credit facility was increased from $40.0 million to $50.0 million and the borrowing based remained at $50 million in the October 2024 redetermination. The Company has an available borrowing capacity of $19.0 million at September 30, 2024. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The next redetermination will be in the second 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 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.

Notes to the Condensed Interim Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2024

(Unaudited, expressed in Thousands of United States dollars except per share information)

The Company was in compliance with both covenants for the quarter ended September 30, 2024. At September 30, 2024, the Current Ratio of the US Subsidiary was 2.1 to 1.0 and the Maximum Leverage Ratio was 0.8 to 1.0 for the three months ended September 30, 2024.

At September 30, 2024, loans and borrowings of $31.0 million (December 31, 2023: $30.0 million) are presented net of loan acquisition costs of $0.3 million (December 31, 2023: $0.3 million).

The number and weighted average exercise prices of stock options are as follows:

The range of exercise prices of the outstanding stock options is as follows:

The fair value of the stock options was estimated using Black Scholes model with the following weighted average inputs:

Notes to the Condensed Interim Consolidated Financial Statements

For the Three and Nine Months Ended September 30, 2024

(Unaudited, expressed in Thousands of United States dollars except per share information)

The number and weighted average fair value of Restricted Stock Units (RSUs) are as follows:

Share based compensation was recorded as follows:

The following table presents the Company’s gross oil and gas revenue disaggregated by revenue source:

Income tax expense is charged at 25.7% for the nine months ended September 30, 2024 representing the best estimate of the average annual effective tax rate expected to apply for the full year, applied to the pre-tax income of the nine-month period.

The Company has recorded natural gas and NGL processing costs related to prior years as the purchaser reassessed prior year gathering and processing costs. Under the terms of the Company’s contract with the purchaser, they are able to correct their fee billings if they find adjustments related to the last 24 months, which is a common industry practice. These amounts, which totaled $0.8 million in the nine months ended September 30, 2024, are included in production and operating expenses. The Company is not aware of any additional reassessed costs and future adjustments may never occur.

 In October 2024, the Company began repurchasing shares under its Normal Course Issuer Bid share buyback program.  The Company has repurchased approximately 104,000 shares at an average price of CAD$4.58 per share.

Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

SEPTEMBER 30, 2024

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 three and nine months ended September 30, 2024, compared to the corresponding periods 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 three and nine months ended September 30, 2024 and the audited consolidated financial statements and MD&A for the year ended December 31, 2023. 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 IFRS and do not have any standardized meanings prescribed by IFRS. Management of the Company believes that such measures and ratios are relevant for evaluating returns on each of the Company’s projects as well as the performance of the enterprise as a whole. The Company’s Non-GAAP Measures may differ from similar computations as reported by other similar organizations and, accordingly, may not be comparable to similar non-GAAP measures and ratios as reported by such organizations. The Company’s Non-GAAP Measures should not be construed as alternatives to net income, cash flows from operating activities, working capital or other financial measures and ratios determined in accordance with IFRS, as an indicator of the Company’s performance.

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, gas and clean and sustainable energy. 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 2024 was 3,032 barrels of oil equivalent per day (BOEPD), an increase of 11% compared to third quarter 2023 production of 2,737 BOEPD. Average production for the nine months ended September 30, 2024 was 3,154 BOEPD, an increase of 13% from the average production of 2,780 BOEPD in the same period of 2023. The increases are due to production from the wells that were drilled and completed in the last three months of 2023 and the first nine months of 2024.

Net income in the third quarter of 2024 was $5.1 million, compared to net income of $2.3 million in the same period of 2023, which was an increase of 118%. The increase was due to higher revenue and an unrealized gain of $1.3 million from commodity contracts in the third quarter of 2024 compared to an unrealized loss on commodity contracts of $2.6 million in the prior year period partially offset by higher income tax expense. Net income in the first nine months of 2024 was $12.5 million, compared to net income of $14.5 million in the same period of 2023. The decrease was due to higher income tax expense of $4.3 million partially offset by higher revenue and a $0.9 million unrealized gain on commodity contracts in the first nine months of 2024 compared to an unrealized loss of $0.4 million in the prior year period.

Gross revenues for the third quarter of 2024 increased by 1% compared to the third quarter of 2023. The increase was due to an 11% increase in production partially offset by a decrease in average prices of 9% in the three months ended September 30, 2024 compared to the same period in 2023. Gross revenues for the nine months ended September 30, 2024 increased by 10% compared to the same period in 2023. The increase was due to a 13% increase in production partially offset by a decrease in average prices of 2% in the nine months ended September 30, 2024 compared to the same period in 2023.

Adjusted EBITDA(1) was $10.1 million for the third quarter of 2024 compared to $9.5 million for the same period in 2023, an increase of 6%. The increase was due to an 11% increase in production partially offset by a decrease in average prices of 9% in the three months ended September 30, 2024 compared to the same period in 2023. Adjusted EBITDA(1) was $30.5 million for the nine months ended September 30, 2024 compared to $28.6 million for the prior year period, an increase of 7%. The increase was due to a 13% increase in production partially offset by a decrease in average prices of 2% in the nine months ended September 30, 2024 compared to the same period in 2023.

Production and operating expense per barrel averaged $6.63 per BOE in the third quarter of 2024 compared to $7.34 per BOE in the third quarter of 2023, a decrease of 10%. The decrease was due to increased production which reduced the per barrel fixed costs. Production and operating expense per barrel averaged $7.84 per BOE in the first nine months of 2024 compared to $6.47 per BOE for the same period of 2023, an increase of 22%. The increase was mainly due to natural gas and NGL processing costs of $0.8 million, or $0.83 per BOE, related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024. Under the terms of the Company’s contract with the purchaser, adjustments to fee billings over the last 24 months are permissible. The adjustments received to date cover 2022 and 2023. Without these costs, operating expense per barrel would be $7.01 per BOE for the first nine months of 2024, an increase of 8% due to higher water hauling costs.

Netback from operations(2) decreased to $40.01 per BOE in the third quarter of 2024 compared to $43.28 per BOE in the same period of 2023, a decrease of 8% due to lower average prices. Netback from operations(2) decreased to $39.78 per BOE in the nine months ended September 30, 2024 compared to $42.48 per BOE in the nine months ending September 30, 2023, a decrease of 6% due to lower prices and higher operating expenses. Netback including commodity contracts(2) for the third quarter of 2024 was $39.95 per BOE compared to $41.65 in 2023, a decrease of 4% from the prior year period. Netback including commodity contracts(2) for the nine months ended September 30, 2024 was $39.09 per BOE, compared to $41.00, a decrease of 5% from the prior year period.

At September 30, 2024, the Company had $19.0 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 2024 was 3,032 BOEPD, an increase of 11% compared to third quarter 2023 production of 2,737 BOEPD. Average production for the nine months ended September 30, 2024 was 3,154 BOEPD, an increase of 13% from the average production of 2,780 BOEPD in the same period of 2023. The increases are due to production from the wells that were drilled and completed in the last three months of 2023 and the first nine months of 2024.

At the end of the quarter, the Company had completed drilling the last three wells in the 2024 drilling program, the Alicia Renee 2-11-3H, Alicia Renee 2-11-4H and Alicia Renee 2-11-5H (all 100% working interest) and completion operations were finished in October. These wells, which are all 1.5-mile lateral wells, are currently flowing back the fracture stimulation fluid. The wells are still cleaning up, but over the last five days, the Alicia 2-11-3H well has averaged 1,049 Barrels of oil equivalent per day (“BOEPD”) (720 barrels of oil per day (“BOPD”)), the Alicia 2-11-4H well has averaged 845 BOEPD (590 BOPD) and the Alicia 2-11-5H well has averaged 630 BOEPD (435 BOPD).

DISCUSSION OF OPERATING RESULTS

Oil production for the third quarter of 2024 was 2,247 BOPD compared to 2,083 BOPD for the same period of 2023, an increase of 8%. Oil production for the first nine months of 2024 was 2,326 BOPD compared to 2,110 BOPD for the same period of 2023, an increase of 10%. The increases are due to production from the wells that were drilled and completed in the last three months of 2023 and the first nine months of 2024. Oil revenue increased by 1% in the third quarter of 2024 compared to the same period of 2023 due to the production increase, partially offset by a decrease in oil prices of 7%. Oil revenue increased by 12% in the first nine months of 2024 compared to the same period of 2023 due to the production increase and an increase in oil prices of 1%.

For the third quarter of 2024, average natural gas production was 1,948 MCFPD compared to 1,565 MCFPD for the same period of 2023, an increase of 24%. Average natural gas production for the first nine months of 2024 was 2,078 MCFPD compared to 1,698 MCFPD for the first nine months of 2023, an increase of 22%. The increases are due to production from the wells that were drilled and completed in the last three months of 2023 and the first nine months of 2024. Natural gas revenue decreased by 45% in the third quarter of 2024 compared to the same period in 2023 due to the decrease in natural gas prices of 55% partially offset by the production increase. Natural gas revenue decreased by 44% in the first nine months of 2024 versus the same period in 2023 due to a decrease in natural gas prices of 54% partially offset by the production increase.

Natural gas liquids (NGL) production in the third quarter of 2024 increased to 460 BOEPD from 393 BOEPD in the same period of 2023, an increase of 17%. NGL production in the first nine months of 2024 increased to 482 BOEPD from 387 BOEPD in the same period of 2023, an increase of 25%. The increases are due to production from the wells that were drilled and completed in the last three months of 2023 and the first nine months of 2024. NGL revenue increased by 21% in the third quarter of 2024 compared to the same period in 2023 due to an increase in NGL prices of 4% and the production increase. NGL revenue increased by 33% in the first nine months of 2024 compared to the same period in 2023 due to an increase in NGL prices of 6% and the production increase.

Average production on a per BOE basis was 3,032 BOEPD in the third quarter of 2024 compared to 2,737 BOEPD in the same period of 2023, an increase of 11%. Average production on a per BOE basis was 3,154 BOEPD in the first nine months of 2024 compared to 2,780 BOEPD in the same period of 2023, an increase of 13%. The increase is due to the factors discussed above. Gross revenue for the third quarter of 2024 increased by 1% compared to the third quarter of 2023 due to an increase in production, partially offset by a decrease in average prices. Gross revenue for the first nine months of 2024 increased by 11% compared to the same period of 2023 due to an increase in average prices and an increase in production.

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 $0.3 million and $0.2 million in the three months ended September 2024 and 2023, respectively, and $0.9 million and $0.5 million in the nine months ended September 30, 2024 and 2023, respectively, that are accounted for as a lease under IFRS 16 as of January 1, 2023.

(4) Includes natural gas and NGL processing costs related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024 totaling $0.8 million, or $0.83 per BOE, in the nine months ended September 2024.

Average prices decreased by 9% in the third quarter of 2024, compared to the same period in the prior year, due to the price decreases in oil and gas, partially offset by an increase in NGL prices as discussed above. Oil made up 74% of the production mix in the third quarter of 2024 compared to 76% for the same period in 2023. Average prices decreased by 2% in the first nine months of 2024, compared to the same period in the prior year, due to the price decrease in gas, partially offset by increases in oil and NGLs. Oil made up 74% of the production mix in the first nine months of 2024 compared to 76% for the same period in 2023.

Royalties on Tishomingo production averaged approximately 21.1% for the third quarter of 2024 versus 22.2% in the third quarter of 2023. Royalties on Tishomingo production averaged approximately 21.5% for the first nine months of 2024 versus 21.3% in the first nine months of 2023. The differences in percentages in both periods are due to different royalty burdens on the 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 $6.63 per BOE for the third quarter of 2024 compared to $7.34 per BOE for the same period in 2023. The decrease was due to increased production which reduced the per barrel fixed costs. Operating expenses averaged $7.84 per BOE for the first nine months of 2024 compared to $6.47 per BOE for the same period in 2023. The increase was mainly due to natural gas and NGL processing costs of $0.8 million, or $0.83 per BOE, related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024. Under the terms of the Company’s contract with the purchaser, adjustments to fee billings over the last 24 months are permissible. The adjustments received to date cover 2022 and 2023. Without these costs, operating expense per barrel would be $7.01 per BOE for the first nine months of 2024, an increase of 8% due to higher water hauling 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 September 30, 2024 the Company had the financial commodity contracts as discussed in note 3 of the Company’s unaudited condensed consolidated interim financial statements. The Company entered into additional commodity contracts in October 2024, which are also discussed in note 3, to meet hedging requirements on its credit facility.

The estimated fair value results in a $0.8 million asset as of September 30, 2024 (December 31, 2023: $0.1 million liability) 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 $0.7 million and a long-term asset of $0.1 million. (December 31, 2023: current liability of $0.1 million and a long-term asset of $0.1 million).

For the third quarter of 2024, approximately 65% of oil production was hedged with costless collars with a price range of $60/bbl to $93.25/bbl. For the first nine months of 2024, approximately 8% of oil production was hedged at $62.77/bbl and 50% of oil production was hedged with costless collars with a price range of $60/bbl to $94.55/bbl.

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

Production and Operating Expenses

Production and operating expenses for the third quarter of 2024 was $1.5 million compared to $1.6 million for the same period of 2023, a decrease of 6%. Production and operating expenses for the first nine months of 2024 were $5.9 million compared to $4.3 million for the same period of 2023, an increase of 38%. The increase was mainly due to 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. Under the terms of the Company’s contract with the purchaser, adjustments to fee billings over the last 24 months are permissible. The adjustments received to date cover 2022 and 2023. The increase is also due to more wells on production and an increase in water hauling costs in 2024 compared to the prior year.

General and Administrative Expenses

G&A expense for the third quarter of 2024 was $1.3 million compared to $1.2 million for the same period of 2023, an increase of 14%. G&A expense for the first nine months of 2024 was $4.1 million compared to $3.1 million for the same period of 2023, an increase of 32%. The increases were primarily due to higher accounting fees and public company costs that resulted from listing on the NASDAQ stock market at the end of 2023 which increased by $0.1 million in the third quarter of 2024 and $0.7 million for the first nine months of 2024. The increases were also due to higher payroll and director costs mainly related to additional personnel and higher investor relations and marketing costs in 2024.

Depletion and Depreciation

Depletion and depreciation expense for the third quarter of 2024 was $3.6 million compared to $3.8 million in the same period of 2023. Depletion and depreciation expense on a per barrel basis was $12.91 for the third quarter of 2024 compared to $15.09 for the third quarter of 2023. Depletion and depreciation expense for the first nine months of 2024 was $11.2 million compared to $11.5 million in the same period of 2023. Depletion and depreciation expense on a per barrel basis was $12.95 for the first nine months of 2024 compared to $15.15 for the first nine months of 2023.

Interest on loans and borrowings

Interest on loans and borrowings increased from $0.7 million in the third quarter of 2023 to $0.8 million for the same period of 2024. Interest on loans and borrowings increased from $1.5 million in the first nine months of 2023 to $2.6 million for the same period of 2024. The increases were due to an increase in interest rates in 2024 and an increase in the outstanding balance in 2024 compared to 2023.

Stock based compensation

Stock based compensation increased from $0.2 million in the third quarter of 2023 to $0.3 million for the same period of 2024. Stock based compensation increased from $0.5 million in the first nine months of 2023 to $0.8 million for the same period of 2024. The increase was due to an increase in the number of stock options and restricted share units granted in 2024 compared to 2023.

Net income for the period

The Company had net income of $5.1 million ($0.14 per basic share) in the third quarter of 2024 compared to net income of $2.3 million ($0.07 per share) for the same period of 2023. The change in net income in 2024 compared to the same period in 2023 is due to a gain in realized and unrealized financial commodity contracts in the third quarter of 2024 totaling $1.3 million versus a loss of $3.0 million in the same period of 2023, an increase in revenue net of royalties of $0.3 million, a decrease in depletion, depreciation and accretion of $0.2 million and a decrease in operating expenses of $0.1 million, partially offset by an increase in income tax expense of $1.7 million, an increase in G&A expense of $0.2 million, an increase in interest on long term debt of $0.2 million, and an increase in stock based compensation of $0.3 million.

The Company had net income of $12.5 million ($0.35 per basic share) in the first nine months of 2024 compared to net income of $14.5 million ($0.41 per share) for the same period of 2023. The change in net income in 2024 compared to the same period in 2023 is due to an increase in income taxes of $4.3 million, an increase in operating expenses of $1.6 million, an increase in interest on long term debt of $1.1 million, an increase in G&A expense of $1.0 million, and an increase in stock based compensation of $0.3 million, partially offset by an increase in revenue net of royalties of $4.0 million, and a net realized and unrealized gain in financial commodity contracts in the first nine months of 2024 totaling $0.3 million versus a net loss of $1.5 million in the same period of 2023.

The explanations for these variances are discussed in the individual sections above.

Cash flows from operating activities

Cash flows from operating activities for the first nine months of 2024 was $28.8 million compared to cash flows from operating activities of $28.7 million for the same period in 2023. The decrease in 2024 compared to the same period in 2023 is due to an increase in operating expenses of $1.6 million, an increase in interest on long term debt of $1.1 million, an increase in G&A expense of $1.0 million, partially offset by an increase in net revenue of $4.0 million.

Cash flows used in investing activities

Cash flows used in investing activities for the first nine months of 2024 was $27.8 million compared to cash flows used in investing activities of $34.5 million for the same period in 2023. The decrease in 2024 compared to the same period in 2023 is due to a decrease of $15.6 million in additions to property plant and equipment.

Cash flows from financing activities

Cash flows from financing activities for the first nine months of 2024 was $0.1 million compared to cash flows from financing activities of $5.3 million for the same period in 2023. The decrease in 2024 compared to the same period in 2023 is due to a decrease in net proceeds from loans and borrowings from $5.9 million in the first nine months of 2023 to $0.9 million in first nine months of 2024.

CAPITAL EXPENDITURES

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

LIQUIDITY AND CAPITAL RESOURCES

In May 2022, the Company’s US subsidiary amended the credit facility from BOK Financial, which is secured by the US subsidiary’s interests in the Tishomingo Field. The credit facility expires in June 2026 and is intended to fund the drilling of the Caney wells in the Tishomingo Field.

For the May 2024 redetermination, the borrowing base of the credit facility was increased from $40.0 million to $50.0 million and the borrowing based remained at $50 million in the October 2024 redetermination. The Company has an available borrowing capacity of $19.0 million at September 30, 2024. The credit facility is subject to a semi-annual review and redetermination of the borrowing base. The next redetermination will be in the second 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 September 30, 2024. At September 30, 2024, the Current Ratio of the US Subsidiary was 2.1 to 1.0 and the Maximum Leverage Ratio was 0.8 to 1.0 for the three months ended September 30, 2024.

At September 30, 2024, loans and borrowings of $31.0 million (December 31, 2023: $30.0 million) are presented net of loan acquisition costs of $0.3 million (December 31, 2023: $0.3 million).

At September 30, 2024, the Company had a working capital deficit of $4.3 million compared to a working capital deficit of $11.9 million at December 31, 2023. The Company had available borrowing capacity of $19.0 million at September 30, 2024. 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

Following are the contractual maturities of financial liabilities, excluding estimated interest payments at September 30, 2024:

* The Credit Facility provides for interest only payments until the September 2026 maturity date. The Company is required to repay amounts owing under the Credit Facility in full on the September 2026 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

Quarterly Variability

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 $0.3 million in the third quarter of 2024 and $0.9 million in the first nine months of 2024 and compressor costs of $0.2 million in the third quarter of 2023 and $0.5 million in the first nine months of 2023 that are accounted for as a lease under IFRS 16.

(5) Includes natural gas and NGL processing costs related to prior years as the purchaser reassessed prior year gathering and processing costs in 2024 totaling $0.8 million, or $0.83 per BOE, in the first nine months of 2024.

Quarterly Variability

The results of the previous eight quarters reflect the Company’s development of the Tishomingo field with production increasing from 1,868 BOEPD in the fourth quarter of 2022 to 3,032 BOEPD in the third quarter of 2024. 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 increased significantly in 2022 due to conflict between Russia and Ukraine as reflected in the fourth quarter 2022 average price of $72.47/BOE. Prices in 2023 and the first nine months of 2024 have since stabilized as reflected in our third quarter 2024 average price of $59.09/BOE.

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 the fourth quarter of 2022, adjusted EBITDA has reflected this increase including our third quarter 2024 adjusted EBITDA of $10.1 million.

Net income 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 between quarter which fluctuate from quarter to quarter. In addition, beginning in the fourth quarter of 2023, the Company has recognized deferred tax expense every quarter including $1.6 million recorded in the third quarter of 2024.

The Company’s bank debt has increased from $18.2 million to $31.0 million 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 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 consolidated 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 consolidated 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 provisions for site restoration and abandonment are 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.

Derivative instruments

The estimated fair value of derivative financial instruments resulting in financial assets and liabilities, by their very nature is subject to estimation, due to the use of future oil and natural gas prices and the volatility in these prices.

Compensation costs

Compensation costs recognized for stock based compensation plans are subject to the estimation of what the ultimate payout will be using pricing models such as Black-Scholes model which is based on assumptions such as volatility, forfeiture rate, interest rate and expected term.

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 35,632,019, 35,735,965 and 35,625,587 common shares outstanding as of November 12, 2024, September 30, 2024 and December 31, 2023, respectively. The Company had 1,078,924 1,078,924 and 939,634 stock options outstanding as of November 12, 2024, September 30, 2024 and December 31, 2023, respectively. The Company had 232,125, 232,125, and 119,140 restricted share units (RSUs) granted as of November 12, 2024, September 30, 2024 and December 31, 2023, 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 with 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.

No shares were repurchase in the third quarter of 2024 but, subsequent to the end of the quarter, the Company has purchased 104,000 shares at an average price of CAD$4.58 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.

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, 2024 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, 2024.

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 and do not have any standardized meanings prescribed by IFRS. Management of the Company believes that such measures and ratios are relevant for evaluating returns on each of the Company’s projects as well as the performance of the enterprise as a whole. The Company’s Non-GAAP Measures may differ from similar computations as reported by other similar organizations and, accordingly, may not be comparable to similar non-GAAP measures and ratios as reported by such organizations. The Company’s Non-GAAP Measures should not be construed as alternatives to net income, cash flows from operating activities, working capital or other financial measures and ratios determined in accordance with IFRS, 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 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:

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: