Exhibit 99.37

FORM 51-101F1 –

STATEMENT OF RESERVES DATA

AND OTHER OIL AND GAS INFORMATION

For the Year Ended December 31, 2022

March 13, 2023

TABLE OF CONTENTS

PART 1: INTRODUCTION		4
PART 2: DISCLOSURE OF RESERVES DATA		5
	2.1 Reserves Data (Forecast Prices and Costs)	5
PART 3: PRICING ASSUMPTIONS		7
	3.1 Forecast Prices Used in Estimates	7
PART 4: RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE		8
	4.1 Reserves Reconciliation	8
PART 5: ADDITIONAL INFORMATION RELATING TO RESERVES DATA		9
	5.1 Undeveloped Reserves	9
	5.2 Significant Factors or Uncertainties	10
	5.3 Future Development Costs	10
PART 6: OTHER OIL AND GAS INFORMATION		11
	6.1 Oil and Gas Properties and Wells	11
	6.2 Properties with No Attributed Reserves	13
	6.3 Forward Contracts	13
	6.4 Tax Horizon	13
	6.5 Costs Incurred	14
	6.6 Exploration and Development Activities	14
	6.7 Production Estimates	15
	6.8 Production History	15
PART 7: NOTES		16

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GLOSSARY OF TERMS

“AIF” refers to the Company’s Annual Information Form filed on SEDAR;

“AIT” stands for ‘After Income Taxes’;

“BIT” stands for ‘Before Income Taxes’;

“Company” or “KEI” means Kolibri Global Energy Inc.;

“NSAI” means Netherland, Sewell & Associates, Inc., independent petroleum engineering consultants of Houston, Texas, U.S.;

“NI 51-101” refers to National Instrument 51-101; and

“Woodford Sale” means the sale by BNK US of its Tishomingo field assets, excluding the Caney and Upper Sycamore formations, the completion of which was announced by the Company on April 21, 2013.

Abbreviations

Bbl	Barrel
Bbls	Barrels
Bcfe	Billion cubic feet of gas equivalent
Boe	Barrels of oil equivalent (converted at 6 Mcf to 1 Boe)
Bopd	Barrels of oil per day
Mbbls	Thousand barrels
MMboe	Millions of barrels of oil equivalent
Mcf	Thousand cubic feet
MMcf	Million cubic feet
Mcf/d	Thousand cubic feet per day
Bcf	Billion cubic feet

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PART 1: INTRODUCTION

The effective date of the information being provided in this statement is December 31, 2022. The preparation date of the information being provided in this statement is March 13, 2023. For a glossary of terminology and definitions relating to the information included within this statement (including the aforementioned dates), readers are referred to NI 51-101.

Reserves and Future Net Revenue

The following is a summary of the oil and natural gas reserves and the net present values of future net revenue of Kolibri Global Energy Inc.’s wholly owned subsidiary BNK Petroleum (U.S.) Inc. as evaluated by NSAI. The Company’s only property with assigned reserves and gathering revenue is the Tishomingo field in Oklahoma, U.S. NSAI is an independent qualified reserves evaluator appointed by the Company pursuant to NI 51-101. Readers should note that totals in the following tables may not add due to rounding.

The estimated future net revenue figures contained in the following tables do not necessarily represent the fair market value of the Company’s reserves. There is no assurance that the forecast prices and cost assumptions used by NSAI in its report to the Company will be attained and variances could be material. NSAI’s report to the Company contained additional assumptions relating to costs and other matters. The recovery and reserves estimates attributed to the Company’s properties described herein are estimates only. The actual reserves attributed to the Company’s properties may be greater or less than those calculated.

All dollar values are expressed in U.S. dollars, unless otherwise indicated.

Cautionary Statements

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.

BOEs may be misleading, particularly if used in isolation. A boe conversion ratio of six mcf to one barrel is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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PART 2: DISCLOSURE OF RESERVES DATA

2.1 Reserves Data (Forecast Prices and Costs)

	United States
	Tight Oil				Shale Gas				Natural Gas Liquids
Reserve Category	KEI Gross (Mbbl)		Net (Mbbl)		KEI Gross (MMcf)		Net (MMcf)		KEI Gross (Mbbl)		Net (Mbbl)
Proved
Developed Producing		4,364		3,425		4,165		3,269		874		686
Undeveloped		20,584		16,212		18,190		14,253		3,795		2,973
Total Proved		24,948		19,637		22,355		17,522		4,668		3,659
Probable		14,547		11,532		17,221		13,683		3,593		2,855
Total Proved Plus Probable		39,495		31,169		39,576		31,205		8,261		6,514
Possible		16,906		13,559		16,597		13,245		3,462		2,763
Total Proved Plus Probable Plus Possible		56,401		44,728		56,173		44,450		11,724		9,277

Notes: May not add due to rounding. The Company’s reserves are derived from non-conventional oil and gas activities. The Company’s reserves are contained in a shale oil reservoir from which gas and natural gas liquids are produced as by-products.

Summary of Oil & Gas Reserves
As of December 31, 2022
Forecast Prices & Costs
	Reserves Total
Reserve Category	KEI Gross (MBOE)		Net (MBOE)
Proved
Developed Producing		5,932		4,656
Undeveloped		27,411		21,561
Total Proved		33,342		26,216
Probable		21,010		16,668
Total Proved Plus Probable		54,352		42,884
Possible		23,134		18,530
Total Proved Plus Probable Plus Possible		77,487		61,413

Note: May not add due to rounding. Boe basis: 6 Mcf to 1 Bbl

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Net Present Value of Future Net Revenue
As of December 31, 2022
Forecast Prices & Costs
	Net Present Value of Future Net Revenue ($ millions)
	Before Income Tax											After Income Tax
Reserve Category		0	%	5	%	10	%	15	%	20	%		0	%	5	%	10	%	15	%	20	%
United States
Proved
Developed Producing		262.8		187.3		147.9		124.1		108.3			262.8		187.3		147.9		124.1		108.3
Undeveloped		933.1		556.1		366.9		257.0		186.3			657.8		420.6		280.8		194.2		137.4
Total Proved		1,195.9		743.4		514.8		381.1		294.7			920.6		607.9		428.7		318.3		245.7
Probable		797.4		377.6		209.6		127.3		81.1			587.5		303.2		169.8		101.7		64.0
Total Proved Plus Probable		1,993.3		1,121.0		724.4		508.4		375.8			1,508.1		911.1		598.5		420.0		309.7
Possible		1,104.2		435.8		214.8		119.7		71.6			813.6		355.4		171.5		90.3		51.0
Total Proved Plus Probable plus Possible		3,097.5		1,556.8		939.2		628.1		447.4			2,321.7		1,266.5		770.0		510.3		360.7

Notes: May not add due to rounding. The after income tax net present values presented in the preceding table take into account available non-operating tax losses of $150.0 million and reflect the tax burden on the Company’s Tishomingo Field interests on a standalone basis, do not consider the business-entity-level tax situation or tax planning and do not provide an estimate of the value at the level of the business entity, which may be significantly different. The financial statements and the management’s discussion and analysis (MD&A) of the Company should be consulted for information at the level of the business entity.

Total Future Net Revenue (Undiscounted - by Reserve Category)
As of December 31, 2022
Forecast Prices & Costs ($ millions)
Reserve Category	Company Gross Revenue		Royalties		Operating Expenses		Severance Taxes		Develop. Costs		Abandonment & Reclamation Costs		Future Net Revenue BIT		Income Taxes		Future Net Revenue AIT
Total Proved		2,610.1		556.3		340.5		131.7		381.1		4.5		1,195.9		275.3		920.6
Total Proved Plus Probable		4,347.3		916.4		599.3		222.2		609.0		7.1		1,993.3		485.2		1,508.1
Total Proved Plus Probable Plus Possible		6,498.1		1,344.7		887.4		337.3		821.3		9.9		3,097.5		775.8		2,321.7

Total Future Net Revenue (NPV discounted 10%, BIT by Reserve Category)
As of December 31, 2022
Forecast Prices & Costs
	Tishomingo Field - Tight Oil, NGL & Shale Gas
Reserve Category	$ millions		Unit Value ($/boe)
Total Proved		514.8		19.6
Total Proved Plus Probable		724.4		16.9
Total Proved Plus Probable Plus Possible		939.2		15.3

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PART 3: PRICING ASSUMPTIONS

3.1 Forecast Prices Used in Estimates

Forecast benchmark reference product price and inflation rate assumptions are summarized below. These forecast assumptions with adjustments were provided in the NSAI report.

Summary of Pricing & Inflation Rate Assumptions
As of December 31, 2022
Forecast Prices & Costs
			United States
Year	WTI*		Henry Hub*		NGL		Inflation Rate
	US$/bbl		US$/MMbtu		US$/bbl		%
2023		86.00		5.00		30.96
2024		84.00		4.50		30.24
2025		80.00		4.25		28.80
2026		81.60		4.34		29.38
2027		83.23		4.42		29.96
2028		84.90		4.51		30.56
2029		86.59		4.60		31.17
2030		88.33		4.69		31.80
2031		90.09		4.79		32.43
2032		91.89		4.88		33.08
								2.0

Note: Sproule Oil & Natural Gas Forecast from NSAI Report to the Company including adjustments for differentials; prices escalated @ 2% after 2032.

2022 weighted average prices were: $94.46 for oil, $7.12 for natural gas and $34.88 for NGLs.

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PART 4: RECONCILIATIONS OF CHANGES IN RESERVES AND FUTURE NET REVENUE

4.1 Reserves Reconciliation

A reconciliation of changes to the Company’s gross (before deduction of royalties) proved, probable and proved plus probable reserves is provided below. This reconciliation reflects changes to the Company’s reserves estimated using forecast prices and costs.

	United States
	Tight Oil								Shale Gas									Natural Gas Liquids
	Proved			Probable		Proved + Probable			Proved			Probable			Proved + Probable			Proved			Probable			Proved + Probable
	(Mbbl)			(Mbbl)		(Mbbl)			(MMcf)			(MMcf)			(MMcf)			(Mbbl)			(Mbbl)			(Mbbl)
31-Dec-21		24,514.8			12,691.0		37,205.8			25,803.1			17,536.2			43,339.3			5,273.8			3,581.3			8,855.0
Extensions		558.5			827.9		1,386.5			355.7			545.7			901.3			74.2			113.8			188.0
Improved Recovery		-			-		-			-			-			-			-			-			-
Technical Revisions		327.7			1,028.0		1,355.6			(3,404.5	)		(861.1	)		(4,265.4	)		(598.7	)		(102.3	)		(701.0	)
Discoveries		-			-		-			-			-			-			-			-			-
Acquisitions		-			-		-			-			-			-			-			-			-
Dispositions		-			-		-			-			-			-			-			-			-
Economic Factors		-			-		-			-			-			-			-			-			-
Production		(453.0	)		-		(453.0	)		(399.4	)		-			(399.4	)		(81.1	)		-			(81.1	)
31-Dec-22		24,948.1			14,546.9		39,495.0			22,354.9			17,220.8			39,575.8			4,668.2			3,592.8			8,260.9

Note: May not add due to rounding. Boe basis: 6 Mcf to 1 Bbl. Changes under “Technical Revisions” include all changes due to revisions in forecast parameters associated with all wells.

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PART 5: ADDITIONAL INFORMATION RELATING TO RESERVES DATA

5.1 Undeveloped Reserves

The Company’s undeveloped reserves exist in the Caney shale of its interests in the Tishomingo Field in Oklahoma, U.S. Most of these reserves are designated within the undeveloped category because significant capital expenditures will be required in order to render these reserves capable of production.

The following tables disclose the proved undeveloped and probable undeveloped reserves from the Company’s current net interest in the Tishomingo Field that were first attributed in each of the most recent three financial years:

	Oil (Mbbl)				Natural Gas MMcf				NGL
Proved Undeveloped Reserves	First Attributed		Booked at Year End		First Attributed		Booked at Year End		First Attributed		Booked at Year End
12/31/2020		48.2		16,881.1		466.3		16,955.3		0.0		3,418.5
12/31/2021		585.5		17,466.1		748.7		17,704.0		196.7		3,615.2
12/31/2022		0.0		16,212.4		485.7		14,252.9		179.4		2,973.4

	Oil (Mbbl)				Natural Gas MMcf				NGL
Probable Undeveloped Reserves	First Attributed		Booked at Year End		First Attributed		Booked at Year End		First Attributed		Booked at Year End
12/31/2020		0.0		9,937.2		305.7		14,216.9		0.0		2,866.4
12/31/2021		147.5		10,084.7		0.0		13,955.3		0.0		2,849.7
12/31/2022		929.6		11,014.3		0.0		13,147.7		0.0		2,742.7

Plans for future development of these undeveloped reserves (based on Forecast Prices and Costs) are summarized below:

United States of America Properties

Tishomingo Field, Oklahoma

NSAI assigns 27,410.3 Mboe (Company Gross Working Interest share) Proved Undeveloped and 21,009.8 Mboe (Company Gross Working Interest share) Probable Undeveloped reserves to the Tishomingo Field. The Proved Undeveloped reserves are forecast to be recoverable from the drilling of 11 wells in 2023 and 27, 19 and 5 wells in 2024, 2025 and 2026 respectively (10.92, 26.77, 13.07 and 1.2 net KEI wells). The Probable Undeveloped reserves are forecast to be recoverable from the drilling of 9 wells in 2025, 30 wells in 2026, 15 wells in 2027 and 7 in 2028 respectively (7.67, 15.77, 4.12 and 2.33 net KEI wells).

The production forecast is based on producing the existing wells and drilling the additional wells as listed above and applying the historical production behavior to the undeveloped well locations.

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5.2 Significant Factors or Uncertainties

Estimates of economically recoverable oil and natural gas reserves (including natural gas liquids) and the future net cash flows therefrom are based upon a number of variable factors and assumptions, 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, will 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. Estimates of after-tax net present value are dependent on a number of factors including utilization of tax-loss carry forwards. 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.

Information on other important economic factors or significant uncertainties that may affect components of the reserves data and other oil and gas information contained in this Form 51-101F1 are contained in the Company’s Management Discussion and Analysis filed under the Company’s profile at www.SEDAR.com and in the AIF under “Risk Factors”.

5.3 Future Development Costs

A summary of the estimated development costs deducted in the estimation of future net revenue attributable to various reserves categories and prepared under various price and cost assumptions are summarized in the following table. The Company expects to fund its estimated future development costs through some combination of internally generated cash flow and debt or equity financing. There can be no guarantee that funds will be available when required to proceed with the development on the schedule contemplated herein or that the Board of Directors of the Company will allocate funding to develop all of the reserves requiring development. Failure to develop such reserves could negatively impact future net revenue.

Summary of Estimated Development Costs Attributed to Reserves
Forecast Prices & Costs
	Estimated Development Costs ($ millions)
	Total Proved		Total Proved + Probable
United States
2023		107.0		107.0
2024		199.4		199.4
2025		65.5		145.3
2026		9.2		109.3
2027+		-		48.0
Total		381.1		609.0

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PART 6: OTHER OIL AND GAS INFORMATION

6.1 Oil and Gas Properties and Wells

The following discussion outlines the Company’s important properties, plants, facilities and installations:

United States

Tishomingo Field, Ardmore Basin, Oklahoma

In Oklahoma, the Company holds approximately 17,171 net acres of Caney shale acreage in the Tishomingo Field near Ardmore, OK. The Company sold all of its Woodford shale rights in the Tishomingo Field in April 2013 and commenced the exploration phase to develop the oily Caney shale. A subsequent transaction in 2015 resulted in the Company obtaining a 4.9% working interest in one section and participating in four Woodford shale horizontal wells which were completed in 2016. The Company plans additional development drilling in this field with the objective of increasing production and reserves.

In 2013, the Company drilled 5 Caney horizontal wells to increase its reserves, oil production and to better understand the Caney formation. By December 31, 2013, the 5 wells were fracture stimulated with 4 wells on production. The 5^th well began production in early January 2014. The Company’s exit production from the Tishomingo Field at December 31, 2013 was approximately 1,040 boepd. KEI’s 2013-year end proved reserves, with an effective date of 12/31/13 were 4 million boe.

In 2014, the Company drilled 5 Caney horizontal wells, fracture stimulated 3 of them, fracture stimulated one third of another well and completed the stimulation of one well that had been drilled in 2013 that had not been fully stimulated. The remaining wellbores were stimulated in 2015. The Company’s exit production rate from the field was approximately 1,400 boepd, which did not include one well that began producing oil in early January 2015. KEI’s 2014 year end proved reserves, with an effective date of 12/31/14 in the Tishomingo Field increased to an estimated 12 million boe.

As noted above, in 2015 the Company completed 2 Caney horizontal wells that had been drilled in 2014. Due to the drastic drop in the price of oil the Company did not drill any additional wells in 2015. The Company averaged 1,367 boepd in the fourth quarter of 2015. KEI’s 2015 year end proved reserves in the Tishomingo Field, with an effective date of 12/31/15 increased to 17.7 million boe compared to the December 31, 2014 estimate, primarily due to upgrading into the proved and probable categories.

Due to the continued low oil prices through 2016, the Company did not complete any wells in 2016. KEI’s 2016 year end proved reserves in the Tishomingo Field increased to 18 million boe, primarily due to technical revisions as a result of the existing wells performing above previous forecasts. Company production averaged 1,045 BOEPD in 2016.

The Company’s 2017 drilling program, consisted of 3 horizontal Caney wells, two of which were drilled to the east of KEI’s previous Caney wells. These wells were successfully drilled under-budget and demonstrated solid operational execution and extended the play to the east. Fracture stimulation programs were modified and much higher proppant placement was achieved. KEI’s 2017 year end proved reserves increased by 40% to 25.2 million boe primarily due to probable and possible locations being converted to proved locations. KEI’s 2017 year end proved and probable reserves increased by 13% to 47.6 million boe. Average production for the year was 1,092 BOEPD since two of the wells came on late in the year. KEI’s 4^th quarter average production was 1,539 BOEPD.

In 2018 the Company drilled and participated in 4 horizontal Caney wells, 3 of them were operated by the Company. The remaining well was a 2-mile lateral, operated by a major oil company, who had the right to be the operator for that section. All the wells were successfully drilled on and or under budget. KEI’s 2018 year end proved reserves increased by 26% to 33.8 million boe primarily due to the new wells being drilled. KEI’s 2018 year end proved and probable reserves increased by 11% to 53.3 million boe. Both the proved and probable reserve increases are primarily a result of the new wells converting probable and possible reserve locations to the proven and probable categories. The proved reserves are estimated to be 76% oil, with the balance being shale gas and natural gas liquids. Average production for the year was 1,662 BOEPD.

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In 2019 the Company did not drill any wells, but there was one well that was listed as PDNP at the end of 2018 that was brought on production, and KEI completed a few workovers to cleanout wellbores. KEI’s 2019 year-end proved reserves were down by 1% to 33.4 million boe. KEI’s 2019-year end proved and probable reserves, decreased by 1% to 52.6 million boe. There was no significant change to the proved, nor probable reserves since KEI did not drill any wells in 2019. The small change is attributed to the existing wells having had low decline rates matching previous assumptions. Average production was 1,379 BOEPD.

In 2020, due to the ultra low oil prices during COVID the Company did not drill any wells. KEI’s 2020 year-end proved reserves were down by 1% to 33.1 million boe. KEI’s 2020 year-end proved and probable reserves, decreased by 1% to 52.2 million boe. There was no significant change to the proved, nor probable reserves since KEI did not drill any wells in 2020. The small change is attributed to the existing wells having had low decline rate matching previous assumptions. Average production was 1,151 BOEPD.

In 2021, the Company did not drill any wells. KEI’s 2021 year end proved reserves were up by 3% to 34.1 million boe. KEI’s 2021 year-end proved and probable reserves, increased by 2% to 53.3 million boe. The small change to both the proved reserves and probable reserves is attributed to the existing wells performing well and due to longer anticipated life of wells due to higher forecast pricing, over last year’s extremely low pricing. Average production was 975 BOEPD.

In 2022, the Company drilled five wells. KEI’s 2022 year end proved reserves were down by 2% to 33.3 million boe, while the proved reserves of oil increased by 2% to 25.0 million barrels. KEI’s 2022 year-end proved and probable reserves increased by 2% to 54.4 million boe, while the proved reserves of oil increased by 6% to39.5 million barrels. The small change is due to the production in 2022 offset by proved and probable reserve additions, plus the percentage of oil increasing from 72 percent to 75 percent in the proved category and increasing from 70 percent to 73 percent in the proved plus probable category.

Oil & Gas Properties Associated with Reserves

As of December 31, 2022

Acreage

Developed

Undeveloped

Total

Plants, Facilities & Installation

Properties

Location

Gross

Net

Gross

Net

Gross

Net

United States

Tishomingo

Oklahoma, U.S.

25,652

17,101

2,560

70

28,212

17,171

Total

25,652

17,101

2,560

70

28,212

17,171

Oil & Gas Properties Associated with Reserves

As of December 31, 2022

United States

Tight Oil

Shale Gas

Natural Gas Liquids

Total

Gross

Net

Gross

Net

Gross

Net

Suspended (1)

Service (2)

Gross

Net

Oklahoma Producing

23

21.2

4.0

0.2

27

21.4

Oklahoma Non-Producing

Total

23

21.2

4.0

0.2

27

21.4

(1) Suspended wells may be capable of production but which, for a variety of reasons, including, but not limited to lack of markets or development are not placed on production at the present time. (2) Service wells are used for the disposal or injection of water or other in-field service operations related to oil and gas product.

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6.2 Properties with No Attributed Reserves

The Company’s unproved properties, including those for which the Company expects its rights to explore, develop and exploit to expire within one year, are outlined in the following table.

Properties with no Attributed Reserves
As of December 31, 2022
		Undeveloped Acreage (Acres)				Company Interest		Work Commitments (existence, nature, timing & cost)
Properties	Location	Gross		Net		(%)
United States
McIntosh County	McIntosh County, OK		4,480		67		3	Held by production with small interests spread over numerous sections.
Total			4,480		67		3

6.3 Forward Contracts

The Company is not bound by any agreements which may impact the realization of future full market prices for its oil and gas production as described in this report, other than the financial commodity contracts listed below.

		Total Volume Hedged		Price
Commodity	Period	(BBLS)		($/BBL)
Oil – WTI Swap	January 1, 2023 to May 31, 2023		45,000	$	56.02
Oil – WTI Swap	January 3, 2023 to December 31, 2023		36,000	$	90.45
Oil – WTI Costless Collars	January 3, 2023 to December 29, 2023		48,000	$	70.00 - $94.00
Oil – WTI Swap	June 1, 2023 to December 31, 2023		63,000	$	64.90
Oil – WTI Swap	January 1, 2024 to May 31, 2024		40,000	$	62.77
Oil – WTI Costless Collars	January 2, 2024 to June 28, 2024		6,000	$	65.00 - $79.50
Oil – WTI Costless Collars	January 2, 2024 to June 28, 2024		24,000	$	65.00 - $86.00
Oil – WTI Costless Collars	June 3, 2024 to June 28, 2024		8,000	$	60.00 - $78.15
Oil – WTI Costless Collars	July 1, 2024 to September 30, 2024		21,000	$	60.00 - $86.65
Oil – WTI Costless Collars	July 1, 2024 to September 30, 2024		18,000	$	60.00 - $78.00

The Company has no transportation obligations or commitments for future deliveries which exceed its expected related future production from proved reserves, as estimated using forecast prices and costs.

6.4 Tax Horizon

The Company does not expect to be required to pay income taxes in the immediate foreseeable future.

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6.5 Costs Incurred

For the year ended December 31, 2022, the Company incurred costs related to its acquisition, exploration and development activities as outlined in the following table.

	Cost Incurred ($ millions)
	United States
Property Acquisition Costs
Proved Properties		Nil
Unproved Properties/Wells		Nil
Exploration Costs		Nil
Development Costs*		37.1

* Includes $1.8 million of costs incurred in 2022 for wells that will be drilled in 2023.

6.6 Exploration and Development Activities

The Company’s drilling activity and results for the year ended December 31, 2022, are summarized in the following table. It should be noted that the data outlined in this table reflects those wells that the Company participated in and where the rig was released during the period.

	Exploratory Wells				Development Wells
	Gross		Net		Gross		Net
United States
Oil Wells		0.0		0.0		5.0		4.97
Gas Wells		0.0		0.0		0.0		0.0
Service Wells		0.0		0.0		0.0		0.0
Stratigraphic Test Wells		0.0		0.0		0.0		0.0
Dry Holes		0.0		0.0		0.0		0.0
Total Wells		0.0		0.0		5.0		4.97

The Company’s exploration and development activities are summarized as follows:

United States

During fiscal year 2022 KEI drilled 5 wells in its Tishomingo Field. The Company plans additional development drilling in the Tishomingo Field, OK with the objective of increasing production and reserves.

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6.7 Production Estimates

Estimated production volumes (before Royalties) derived from the first year (2022) of the cash flow forecasts prepared in conjunction with the Company’s reserves data included in the NSAI Report are provided in the following table.

Summary of Production Estimates
Proved + Probable Reserves Case
For Year 2023
	United States
	Tight Oil		Shale Gas		Natural Gas Liquids		Company Total
Reserve Category	(Mbbl)		(MMcf)		(Mbbl)		(Mboe)
United States
Tishomingo, OK		1,203.5		900.4		187.8		1,541.4
Total		1,203.5		900.4		187.8		1,541.4

(1) Significant fields represent greater than 20% of Company total (by country) of production in the first year of forecast

6.8 Production History

The Company’s historical production and netback data for period ended December 31, 2022 is presented below.

Summary of 2022 Company Share of Production & Netbacks
	United States
	Q1			Q2			Q3			Q4			Total Year
Company share of daily production before deduction of royalties
Shale Gas (Mcf/d)		922			1,271			1,083			969			1,061
Tight Oil (bopd)		714			1,439			1,252			1,551			1,241
NGLs (bopd)		186			277			269			155			222
Average ($/bbl or $/mcf)
Price received ($/boe)		74.97			92.02			80.89			72.47			80.82
Royalties paid		(16.50	)		(21.19	)		(17.96	)		(15.83	)		(18.07	)
Production costs		(9.56	)		(7.77	)		(7.77	)		(8.25	)		(8.19	)
Netback from operations		48.91			63.06			55.16			48.39			54.56
Price adjustment from commodity contracts		(12.03	)		(9.40	)		(5.47	)		(2.34	)		(6.77	)
Netback after adjustments		36.88			53.66			49.69			46.05			47.79
Total Production (mboe before deductions of royalties)		94.9			175.4			156.5			171.8			598.6

Boe basis: 6 Mcf to 1 Bbl

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PART 7: NOTES

The following definitions and guidelines are contained in Section 5.4 of Volume 1 of the Canadian Oil and Gas Evaluation Handbook (Second Edition, September 1, 2007) prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society) (the “COGE Handbook”) and have been prepared by the Standing Committee on Reserves Definitions of the CIM (Petroleum Society). Readers should consult the COGE Handbook for additional explanation and guidance. Certain other terms used in this Listing Application have the meanings assigned to them in NI 51-101 and accompanying Companion Policy 51-101 CP, adopted by the Canadian securities regulatory authorities.

Gross

(a) In relation to the Company’s interest in production or reserves, its “company gross reserves”, which are the Company’s working interest (operating or non-operating) share before deduction of royalties and without including any royalty interest of the Company.

(b) In relation to wells, the total number of wells in which the Company has an interest.

(c) In relation to properties, the total area of properties in which the Company has an interest.

Net

(a) In relation to the Company’s interest in production or reserves, the Company’s working interest (operating and non-operating) share after deduction of royalty obligations, plus the Company’s royalty interests in production or reserves.

(b) In relation to the Company’s interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company.

The following definitions apply to both estimates of individual reserves entities and the aggregate of reserves for multiple entities:

Reserve Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations from a given date forward, based on:

■ Analysis of drilling, geological, geophysical and engineering data;

■ The use of established technology; and

■ Specified economic conditions

Reserves are classified according to the degree of certainty associated with the estimates:

(a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

(b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Development and Production Status

Each of the reserve categories (proved and probable) may be divided into developed and undeveloped categories:

(a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

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(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

(ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

■ At least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

■ At least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Forecast prices and costs

Future prices and costs that are:

(a) Generally accepted as being a reasonable outlook of the future; and

(b) If, and only to the extent that, there are fixed or presently determinable future prices or costs to which the Company is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in paragraph (a).

The forecast summary pricing table identifies benchmark reference pricing that apply to the Company.

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