All amounts are in U.S. Dollars unless otherwise indicated:

THIRD QUARTER 2022 HIGHLIGHTS

• Adjusted EBITDA⁽¹⁾ was $6.9 million in the third quarter of 2022 compared to $1.7 million in the third quarter of 2021, an increase of 296%. The increase was primarily due to an increase in production of 77% and an increase in average prices of 43%, partially offset by higher realized losses from commodity contracts in the third quarter of 2022
• Net income for the third quarter of 2022 was $9.3 million compared to net income of $0.6 million for the third quarter of 2021 due to increases in average prices and production and an unrealized gain on commodity contracts of $4.6 million in the third quarter of 2022
• Revenue, net of royalties was $9.9 million in the third quarter of 2022 compared to $3.9 million for the third quarter of 2021, which was an increase of 152%, as average prices increased by 43% and production increased by 77%
• Average netback from operations⁽²⁾ for the third quarter of 2022 was $55.16/boe, an increase of 54% from the prior year third quarter due to higher prices in 2022. Average netback including commodity contracts⁽²⁾ for the third quarter of 2022 was $49.69 per boe, an increase of 84% from the prior year third quarter
• Average production for the third quarter of 2022 was 1,702 BOEPD, an increase of 77% compared to third quarter 2021 production of 960 BOEPD. This increase is due to production from the Barnes 7-3H well and the Barnes 8-4H well
• Production and operating expenses per barrel averaged $7.77 per BOE in the third quarter of 2022 compared to $8.40 per BOE in the second quarter of 2021, a decrease of 8%. The decrease was due to increased production which reduced the per barrel fixed costs partially offset by higher production taxes due to an increase in prices
• In October 2022, the credit facility was redetermined and the borrowing base was increased from $20 million to $25 million. After the redetermination, the Company has $8.8 million of available borrowing capacity

1. Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
2. Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release.

KEI’s President and Chief Executive Officer, Wolf Regener commented:

“We are pleased that the Company generated third quarter 2022 adjusted EBITDA⁽¹⁾ of $6.9 million which was an increase of almost 300% from the prior year quarter. The Barnes 7-3H well and the Barnes 8-4H well, the first two wells in our 2022 drilling program, continue to exceed management’s type curve.

We are excited that we will bring three wells into production during the fourth quarter. The Company has just completed drilling the Glenn 16-3H well, which is the fifth well in our 2022 drilling program. The Emery 17-2H and Brock 9-3H wells have already been drilled. Completion operations on the Emery 17-2H well have begun, with production expected later in November. The completion operations on the Brock 9-3H well and the Glenn 16-3H well will be done concurrently immediately after the Emery 17-2H well with production expected in December.

Average production for the third quarter of 2022 was 1,702 BOEPD, an increase of 77% compared to third quarter 2021 production of 960 BOEPD due to new production from the Barnes 7-3H well and the Barnes 8-4H well.

Adjusted EBITDA⁽¹⁾ was $6.9 million for the third quarter of 2022 compared to $1.7 million for the prior year third quarter, an increase of 296%. The increase was primarily due to an increase in average prices of 43% and an increase in production of 77%, partially offset by higher realized losses from commodity contracts in the third quarter of 2022.

Net income in the third quarter of 2022 was $9.3 million, compared to a net income of $0.6 million in the third quarter of 2021. The increases were due to higher production and higher average prices and an unrealized gain on commodity contracts of $4.6 million in the third quarter of 2022.

Netback from operations⁽²⁾ increased to $55.16 per BOE in the third quarter of 2022 compared to $35.87 per BOE in the third quarter of 2021, an increase of 54%. Netback including commodity contracts⁽²⁾ for the third quarter of 2022 was $49.69 per BOE, an increase of 84% from the prior year third quarter. The 2022 increases compared to the same periods in the prior year were due to the increase in average prices.

Net revenue was $9.9 million in the third quarter of 2022 compared to $3.9 million for third quarter of 2021, which was an increase of 152% due to higher prices and higher production.

Operating expenses averaged $7.77 per BOE in the third quarter of 2022 compared to $8.40 per BOE in the third quarter of 2021, a decrease of 8%. The decrease was due to increased production which reduced the per barrel fixed costs partially offset by higher production taxes due to an increase in prices.

In October 2022, the credit facility with BOK Financial was redetermined and the borrowing base was increased from $20 million to $25 million. After the redetermination, the Company now has $8.8 million of available borrowing capacity.”

Third Quarter 2022 versus Third Quarter 2021

Oil and gas gross revenues totaled $12.7 million in the third quarter of 2022 versus $5.0 million in the third quarter of 2021. Oil revenues increased $6.7 million or 162% to $10.8 million as average oil prices increased by $23.91 per barrel or 34% to $93.52 and oil production increased by 95% to 1,252 boepd. Natural gas revenues increased by $0.7 or 219% to $1.0 million as natural gas prices increased $6.12/mcf or 149% and average natural gas production increased by 238 mcfpd or 28%. Natural gas liquids (NGLs) revenues increased $0.3 million or 55% as NGL prices increased 3% to $35.33/boe and NGL production increased by 91 boepd or 51%.

Average third quarter 2022 production per day increased 742 boepd or 77% from the third quarter of 2021. The increase was due to new production from the Barnes 7-3H well and the Barnes 8-4H well.

Production and operating expenses increased to $1.2 million in the third quarter of 2022, an increase of 64%. Operating expenses averaged $7.77 per BOE for the third quarter of 2022 compared to $8.40 per BOE for the same period in 2021. The decrease was due to increased production which reduced the per barrel fixed costs partially offset by higher production taxes due to an increase in prices.

Depletion and depreciation expense increased $1.0 million or 113% due to increased production and a higher PP&E balance after the reversal of previous impairment in the fourth quarter of 2021.

General and administrative expenses increased $0.3 million or 39% in the third quarter of 2022 due to due to increases in payroll costs and director fees in 2022 and additional non-recurring professional costs related to the share consolidation process.

Interest expense increased by 19% in the third quarter of 2022 compared to the same period in the prior year due to higher interest rates partially offset by principal payments on the credit which reduced the outstanding loan balance.

Finance income increased by $4.6 million in the third quarter of 2022 compared to the third quarter of 2021 due to realized gains on commodity contracts in the third quarter of 2022.

FIRST NINE MONTHS 2022 HIGHLIGHTS

• Adjusted EBITDA⁽¹⁾ was $18.3 million in the first nine months of 2022 compared to $4.7 million in the first nine months of 2021, an increase of 288%. The increase was primarily due to an increase in average prices of 66% and an increase in production of 58%, partially offset by higher realized losses from commodity contracts in the first nine months of 2022
• Net income for the first nine months of 2022 was $13.9 million compared to net loss of $1.3 million for the third quarter of 2021 due to increases in average prices and production and an unrealized gain on commodity contracts of $1.6 million in the first nine months of 2022
• Revenue, net of royalties was $27.8 million in the first nine months of 2022 compared to $10.7 million for first nine months of 2021, an increase of 160%, due to an increase in average production and average prices
• Average netback from operations⁽²⁾ for the first nine months of 2022 was $57.05/boe, an increase of 81% from the prior year period due to higher prices in 2022. Netback including commodity contracts⁽²⁾ for the first nine months of 2022 was $48.50/boe which was 93% higher than the prior year period
• Average production for the first nine months of 2022 was 1,563 BOEPD, an increase of 58% compared to first nine months 2021 production of 991 BOEPD. This increase is due to production from the Barnes 7-3H well and the Barnes 8-4H well
• Production and operating expenses per barrel averaged $8.17 per BOE in the both the first nine months of 2022 and 2021 as the decrease from increased production which reduced the per barrel fixed costs was offset by higher production taxes due to an increase in prices

1. Adjusted EBITDA is considered a non-GAAP measure. Refer to the section entitled “Non-GAAP Measures” of this earnings release.
2. Netback from operations and netback including commodity contracts are considered non-GAAP ratios. Refer to the section entitled “Non-GAAP Measures” of this earnings release.

First Nine Months of 2022 versus First Nine Months of 2021

Oil and gas gross revenues totaled $35.9 million in the first nine months of 2022 versus $13.7 million in the first nine months of 2021, an increase of 163%. Oil revenues were $31.3 million in the first nine months of 2022 versus $11.5 million in the same period of 2021, an increase of 172% as average oil prices increased 60% to $100.91 a barrel and oil production increased by 69% to 1,137 boepd. Natural gas revenues increased $1.3 million or 157% due to an average natural gas price increase of 106% and a 25% increase in natural gas production. NGL revenue increased $1.1 million or 86% due to an average NGL price increase of 33% and an increase in NGL production of 40% in the first nine months of 2022 compared to the comparable prior year period.

Average production per day for the first nine months of 2022 increased 58% from the prior year comparable period. The increase was due to new production from the Barnes 7-3H well and the Barnes 8-4H well.

Production and operating expenses increased to $3.5 million or 58% in the first nine months of 2022 compared to the prior year period. Production and operating expenses per barrel averaged $8.17 per BOE in the both the first nine months of 2022 and 2021 as the decrease from increased production which reduced the per barrel fixed costs was offset by higher production taxes due to an increase in prices.

Depletion and depreciation expense increased $2.4 million due to increased production and a higher PP&E balance after the reversal of previous impairment in the fourth quarter of 2021.

General and administrative expenses increased $0.4 million or 17% in the first nine months of 2022 due to due to increases in payroll costs and director fees in 2022 and additional non-recurring professional costs related to the share consolidation process.

Finance income increased by $1.6 million due to unrealized gains on financial commodity contracts recorded in 2022.

Finance expense decreased $1.0 million in the first nine months of 2022 due to an unrealized loss on commodity contracts of $3.0 million in 2021 partially offset by higher realized losses on commodity contracts which increased by $2.0 million compared to the prior year period.

The information outlined above is extracted from and should be read in conjunction with the Company's unaudited financial statements for the three and nine months ended September 30, 2022 and the related management's discussion and analysis thereof, copies of which are available under the Company's profile at www.sedar.com.

NON-GAAP MEASURES

Netback from operations, netback including commodity contracts and adjusted EBITDA (collectively, the "Company’s Non-GAAP Measures") are not measures or ratios recognized under Canadian generally accepted accounting principles ("GAAP") 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 related to operating activities, working capital or other financial measures and ratios determined in accordance with IFRS, as an indicator of the Company's performance.

An explanation of how the Company’s Non-GAAP Measures provide useful information to an investor and the purposes for which the Company’s management uses the Non-GAAP Measures is set out in the management's discussion and analysis under the heading “Non-GAAP Measures” which is available under the Company's profile at www.sedar.com and is incorporated by reference into this earnings release.

The following is the reconciliation of the non-GAAP ratio netback from operations to net income (loss) from continuing operations, which the Company considers to be the most directly comparable financial measure that is disclosed in the Company’s financial statements:

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:

CAUTIONARY STATEMENTS

In this news release and the Company’s other public disclosure:

1. 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.
2. Discounted and undiscounted net present value of future net revenues attributable to reserves do not represent fair market value.
3. 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.
4. The Company discloses peak and 30-day initial production rates and other short-term production rates. Readers are cautioned that such 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 release contains forward-looking information including information regarding the proposed timing and expected results of exploratory and development work including production from the Company's Tishomingo field, Oklahoma acreage, expectations regarding cash flow, the Company’s reserves based loan facility, including scheduled repayments, expected hedging levels 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" 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 and that declines will match the modeling, that 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 anticipated results and estimated costs will be consistent with managements’ expectations, that all required permits and approvals and the necessary labor and equipment will be obtained, provided or available, as applicable, on terms that are acceptable to the Company, when required, that no unforeseen delays, unexpected geological or other effects, equipment failures, permitting delays or labor or contract disputes are encountered, that the development plans of the Company and its co-venturers will not change, that the demand for oil and gas will be sustained, that the 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 reserves-based loan facility and that the borrowing base will not be reduced, that funds will be available from the Company’s reserves based loan facility when required to fund planned operations, that the Company will not be adversely affected by changing government policies and regulations, social instability or other political, economic or diplomatic developments in the countries in which it operates and that global economic conditions will not deteriorate in a manner that has an adverse impact on the Company's business and its ability to advance its business strategy.

Forward looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from those anticipated. These risks include, but are not limited to: any of the assumptions on which such forward looking information is based vary or prove to be invalid, including that the Company’s geologic and reservoir models or analysis are not validated, anticipated results and estimated costs will not be consistent with managements’ expectations, the risks associated with the oil and gas industry (e.g. operational risks in development, exploration and production; delays or changes in plans with respect to exploration and development projects or capital expenditures; the uncertainty of reserve and resource estimates and projections relating to production, costs and expenses, and health, safety and environmental risks including flooding and extended interruptions due to inclement or hazardous weather), the risk of commodity price and foreign exchange rate fluctuations, risks and uncertainties associated with securing the necessary regulatory approvals and financing to proceed with continued development of the Tishomingo Field, the Company or its subsidiaries is not able for any reason to obtain and provide the information necessary to secure required approvals or that required regulatory approvals are otherwise not available when required, that unexpected geological results are encountered, that completion techniques require further optimization, that production rates do not match the Company’s assumptions, that very low or no production rates are achieved, that the Company will cease to be in compliance with the covenants under its reserves-based loan facility and be required to repay outstanding amounts or that the borrowing base will be reduced pursuant to a borrowing base re-determination and the Company will be required to repay the resulting shortfall, that the Company is unable to access required capital, that funding is not available from the Company’s reserves based loan facility at the times or in the amounts required for planned operations, that occurrences such as those that are assumed will not occur, do in fact occur, and those conditions that are assumed will continue or improve, do not continue or improve and the other risks identified in the Company’s most recent Annual Information Form under the “Risk Factors” section, the Company’s most recent management's discussion and analysis and the Company’s other public disclosure, available under the Company’s profile on SEDAR at www.sedar.com.

With respect to estimated reserves, the evaluation of the Company’s reserves is based on a limited number of wells with limited production history and includes a number of assumptions relating to factors such as availability of capital to fund required infrastructure, commodity prices, production performance of the wells drilled, successful drilling of infill wells, the assumed effects of regulation by government agencies and future capital and operating costs. All of these estimates will vary from actual results. Estimates of the recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, may vary. The Company's actual production, revenues, taxes, development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. In addition to the foregoing, other significant factors or uncertainties that may affect either the Company’s reserves or the future net revenue associated with such reserves include material changes to existing taxation or royalty rates and/or regulations, and changes to environmental laws and regulations.

Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause actual results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking information included in this release is expressly qualified in its entirety by this cautionary statement. Accordingly, readers should not place undue reliance on forward-looking information. The Company undertakes no obligation to update these forward-looking statements, other than as required by applicable law.

About Kolibri Global Energy Inc.

Kolibri Global Energy Inc. is a North American energy company focused on finding and exploiting energy projects in oil, gas, and clean and sustainable energy. 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. The Company's shares are traded on the Toronto Stock Exchange under the stock symbol KEI and on the OTCQX under the stock symbol KGEIF.

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