Leucrotta Exploration Inc.: Leucrotta Exploration Announces 2021 Year-End Reserves

Calgary, Alberta--(Newsfile Corp. - March 16, 2022) - Leucrotta Exploration Inc. (TSXV: LXE) ("Leucrotta" or the "Company") is pleased to announce its 2021 year-end reserves as independently evaluated by GLJ Ltd. ("GLJ") effective December 31, 2021 (the "GLJ Report"), in accordance with National Instrument 51-101 ("NI 51-101") and the Canadian Oil and Gas Evaluation ("COGE") Handbook. All dollar figures are Canadian dollars unless otherwise noted.

Introduction

During 2021, Leucrotta made the strategic decision to sell its Doe property for gross proceeds of $30.0 million, raise additional equity capital for gross proceeds of $34.4 million and start the PAD development of its Mica Project. Based on successful results of its first PAD and the significant delineation already completed, Leucrotta was able to deliver strong year over year reserve growth despite the sale of Doe that had 10.7 million boe (86% undeveloped) of Proved plus Probable reserves booked to the property.

The GLJ Report incorporates Leucrotta's initial move to 2,400 metre lateral lengths and increased frac intensity used on the Mica Test PAD. The report includes 14 producing wells and 26 undeveloped locations in the Lower Montney that only cover less than 10% of Leucrotta's large contiguous land base that is greater than 250 sections of Montney rights. These minimal reserve bookings leave material upside for Leucrotta to potentially book additional reserves in the future.

Leucrotta has also delineated and proven the Upper and Basal Montney productive on its land base including 2 wells in each zone but has only booked 4 Upper locations and no Basal locations leaving reserve upside of greater than 99% of its land base for these zones. The presence of stacked zones on the property will materially reduce the environmental footprint per well and enhance economics.

Leucrotta has estimated approximately 18 billion barrels of Original Oil in Place ("OOIP") and 17 trillion cubic feet of Original Gas in Place ("OGIP") over its land base. Leucrotta's business plan is to continue to develop the property, establish the ultimate reserve recoveries and move the established recoverable resource from land to its Proved plus Probable reserve base and eventually to its Producing reserve base. With regard to this, Leucrotta has made significant strides in 2021 as noted below.

Reserve Highlights

Leucrotta is pleased to report material reserve and value increases notwithstanding the sale of the Doe property that had 10.7 million boe booked as noted above:

• Increased Proved Producing reserves by 71% to 7.7 million boe from 4.5 million boe
• Increased Total Proved reserves by 43% to 21.1 million boe from 14.8 million boe
• Increased Total Proved plus Probable reserves by 16% to 50.7 million boe from 43.6 million boe
• Increased Proved Producing value by 241% to $111.2 million from $32.6 million
• Increased Total Proved Reserve value by 185% to $167.8 from $58.8 million
• Increased Total Proved plus Probable Reserve value by 143% to $393.9 million from $161.9 million
• Doubled Net Asset Value to $528.2 million from $267.0 million (Per Share increase of 60% to $2.13 per Share)

Reserves Summary

Leucrotta's December 31, 2021 reserves as prepared by GLJ effective December 31, 2021 and based on the GLJ (2022-01) future price forecast are as follows ^(1,4):

Working Interest Reserves (2)	Tight Oil (Mbbl)	Shale Natural Gas (Mmcf)	NGLs (Mbbl)	Total Oil Equivalent (Mboe) (3)
Proved
Producing	1,325	36,439	276	7,674
Developed non-producing	123	5,796	77	1,166
Undeveloped	2,115	52,339	1,422	12,260
Total proved	3,563	94,574	1,774	21,100
Probable	4,474	135,953	2,418	29,550
Total proved & probable	8,037	230,527	4,192	50,650

Notes:

1. Numbers may not add due to rounding.
2. "Working Interest" or "Gross" reserves means Leucrotta's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Leucrotta.
3. Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.
4. Disclosure of Net reserves will be included in Company's AIF to be filed on SEDAR at www.sedar.com on or before April 30, 2022. "Net" reserves means Leucrotta's working interest (operated and non-operated) share after deduction of royalties, plus Leucrotta's royalty interest in reserves.

Reserves Values

The estimated future net revenues before taxes associated with Leucrotta's reserves effective December 31, 2021 and based on the GLJ (2022-01) future price forecast are summarized in the following table ^(1,2,3,4):

	Discount factor per year
($000s)	0%	5%	10%	15%	20%
Proved
Producing	165,688	132,580	111,185	96,547	85,991
Developed Non-producing	22,615	17,422	14,212	12,086	10,585
Undeveloped	145,131	79,348	42,394	19,974	5,487
Total proved	333,433	229,350	167,791	128,607	102,063
Probable	595,344	346,832	226,069	158,652	116,869
Total proved & probable	928,777	576,182	393,860	287,260	218,932

Notes:

1. Numbers may not add due to rounding.
2. The estimated future net revenues are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures.
3. The estimated future net revenue contained in the table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated.
4. The after-tax present values of future net revenue attributed to Leucrotta's reserves will be included in Company's AIF to be filed on SEDAR at www.sedar.com on or before April 30, 2022.

Price Forecast

The GLJ (2022-01) price forecast is as follows:

Year	WTI Oil @ Cushing ($US / Bbl)	Edmonton Light Oil ($Cdn / Bbl)	AECO Natural Gas ($Cdn / Mmbtu)	Chicago Natural Gas ($US / Mmbtu)	Foreign Exchange (US$/Cdn$)
2022	73.00	87.97	3.40	3.65	0.790
2023	69.01	81.89	3.10	3.35	0.790
2024	67.24	79.32	3.15	3.00	0.790
2025	68.58	80.91	3.21	3.06	0.790
2026	69.96	82.53	3.28	3.13	0.790
2027	71.35	84.18	3.34	3.19	0.790
2028	72.78	85.86	3.41	3.26	0.790
2029	74.24	87.58	3.48	3.33	0.790
2030	75.72	89.32	3.55	3.40	0.790
2031	77.24	91.11	3.62	3.47	0.790
Escalate thereafter (1)	2.0% per year	2.0% per year	2.0% per year	2.0% per year

Note:

1. Escalated at two per cent per year starting in 2032 in the January 1, 2022 GLJ price forecast with the exception of foreign exchange, which remains flat.

Net Asset Value ("NAV")

Leucrotta's NAV as at December 31, 2021 and based on the GLJ (2022-01) future price forecast is as follows:

($000s, except per share amounts)
	Pre-tax net present value ("NPV") of proved & probable reserves discounted at 10%		393,860
	Undeveloped land (1)		104,000
	Working capital		30,315
	Net asset value		528,175
	Shares outstanding (basic)		247,822
	Net asset value per share		$ 2.13

Note:

1. Undeveloped land is included at cost of approximately $665 per acre.

Reserve Life Index ("RLI")

Leucrotta's RLI presented below is based on estimated Q4 2021 average production of 3,290 boe per day.

Reserve Category	RLI
Proved plus Probable Reserves	41.8
Proved Reserves	17.4

Reserves Reconciliation

The following summary reconciliation of Leucrotta's working interest reserves compares changes in the Company's reserves as at December 31, 2021 to the reserves as at December 31, 2020 based on the based on the GLJ (2022-01) future price forecast ^(1,2) :

	Total Proved			Tight Oil			Shale Natural Gas			NGLs			Total Oil Equivalent
				(Mbbl)			(Mmcf)			(Mbbl)			(Mboe) (3)
	Opening balance			1,268			71,352			1,632			14,791
	Extensions and improved recovery			984			16,966			271			4,083
	Technical revisions			1,476			28,584			662			6,902
	Dispositions			-			(18,847	)		(755	)		(3,896	)
	Economic factors			8			682			10			131
	Production			(173	)		(4,162	)		(45	)		(912	)
	Closing balance			3,563			94,574			1,774			21,100
	Proved plus Probable			Tight Oil			Shale Natural Gas			NGLs			Total Oil Equivalent
				(Mbbl)			(Mmcf)			(Mbbl)			(Mboe) (3)
	Opening balance			4,418			206,360			4,752			43,563
	Extensions and improved recovery			366			6,046			90			1,464
	Technical revisions			3,362			71,062			1,459			16,664
	Dispositions			-			(51,572	)		(2,113	)		(10,708	)
	Economic factors			63			2,794			49			578
	Production			(173	)		(4,162	)		(45	)		(912	)
	Closing balance			8,037			230,527			4,192			50,650

Notes:

1. Numbers may not add due to rounding.
2. "Working Interest" or "Gross" reserves means Leucrotta's working interest (operating and non-operating) share before deduction of royalties and without including any royalty interest of Leucrotta.
3. Oil equivalent amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil.

Finding and Development Costs ("F&D") and Finding, Development and Acquisition Costs ("FD&A")

Leucrotta has presented FD&A and F&D costs below:

				2021						2020						3 Year Cumulative
							Proved &						Proved &						Proved &
($000's, except where noted)				Proved			Probable			Proved			Probable			Proved			Probable
F&D costs (excluding net acquisitions/dispositions)
	Exploration and development expenditures			38,251			38,251			12,601			12,601			63,409			63,409
	Change in FDC(1)			48,599			20,112			(44,713	)		(97,021	)		(10,629	)		(82,113	)
F&D costs excluding net acquisitions/dispositions (Including FDC)				86,850			58,363			(32,112	)		(84,420	)		52,780			(18,704	)
FD&A costs (including net acquisitions/dispositions)
	Exploration and development expenditures			38,251			38,251			12,601			12,601			63,409			63,409
	Net acquisitions (dispositions)			(28,584	)		(28,584	)		(7,091	)		(7,091	)		(38,002	)		(38,002	)
	FD&A costs including net acquisitions/dispositions			9,667			9,667			5,510			5,510			25,407			25,407
	Change in FDC			48,599			20,112			(44,713	)		(97,021	)		(10,629	)		(82,113	)
FD&A costs including net acquisitions/dispositions (Including FDC)				58,266			29,779			(39,203	)		(91,511	)		14,778			(56,706	)
Reserve Additions (Mboe) (2)
	Exploration and development			11,117			18,707			(5,236	)		(16,337	)		7,350			5,388
	Net acquisitions/dispositions			(3,896	)		(10,708	)		-			-			(3,896	)		(10,708	)
Total Reserve Additions				7,221			7,999			(5,236	)		(16,337	)		3,454			(5,320	)
F&D costs excluding net acquisitions/dispositions ($/boe)
	Excluding FDC			3.44			2.04			(2.41	)		(0.77	)		8.63			11.77
	Including FDC			7.81			3.12			6.13			5.17			7.18			(3.47	)
FD&A costs ($/boe)
	Excluding FDC			1.34			1.21			(1.05	)		(0.34	)		7.36			(4.78	)
	Including FDC			8.07			3.72			7.49			5.60			4.28			10.66

Notes:

1. Future development capital ("FDC") expenditures required to recover reserves estimated by GLJ. The aggregate of the exploration and development costs incurred in the most recent financial period and the change during that period in estimated future development costs generally may not reflect total finding and development costs related to reserve additions for that period.
2. Sum of drilling extensions, technical revisions and economic factors in the reserves reconciliation included above.

Capital Expenditures

Capital allocation by category is as follows:

	($000s)			2021			2020
	Property acquisition			608			-
	Undeveloped land			808			1,115
	Property and equipment dispositions			(30,000	)		(8,206	)
	Sub-total acquisitions/dispositions			(28,584	)		(7,091	)
	Drilling and completion			33,085			5,828
	Facilities and related infrastructure			4,577			6,630
	Geological, geophysical and other			589			143
	Sub-total capital expenditures			38,251			12,601
	Total all-in capital			9,667			5,510

For Leucrotta's full NI 51-101 disclosure related to its 2021 year-end reserves please refer to the Company's AIF to be filed on SEDAR at www.sedar.com on or before April 30, 2022.

Forward-Looking Information

This news release contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.

More particularly and without limitation, this document contains forward-looking statements and information relating to the Company's oil, NGLs and natural gas production and reserves and reserves values, capital programs, and oil, NGLs, and natural gas commodity prices. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities and the availability and cost of labor and services.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

Unaudited Financial Information

Certain financial and operating results included in this news release such as FD&A costs, F&D costs, capital expenditures, working capital and production information are based on unaudited estimated results. These estimated results are subject to change upon completion of the audited financial statements for the year ended December 31, 2021, and changes could be material. The Company anticipates filing its audited financial statements and related management's discussion and analysis for the year ended December 31, 2021 on SEDAR at www.sedar.com on or before April 30, 2022.

Reserves Data

There are numerous uncertainties inherent in estimating quantities of light and medium oil, tight oil, shale gas, conventional natural gas and NGLs reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable light and medium oil, tight oil, shale gas, conventional natural gas and NGLs reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially.

Individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

This news release contains estimates of the net present value of the Company's future net revenue from its reserves. Such amounts do not represent the fair market value of the Company's reserves.

The reserves data contained in this news release has been prepared in accordance with National Instrument 51-101 ("NI 51-101"). The reserve data provided in this news release presents only a portion of the disclosure required under NI 51-101. All of the required information will be contained in the Company's Annual Information Form for the year ended December 31, 2021, to be filed on SEDAR at www.sedar.com on or before April 30, 2022.

Reserves are estimated remaining quantities of oil and natural gas and related substance anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology, and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:

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.

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.

Well Recoveries

Well recoveries are equivalent to EUR - Estimated Ultimate Recovery which is defined as "those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from an accumulation, plus those quantities already produced therefrom."

Potential Drilling Locations

This news release discloses drilling locations in three categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; and (iii) an aggregate total of (i) and (ii).

The 26 Lower Montney locations referenced in page 1 of this news release have been assigned reserves in the following categories at December 31, 2021, as independently evaluated by GLJ, in accordance with NI 51-101:

• 10 Proved Undeveloped
• 16 Probable Undeveloped

The 4 Upper Montney locations referenced in page 1 of this news release have been assigned reserves in the following categories at December 31, 2021, as independently evaluated by GLJ, in accordance with NI 51-101:

• 2 Proved Undeveloped
• 2 Probable Undeveloped

The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors.

Original Oil in Place (OOIP) and Original Gas in Place (OGIP)

OGIP (Original Gas in Place) and OOIP (Original Oil in Place) are equivalent to Total Petroleum Initially In Place ("TPIIP") for the purposes of this news release.

TPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook ("COGEH"), is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to "total resources"). There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

The OGIP and OOIP estimates quoted in this news release are unaudited internal estimates effective December 31, 2020 prepared by a qualified reserves evaluator in accordance with the COGEH Handbook. "Internal estimate" means an estimate that is derived by the Company's internal APEGA certified engineer(s), and geologist(s) and prepared in accordance with National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. Product type for the OOIP number is "tight oil" and product type for the OGIP number is "shale gas". The location of the resource is the Montney formation in the Doe, Mica and Two Rivers areas of Northeast British Columbia, north of the Town of Dawson Creek and east of Fort St. John where Leucrotta owned 246 net sections (258 Gross) with an average ownership working interest of 95% at the time of the evaluation. The key variables relevant to the evaluation are porosity, reservoir thickness, pressure, water saturation and gas composition which have increasing uncertainty, both positive and negative, with distance from existing wells

Industry Metrics

This news release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this news release. These metrics are "F&D costs", "FD&A costs", "net asset value", and "reserve-life index". These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons.

Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time, however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods.

"F&D costs" are calculated by dividing the sum of the total capital expenditures for the year (in dollars) by the change in reserves within the applicable reserves category (in boe). F&D costs, including FDC, includes all capital expenditures in the year as well as the change in FDC required to bring the reserves within the specified reserves category on production.

"FD&A costs" are calculated by dividing the sum of the total capital expenditures for the year inclusive of the net acquisition costs and disposition proceeds (in dollars) by the change in reserves within the applicable reserves category inclusive of changes due to acquisitions and dispositions (in boe). FD&A costs, including FDC, includes all capital expenditures in the year inclusive of the net acquisition costs and disposition proceeds as well as the change in FDC required to bring the reserves within the specified reserves category on production.

The Company uses F&D and FD&A as a measure of the efficiency of its overall capital program including the effect of acquisitions and dispositions. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.

"Net Asset Value" or "NAV" is calculated based on Leucrotta's estimated future net revenues before taxes associated with Leucrotta's reserves plus the value of undeveloped land and working capital, divided by the number of common shares outstanding. The term NAV does not have any standardized meaning according to IFRS and therefore may not be comparable to similar measures presented by other companies. Management believes that NAV can provide information useful to its shareholders in understanding its performance and may assist in the evaluation of its business relative to its peers.

"Reserve life index" or "RLI" is calculated by dividing the reserves (in boe) in the referenced category by the latest quarter of production (in boe) annualized. The Company uses this measure to determine how long the booked reserves will last at current production rates if no further reserves were added.

BOE Conversions

BOE's 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.

Abbreviations

Bbl	barrel
Mbbl	thousands of barrels
MMbtu	millions of British thermal units
Mcf	thousand cubic feet
MMcf	million cubic feet
Tcf	trillion cubic feet
NGLs	natural gas liquids
BOE	barrel of oil equivalent
MBOE	thousands of barrels of oil equivalent
WTI	West Texas Intermediate at Cushing Oklahoma

For further information, please contact:

LEUCROTTA EXPLORATION INC.
2110, 530 - 8^th Ave SW
Calgary, Alberta T2P 3S8
Phone: [phone]
www.leucrotta.ca

Robert Zakresky
President and Chief Executive Officer

Nolan Chicoine
Vice President, Finance and Chief Financial Officer

Neither the TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

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