MANAGEMENT’S DISCUSSION AND ANALYSIS (Form 6-K)

The third quarter of 2026 report is prepared as of November 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
(US $000 except per share)		Three Months ended								Nine Months ended
		September 30,								September 30,
		2026				2025				2026				2025
Financial
Oil and gas gross revenues			23,120				18,934				76,164				53,744
Oil and gas revenues, net of royalties			18,310				14,956				60,421				42,116
Net operating income(1)			15,761				12,456				51,561				35,651
Net income			3,567				3,598				16,064				12,216
Basic net income per share			0.10				0.10				0.45				0.34
Diluted net income per share			0.10				0.10				0.45				0.34
Cash flows from operating activities			11,588				6,681				39,549				29,175
Adjusted EBITDA(2)			13,300				11,064				44,552				31,565
Additions to property, plant and equipment			19,787				17,369				43,329				44,220
Operating
Average production (Boepd)			3,867				4,254				4,412				3,851
Average price ($/BOE)			64.98				48.38				63.23				51.12
Netback from operations ($/BOE)(3)			43.48				30.84				41.85				32.86
Netback including commodity contracts($/BOE)(3)			40.55				30.89				39.79				32.91

		Sep 30, 2026				Jun 30, 2026				Mar 31, 2026				Dec 31, 2025
Balance Sheet
Cash and cash equivalents			4,384				1,635				2,692				2,797
Total assets			327,565				308,115				294,305				293,942
Working capital (deficiency)			(12,579	)			(14,082	)			(5,082	)			(12,573	)
Available borrowing capacity			19,542				30,542				16,542				15,542
Total non-current liabilities			76,676				64,342				64,776				65,464

(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 2026 was 3,867 BOEPD, a decrease of 9% compared to third quarter 2025 production of 4,254 BOEPD. The decrease in the third quarter of 2026 was primarily due to production on certain wells being temporarily shut in during the drilling and completion operations on the four new wells during the quarter along with normal production declines. Average production for the nine months ended September 30, 2026 was 4,412 BOEPD, an increase of 15% from the average production of 3,851 BOEPD in the same period of 2025. The increase in production for the nine months ended September 30, 2026 was primarily due to production on the wells that were drilled and completed in the fourth quarter of 2025.

Net revenues for the third quarter of 2026 increased by 22% compared to the third quarter of 2025. The increase was due to a 34% increase in average prices partially offset by a 9% decrease in production. Net revenues for the first nine months of 2026 increased by 43% compared to the same period of 2025. The increase was due to a 15% increase in production and a 24% increase in average prices.

Net income in the third quarter of 2026 was $3.6 million, compared to net income of $3.6 million in the same period of 2025. Net income in the first nine months of 2026 was $16.1 million, compared to net income of $12.2 million in the same period of 2025. The increase was primarily due to the increase in revenue partially offset by higher operating expenses and realized and unrealized losses on commodity contracts in 2026.

Adjusted EBITDA⁽¹⁾ was $13.3 million for the third quarter of 2026 compared to $11.1 million for the third quarter of 2025, an increase of 20%. Adjusted EBITDA⁽¹⁾ was $44.6 million for the nine months ended September 30, 2026 compared to $31.6 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 $8.39 per BOE in the third quarter of 2026 compared to $7.37 per BOE in the third quarter of 2025, an increase of 14%. Production and operating expense per barrel averaged $8.43 per BOE in the first nine months of 2026 compared to $7.20 per BOE for the same period of 2025, an increase of 17%. The increases were primarily due to higher severance taxes due to higher prices, workover costs on a non-operated well and higher chemical and water hauling costs in 2026.

Netback from operations⁽²⁾ increased to $43.48 per BOE in the third quarter of 2026 compared to $30.84 per BOE in the same period of 2025, an increase of 41%. Netback including commodity contracts⁽²⁾ for the third quarter of 2026 was $40.55 per BOE compared to $30.89 per BOE in 2025, an increase of 31%. Netback from operations⁽²⁾ increased to $41.85 per BOE in the nine months ended September 30, 2026 compared to $32.86 per BOE in the nine months ended September 30, 2025, an increase of 27%. Netback including commodity contracts⁽²⁾ for the nine months ended September 30, 2026 was $39.79 per BOE, compared to $32.91, an increase of 21% 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 September 30, 2026, the Company had $19.5 million of available borrowing capacity on the credit facility and was in compliance with both of its debt covenants. In October 2026, the credit facility was redetermined with the borrowing capacity remaining at $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 third quarter of 2026 was 3,867 BOEPD, a decrease of 9% compared to third quarter 2025 production of 4,254 BOEPD. The decrease in the third quarter of 2026 was primarily due to certain wells being temporarily shut in during the drilling and completion operations on the four new wells during the quarter along with normal production declines. Average production for the nine months ended September 30, 2026 was 4,412 BOEPD, an increase of 15% from the average production of 3,851 BOEPD in the same period of 2025. The increase in production for the nine months ended September 30, 2026 was primarily due to production from the wells that were drilled and completed in the fourth quarter of 2025.

Production on the three Clifton Mack wells started at the end of the third quarter. As previously announced, the Clifton Mack wells are currently producing at a combined rate of about 1,911 BOEPD, which includes about 720 barrels of oil per day. The Company completed drilling the Lovina 5-8-1H well (98.5% working interest) at the end of the third quarter and fracture stimulation operations were completed in October 2026. As previously announced, production on the Lovina 5-8-1HF well, which is our first False Caney well, has been averaging 636 BOEPD, which includes about 545 barrels of oil per day. The Company expects annual capital expenditures for the year to be between $47 million and $48.5 million which is higher than the previously disclosed forecasted range of $38 million to $43 million.

Production and Revenue		Three months ended September 30												Nine months ended September 30
		2026				2025				%				2026				2025				%
Average production (BOEPD)			3,867				4,254				(9	)			4,412				3,851				15
Average oil production (BOPD)			2,676				2,809				(5	)			3,041				2,589				17
Average natural gas production (MCFPD)			3,901				3,861				1				3,431				3,515				(2	)
Average NGL production (BOEPD)			541				801				(32	)			799				676				18
Average oil price ($/bbl)			85.01				63.93				33				82.82				65.85				26
Average natural gas price ($/mcf)			3.42				2.71				26				2.99				3.22				(7	)
Average NGL price ($/bbl)			19.30				19.74				(2	)			21.16				22.27				(5	)
Average price ($/BOE)			64.98				48.38				34				63.23				51.12				24
Oil gross revenue ($000)			20,932				16,518				27				68,749				46,546				48
Natural gas gross revenue ($000)			1,227				962				28				2,800				3,089				(9	)
NGL gross revenue ($000)			961				1,454				(34	)			4,615				4,109				12

DISCUSSION OF OPERATING RESULTS

Oil production for the third quarter of 2026 was 2,676 BOPD compared to 2,809 BOPD for the same period of 2025, a decrease of 5%. The decrease was due to certain wells being temporarily shut in during the drilling and completion operations on the four new wells during the quarter along with normal production declines. Oil production for the first nine months of 2026 was 3,041 BOPD compared to 2,589 BOPD for the same period of 2025, an increase of 17%. The increase was due to production from the wells that were drilled and completed in the fourth quarter of 2025. Oil revenue increased by 27% in the third quarter of 2026 compared to the same period of 2025 due to an increase in oil prices of 33%, partially offset by the production decrease of 5%. Oil revenue increased by 48% in the first nine months of 2026 compared to the same period of 2025 due to an increase in oil prices of 26%, and a production increase of 17%.

For the third quarter of 2026, average natural gas production was 3,901 MCFPD compared to 3,861 MCFPD for the same period of 2025, an increase of 1%. Average natural gas production for the first nine months of 2026 was 3,431 MCFPD compared to 3,515 MCFPD for the first nine months of 2025, a decrease of 2%. The decrease for the first nine months of 2026 was due to reassessed prior period volume adjustments made by the Company's gas purchaser in the second quarter, which increased NGL production and decreased natural gas production. Natural gas revenue increased by 28% in the third quarter of 2026 compared to the prior year period due to a price increase of 26%. Natural gas revenue decreased by 9% in the first nine months of 2026 versus the same period in 2025 due to a 7% price decrease.

Natural gas liquids (NGL) production in the third quarter of 2026 decreased to 541 BOEPD from 801 BOEPD in the same period of 2025, a decrease of 32%. The decrease was due to certain wells being temporarily shut in during the quarter. NGL production in the first nine months of 2026 increased to 799 BOEPD from 676 BOEPD in the same period of 2025, an increase of 18%. The increase for the first nine months of 2026 was due to reassessed prior period volume adjustments made by the Company's gas purchaser in the second quarter, which increased NGL production and decreased natural gas production. NGL revenue decreased by 34% in the third quarter of 2026 compared to the same period in 2025 due to the 32% production decrease and a 2% price decrease. NGL revenue increased by 12% in the first nine months of 2026 compared to the same period in 2025 due to the 18% production increase partially offset by a 5% decrease in NGL prices.

Average production on a per BOE basis was 3,867 BOEPD in the third quarter of 2026 compared to 4,254 BOEPD in the same period of 2025, a decrease of 9%. The decrease was due to the factors discussed above. Average production on a per BOE basis was 4,412 BOEPD in the first nine months of 2026 compared to 3,851 BOEPD in the same period of 2025, an increase of 15%. The increase was due to the factors discussed above. Gross revenue for the third quarter of 2026 increased by 22% compared to the third quarter of 2025 due to increases in revenue for oil and natural gas partially offset by lower NGL revenue. Gross revenue for the first nine months of 2026 increased by 42% compared to the same period of 2025 due to increases in revenue for oil and NGLs, partially offset by lower gas revenue.

Royalties, Operating Expenses and Netback

		Three months ended September 30												Nine months ended September 30
($/BOE)		2026				2025				%				2026				2025				%
Average price			64.98				48.38				34				63.23				51.12				24
Less: royalties			13.11				10.17				29				12.95				11.06				17
Less: operating expenses(3)			8.39				7.37				14				8.43				7.20				17
Netback from operations(1)			43.48				30.84				41				41.85				32.86				27
Price adjustment from commodity contracts(2)			(2.93	)			0.05				-				(2.06	)			0.05				-
Netback including commodity contracts(1)			40.55				30.89				31				39.79				32.91				21

(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 include compressor costs of $0.4 million in the third quarter of 2026 and $1.3 million in the first nine months of 2026 and compressor costs of $0.4 million in the third quarter of 2025 and $1.1 million in the first nine months of 2025 that are accounted for as a lease under IFRS 16.

Average prices increased by 34% in the third quarter of 2026, compared to the same period in the prior year, due to the price increases in oil and natural gas as discussed above. Oil made up 69% of the production mix in the third quarter of 2026 compared to 66% for the same period in 2025. Average prices increased by 24% in the first nine months of 2026, compared to the same period in the prior year, due to the price increase in oil, partially offset by a decrease in natural gas and NGL prices as discussed above. Oil made up 69% of the production mix in the first nine months of 2026 compared to 67% for the same period in 2025.

Royalties on Tishomingo production averaged approximately 20.8% for the third quarter of 2026 versus 21.0% in the third quarter of 2025. Royalties on Tishomingo production averaged approximately 20.7% for the first nine months of 2026 versus 21.6% in the first nine 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. Production and operating expense per barrel averaged $8.39 per BOE in the third quarter of 2026 compared to $7.37 per BOE in the third quarter of 2025, an increase of 14%. Production and operating expense per barrel averaged $8.43 per BOE in the first nine months of 2026 compared to $7.20 per BOE for the same period of 2025, an increase of 17%. The increases were primarily due to higher severance taxes due to higher prices, workover costs on a non-operated well and higher chemical costs in 2026.

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 September 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 $2.3 million net liability as of September 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 $2.1 million and a long term liability of $0.2 million (December 31, 2025: current asset of $0.4 million).

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

($000s)		Three months ended September 30,								Nine months ended September 30,
		2026				2025				2026				2025
Realized gain (loss) on financial commodity contracts		$	(1,043	)		$	18			$	(2,491	)		$	58
Unrealized loss on financial commodity contracts		$	(2,433	)		$	(464	)		$	(3,160	)		$	(9	)

Production and Operating Expenses

Production and operating expenses were $2.5 million for the third quarter of 2026 versus $2.5 million for the third quarter of 2025. Production and operating expenses were $8.9 million for the first nine months of 2026 versus $6.5 million for the first nine months of 2025. The increase in the first nine months of 2026 compared to the prior year period was due to the increase in production.

General and Administrative Expenses

General & Administrative ("G&A") expense for the third quarter of 2026 and the third quarter of 2025 was $1.4 million. G&A expense for the first nine months of 2026 was $4.5 million compared to $4.1 million for the same period of 2025, an increase of 9%. The increase was primarily due to an increase in consulting and legal costs in 2026 compared to the same period in 2025.

Depletion and Depreciation and Amortization

Depletion, depreciation and amortization ("DD&A") expense for the third quarter of 2026 was $4.3 million compared to $4.6 million in the same period of 2025. DD&A expense on a per barrel basis was $12.07 for the third quarter of 2026 compared to $11.64 for the third quarter of 2025. The decrease in the DD&A expense was primarily due to the decrease in production in 2026 compared to the same period in 2025. DD&A expense for the first nine months of 2026 and 2025 was $14.4 million and $12.1 million, respectively. DD&A expense on a per barrel basis was $11.98 for the first nine months of 2026 compared to $11.54 for the first nine months of 2025. The increase in the DD&A expense was primarily due to the increase in production in the first nine months of 2026 compared to the same period in 2025.

Interest on loans and borrowings

Interest on loans and borrowings was $0.8 million in the third quarter of 2026 compared to $0.9 million for the same period of 2025. The decrease was due to a lower interest rate in 2026 compared to 2025. Interest on loans and borrowings increased from $2.2 million in the first nine months of 2025 to $3.1 million for the same period of 2026. The increase was due to an increase in the outstanding debt balance during 2026 compared to 2025, partially offset by a decrease in interest rates.

Income tax expense

Income tax expense was $1.4 million in the third quarter of 2026 versus $1.2 million in the same period of 2025. Income tax expense was $5.6 million in the first nine months of 2026 versus $4.1 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 $3.6 million ($0.10 per basic share) in the third quarter of 2026 compared to net income of $3.6 million ($0.10 per basic share) for the same period of 2025. The change in net income in the third quarter of 2026 compared to the same period in 2025 was due to an increase in revenue net of royalties of $3.4 million and a decrease in DD&A expense of $0.3 million, partially offset by a higher net loss in realized and unrealized financial commodity contracts of $3.0 million and an increase in stock based compensation of $0.3 million.

The Company had net income of $16.1 million ($0.45 per basic share) in the first nine months of 2026 compared to net income of $12.2 million ($0.34 per basic share) for the same period of 2025. The change in net income in 2026 compared to the same period in 2025 was due to an increase in revenue net of royalties of $18.3 million partially offset by an increase in operating expenses of $2.4 million, an increase in DD&A expense of $2.3 million, an increase in income tax expense of $1.4 million, an increase in interest expense of $0.9 million, an increase in stock based compensation of $0.9 million and an increase in net loss on realized and unrealized financial commodity contracts of $5.6 million.

Cash from operating activities

Cash flows from operating activities for the first nine months of 2026 was $39.5 million compared to cash flows from operating activities of $29.2 million in the same period of 2025. The increase in 2026 was 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 nine months of 2026 was $42.7 million compared to cash flows used in investing activities of $40.2 million in the same period of 2025. The increase was due to the difference in timing of working capital changes between 2026 and 2025.

Cash flows from financing activities

Cash flows from financing activities for the first nine months of 2026 was $4.8 million compared to cash flows from financing activities of $10.0 million in the first nine months of 2025. The decrease was due to net borrowings of $6.0 million on loans and borrowings in 2026 compared to net borrowings on loans and borrowings of $13 million in 2025.

CAPITAL EXPENDITURES

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

($000)		Nine Months Ended September 30,
		2026				2025
Additions to oil and gas properties		$	43,329			$	44,220
		$	43,329			$	44,220

LIQUIDITY AND CAPITAL RESOURCES

(000s; other than number of shares and per share amounts)		September 30, 2026				December 31, 2025
Working Capital (Deficiency) (US$)		$	(12,579	)		$	(12,573	)
Loans and Borrowings (US$)		$	55,458			$	49,458
Shares Outstanding, end of period			35,951,495				35,471,833
Market Price per share (in Canadian $)		$	8.80			$	5.41
Market Value of Shares (in Canadian $)		$	316,373			$	191,903

The borrowing base of the credit facility is $75.0 million and the Company has an available borrowing capacity of $19.5 million at September 30, 2026. The credit facility is subject to a semi-annual review and redetermination of the borrowing base.

In October 2026, the credit facility was redetermined with the borrowing capacity remaining at $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 September 30, 2026. At September 30, 2026, the Current Ratio of the US Subsidiary was 1.28 to 1.0 and the Maximum Leverage Ratio was 1.08 to 1.0 for the three months ended September 30, 2026.

At September 30, 2026, loans and borrowings of $55.5 million (December 31, 2025: $49.5 million) are presented net of loan acquisition costs of $0.7 million (December 31, 2025: $0.7 million).

At September 30, 2026, the Company had a working capital deficit of $12.6 million compared to a working capital deficit of $12.6 million at December 31, 2025. The Company had available borrowing capacity of $19.5 million at September 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 September 30, 2026:

		Total				2026				2027				Thereafter
Liabilities ($000s)
Lease payable		$	1,333			$	421			$	827			$	85
Loans and borrowings*			67,201				1,068				4,270				61,863
Accounts payable and other payables			25,100				25,100				-				-
Fair value of commodity contracts			2,274				880				1,394
		$	95,908			$	27,469			$	6,491			$	61,948

*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 September 30, 2026 was 7.7%. 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:

		2026												2025															2024
		Q3				Q2				Q1				Q4				Q3				Q2				Q1				Q4
Daily Production
Oil (BOPD)			2,676				3,022				3,452				3,131				2,809				2,115				2,844				3097
Natural gas (MCFPD)			3,901				2,764				3,624				3,639				3,861				2,880				3,803				3,615
NGLs (BOEPD)			541				1,227				629				755				801				625				599				740
Average production (BOEPD)			3,867				4,690				4,685				4,493				4,254				3,220				4,077				4,440

		2026												2025															2024
		Q3				Q2				Q1				Q4				Q3				Q2				Q1				Q4
Average Price
Oil ($/bbl)			85.01				95.08				70.31				57.11				63.93				62.25				70.51				69.00
Natural gas ($/mcf)			3.42				0.04				4.79				2.56				2.71				3.09				3.85				2.82
NGL ($/bbl)			19.30				21.46				22.21				15.05				19.74				17.59				30.67				23.38
Average price ($/BOE)			64.98				66.50				58.49				44.39				48.38				47.06				57.28				54.32

		2026												2025															2024
($/BOE)		Q3				Q2				Q1				Q4				Q3				Q2				Q1				Q4
Netback(1)
Average price ($/BOE)			64.98				66.50				58.49				44.39				48.38				47.06				57.28				54.32
Royalties			13.11				13.68				12.08				8.73				10.17				10.25				12.66				11.79
Operating expenses(4)			8.39				8.90				8.00				7.67				7.37				7.15				7.07				6.59
Netback from operations(1)			43.48				43.92				38.41				27.99				30.84				29.66				37.55				35.94
Price adjustment from commodity contracts			(2.93	)			(2.71	)			(0.69	)			0.32				0.05				0.13				-				(0.04	)
Netback including commodity contracts(1)			40.55				41.21				37.72				28.31				30.89				29.79				37.55				35.90

		2026												2025															2024
($000, except as noted)		Q3				Q2				Q1				Q4				Q3				Q2				Q1				Q4
Net operating income(2)
Oil and gas gross revenue			23,120				28,380				24,664				18,349				18,934				13,790				21,020				22,185
Royalties			4,810				5,838				5,095				3,609				3,978				3,002				4,648				4,812
Operating expenses			2,549				3,377				2,934				2,778				2,500				1,738				2,227				2,354
			15,761				19,165				16,635				11,962				12,456				9,050				14,145				15,019

		2026												2025															2024
($000, except as noted)		Q3				Q2				Q1				Q4				Q3				Q2				Q1				Q4
Net income			3,567				8,470				4,027				3,261				3,598				2,853				5,765				5,643
Basic net income ($/share)			0.10				0.24				0.11				0.09				0.1				0.08				0.16				0.16
Adjusted EBITDA(3)			13,300				16,434				14,818				10,542				11,064				7,681				12,820				13,493
Cash flows from operating activities			11,588				16,870				11,091				12,360				6,681				9,487				13,007				10,093
Bank debt			54,786				43,749				47,794				48,757				45,732				29,702				27,277				33,240
Total assets			327,565				308,115				294,305				293,942				282,087				262,817				254,620				248,759

(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 include compressor costs of $1.3 million in 2026, $1.5 million in 2025 and $0.4 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 starting at 4,440 BOEPD in the fourth quarter of 2024 to 3,867 BOEPD in the third 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 2026. Oil prices decreased from $69.00 in the fourth quarter of 2024 down to $57.11 in the fourth quarter of 2025 before recovering to $85.01 in the third 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 $13.5 million in the fourth quarter of 2024 and has generally increased or remained constant in subsequent quarters. The third quarter of 2026 adjusted EBITDA was $13.3 million due to higher prices but lower production 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. In the third quarter 2026 net income decreased to $3.6 million due to an unrealized loss on commodity contracts of $2.4 million, a realized loss on commodity contracts of $1.0 million and lower production.

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 $248.8 million in the fourth quarter of 2024 to $327.6 million in the third quarter of 2026.

The Company's net bank debt has increased from $33.2 million to $54.8 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 third quarter 2026 leverage ratio was 1.08 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:

●

Proved and probable oil and gas reserves - Significant assumptions that are valid at the time of oil and gas reserve estimation may change significantly when additional information becomes available. Estimates of economically recoverable proved and probable oil and gas reserves are based upon a number of significant assumptions, such as forecasted production, forecasted oil and gas commodity prices, forecasted operating costs, forecasted royalty costs, and forecasted future development costs. Changes in forecasted oil and gas commodity price assumptions, costs or recovery rates may change the economic status of proved and probable oil and gas reserves and may ultimately result in a restatement of proved and probable oil and gas reserves. Independent third-party reserve evaluators are engaged at least annually to estimate proved and probable oil and gas reserves.

●	Discount rate - The discount rate used to calculate the net present value of cash flows is based on estimates of an industry peer group weighted average cost of capital. Changes in the economic environment could result in significant changes to this estimate.

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 35,951,495, 35,951,495 and 35,471,833 common shares outstanding as of November 12, 2026, September 30, 2026 and December 31, 2025, respectively. The Company had 817,657, 817,657 and 882,621 stock options outstanding as of November 12, 2026, September 30, 2026 and December 31, 2025, respectively. The Company had 659,181, 659,181, and 509,959 restricted share units (RSUs) outstanding as of November 12, 2026, September 30, 2026 and December 31, 2025, respectively.

NORMAL COURSE ISSUER BID

On September 21, 2026, the Company announced a normal course issuer bid (the "Bid") to purchase up to an aggregate of 1,797,574 common shares, being approximately 5% of the total number of 35,951,495 common shares issued and outstanding as at September 18, 2026, through the facilities of the Nasdaq Capital Market. 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. As of the date of this MD&A, no shares have been purchased under the Bid.

During its previous normal course issuer bids, the Company repurchased an aggregate of 661,052 common shares at an average price of US$5.09 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 uncertainty of finding oil and gas in commercial quantities
	●	risks related to the threat or imposition of tariffs which could impact the cost of capital expenditures and disrupt supply chains in the future
	●	securing markets for existing and future production
	●	commodity price fluctuations due to market forces
	●	volatile market conditions related to current ongoing global conflicts, including the war in Iran, which could affect global supply dynamics and lead to heightened price volatility. Increases in oil prices will benefit revenues in the short term but sustained geopolitical instability could lead to abrupt price swings and a potential global economic slowdown
	●	financial risk due to foreign exchange rates and interest rate exposure
	●	changes to government regulations in the United States, including regulations relating to prices, taxes, royalties and environmental protection
	●	changing government policies and regulations, social instability and other political, economic or diplomatic developments in the countries in which the Company operates
	●	uncertainty regarding the Company's ability to fund wells drilled in non-operated sections of the Tishomingo field
	●	production-related risks leading to temporary shutting-in of wells, including, but not limited to, weather related risks and field conditions, completion activities of other operators in close proximity to the Company's wells, adverse conditions affecting production, transportation or processing, and the uncertainty of pipeline repairs
	●	availability of equity or debt financing is affected by many factors, many of which are beyond the control of the Company
	●	uncertainties inherent in estimating quantities of oil and natural gas reserves and cash flows to be derived therefrom
	●	the oil and gas industry is intensely competitive and the Company competes with a large number of companies with greater resources
	●	risks related to evolving emissions, carbon and other regulations impacting climate change and the advancement of alternative sources of renewable energy

	●	risks related to the limit on the number of common shares that the Company is authorized to issue being 37,367,894 (the "Share Limit"), without approval by the shareholders of the Company, which limit was passed at a requisitioned special meeting of the Company's shareholders on November 25, 2025
	●	risks related to the Credit Facility, including the risk that the Company could be required under the terms of the Credit Facility to prepay the outstanding principal amount and other amounts owing under the Credit Facility in certain circumstances, some of which are out of the Company's control, including failure to comply with financial ratio tests, borrowing base redeterminations, Mr. Wolf Regener ceasing to be the President of Kolibri Global Energy Inc., certain changes to the board of directors of the Company and the acquisition by any person or persons acting jointly or in concert of 25% or more of the Company's shares. There can be no assurance that the Company will be able to obtain sufficient capital to repay the Credit Facility. A failure by the Company to perform its obligations under the Credit Facility could result in, among other adverse effects, the loss of the Company's Tishomingo Field assets. See "Liquidity and Capital Resources" and "Contractual Obligations" above and the "Risk Factors" section in the Company's most recent Annual Information Form.
	●	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.

The Company seeks to mitigate these risks by:

	●	maintaining product mix to manage exposure to commodity price risk
	●	monitoring the impact of tariffs on prices and supply chains to ensure the Company can execute its drilling program
	●	monitoring production trends to maximize the potential of its capital spending program
	●	from time to time, entering into financial commodity contracts to hedge against commodity price risk
	●	ensuring strong third-party operators for non-operated properties
	●	transacting with creditworthy counterparties
	●	monitoring commodity prices and capital programs to manage cash flows
	●	reviewing proposed changes in applicable government regulations and laws to assess the impact on the Company's operations

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 September 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 September 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:

(US $000)		Three months ended September 30,								Nine months ended September 30,
		2026				2025				2026				2025
Net income			3,567				3,598				16,064				12,216
Adjustments:
Income tax expense			1,382				1,228				5,569				4,145
Finance income			(6	)			(28	)			(10	)			(84	)
Finance expense			4,381				1,419				8,968				2,423
Share based compensation			786				512				2,079				1,237
General and administrative expenses			1,418				1,410				4,518				4,144
Depletion, depreciation and amortization			4,293				4,555				14,434				12,134
Other income			(60	)			(238	)			(61	)			(564	)
Netback from operations			15,761				12,456				51,561				35,651
Netback from operations ($ per BOE)			43.48				30.84				41.85				32.86

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:

(US $000)		Three Months ended September 30,								Nine months ended September 30,
		2026				2025				2026				2025
Oil and gas revenue, net of royalties			18,310				14,956				60,421				42,116
Less: production and operating expenses			2,549				2,500				8,860				6,465
Net operating income			15,761				12,456				51,561				35,651

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:

(US $000)		Three months ended September 30,								Nine months ended September 30,
		2026				2025				2026				2025
Net income			3,567				3,598				16,064				12,216
Income tax expense			1,382				1,228				5,569				4,145
Depletion and depreciation			4,293				4,555				14,434				12,134
Accretion			64				64				194				188
Interest expense			841				890				3,123				2,226
Unrealized (gain) loss on commodity contracts			2,433				464				3,160				9
Share based compensation			786				512				2,079				1,237
Interest income			(5	)			(10	)			(7	)			(26	)
Other income			(60	)			(238	)			(61	)			(564	)
Foreign currency loss (gain)			(1	)			1				(3	)			-
Adjusted EBITDA			13,300				11,064				44,552				31,565

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

(a)

The Company's natural gas production is reported in thousands of cubic feet ("Mcfs"). The Company also uses references to barrels ("Bbls") and barrels of oil equivalent ("BOEs") to reflect natural gas liquids and oil production and sales. BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

(b)

Discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value.

(c)

Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

(d)

This MD&A and the Company's other public disclosure contains peak and 30-day initial production rates and other short-term production rates. Readers are cautioned that initial production rates are preliminary in nature and are not necessarily indicative of long-term performance or of ultimate recovery.

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 management's expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the combination of cash on hand and cash flows from operating activities will be sufficient to finance the Company's cash requirements through 2027, 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.