25. Standardized measurement of oil and gas (unaudited)

The estimates of the Company's proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of December 31, 2021, and 2020 were based on evaluations prepared by McDaniel and Associates Consultants Ltd. ("McDaniel"). The services provided by McDaniel are not audits of the Company's reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to these consolidated financial statements on NI51-101 and included in the Form 40-F (on SEDAR and EDGAR). Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table summarizes the prices utilized in the reserve estimates for 2021 and 2020. Commodity prices utilized for the reserve estimates prior to adjustments for location, grade and quality are as follows:

	As at December 31,		As at December 31,
	2021	2021	2020	2020
	WTI Crude Prices	Henry Hub Prices	WTI Crude Prices	Henry Hub Prices
	Oil, $/bbl	Gas, $/Mmbtu	Oil, $/bbl	Gas, $/Mmbtu
2021	-	-	47.17	2.83
2022	72.83	3.85	50.17	2.87
2023	68.78	3.44	53.17	2.90
2024	66.76	3.17	54.97	2.96
2025	68.09	3.24	56.07	3.02
2026	69.45	3.30	57.19	3.08
2027	70.84	3.37	58.34	3.14
2028	72.26	3.44	59.50	3.20
2029	73.70	3.50	60.69	3.26
2030	75.18	3.58	61.91	3.33
2031	76.68	3.65	63.15	3.39
2032	78.21	3.72	-	-

The Company's total estimated proved reserves at December 31, 2021 were approximately 12.4 MBOE of which 41% was oil and 59% was natural gas and natural gas liquids.

Changes in Proved Reserves:

	Oil		Natural Gas		NGL's
Proved Developed and Undeveloped Reserves:	(Bbls)		(Mcf)		(Bbls)
As of December 31, 2019	5,171,730		8,983,800		1,132,741
Revision of previous estimates	(1,922,397	)	(2,338,096	)	(294,803	)
Purchase of minerals in place
Extension and discoveries	2,099,800		7,610,800		959,623
Sales of minerals in place
Production	(921,933	)	(1,792,104	)	(225,961	)
As of December 31, 2020	4,427,200		12,464,400		1,571,600
Revision of previous estimates	(2,201,254	)	(4,148,838	)	(935,261	)
Purchase of minerals in place
Extension and discoveries	3,620,100		38,835,400		2,971,832
Sales of minerals in place
Production	(729,446	)	(3,436,462	)	(262,971	)
As of December 31, 2021	5,116,600		43,714,500		3,345,200

Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves ("PUD") are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. Such downward revisions would primarily be the result of reserves written off due to the five-year limitation. For the year ended December 31, 2021 and 2020 no such impairments were required.

Summary of Proved Developed and Proved Undeveloped Reserves as of December 31, 2021, 2020 and 2019:

	Oil	Natural Gas	NGL's
	(Bbls)	(Mcf)	(Bbls)
Proved Developed Reserves:
As of December 31, 2019	2,231,550	2,555,500	281,105
As of December 31, 2020	2,124,000	8,634,700	835,500
As of December 31, 2021	2,893,199	10,091,899	1,410,200
Proved Undeveloped Reserves:
As of December 31, 2019	2,940,180	6,428,310	707,114
As of December 31, 2020	2,303,200	3,829,600	735,100
As of December 31, 2021	2,223,401	33,622,601	1,935,000

As at December 31, 2021, the Company reported estimated PUDs of 7.8 MBOE, which accounted for 63% of its total estimated proved oil and gas reserves. This figure primarily consists of 11 gross locations between our Giddings and Hawkville acreage to be drilled in 2022. The cost of these projects would be funded, to the extent possible, from existing cash balances, cash flow from operations, development partnerships and credit facilities.

The following table discloses the Company's progress toward the conversion of PUDs during fiscal 2021.

Progress of Converting Proved Undeveloped Reserves:

	Oil & Natural Gas		Future
	(BOE)		Development Costs
PUDs, beginning of year	3,677		48,879,727
Revision of previous estimates	(294	)	(34,914,091	)
Sales of reserves
Conversion to PD reserves	(1,448	)	(13,965,636	)
Additional PUDs added	7,827		104,500,000
PUDs, end of year	9,762		104,500,000

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2021 and 2020 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing oil and

natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company's share of proved undeveloped properties through December 31, 2022 are $104,500,000.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards.

The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made described below. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

The current reporting rules require that year end reserve calculations and future cash inflows be based on the 3 Consultant Average (McDaniels, GLJ and Sproule) as described by SEDAR and COGEH. The average prices used for fiscal 2021 were $37.42 per bbl of oil and $2.29 per mcf of natural gas. The average prices used for fiscal 2020 were $53.23 per bbl of oil and $1.66 per mcf of natural gas.

The standardized measure of discounted future net cash flows is computed by applying the 3 Consultant Average (McDaniels, GLJ and Sproule) as described by SEDAR and COGEH to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference.

The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties.

The following information is based on the Company's best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2021, and 2020 in accordance with ASC 932, "Extractive Activities - Oil and Gas" which requires the use of a l 0% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company's proved oil and gas reserves.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:

		Year Ended			Year Ended
		December 31, 2021			December 31, 2020
Future cash inflows	$	610,071,000		$	393,698,000
Roylaties		(195,966,000	)		(123,213,000	)
Future production costs and taxes		(113,547,000	)		(84,248,000	)
Future development costs		(85,606,000	)		(48,262,000	)
Future income taxes		(46,525,000	)		(29,990,000	)
Future ADR Costs		(1,972,000	)		(1,355,000	)
Future net cash flows	$	166,426,000		$	106,630,000
Annual 10% discount for estimated timing of cash flows		(55,888,400	)		(22,718,300	)
Standardized measure of discounted future net cash flows	$	110,537,600		$	64,642,800