Leucrotta Exploration Announces 2018 Year-End Reserves

Calgary, Alberta--(Newsfile Corp. - March 7, 2019) - Leucrotta Exploration Inc. (TSXV: LXE) ("Leucrotta" or the "Company") is pleased to announce its 2018 year-end reserves as independently evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2018 (the "GLJ Report"), in accordance with National Instrument 51-101 ("NI 51-101") and Canadian Oil and Gas Evaluation ("COGE") Handbook. All dollar figures are Canadian dollars unless otherwise noted.

2018 Highlights

• Increased proved plus probable reserves by 60% to 59.2 million boe.
• Increased proved reserves by 38% to 20.8 million boe.
• Reserve replacement of 1,805% on a proved plus probable basis and 546% on a proved basis.
• Achieved finding and development costs including changes in future development capital ("FDC") on a proved plus probable basis of $8.38 per boe.
• Lower Montney cumulative booked reserves on only 13 net sections of approximately 220 net sections in the Doe/Mica/Two Rivers Montney Core area.
• Upper Montney cumulative booked reserves on only 4.5 net sections of approximately 220 net sections in the Doe/Mica/Two Rivers Montney Core area.
• Increased Net Asset Value to $1.66 per share exclusive of land value ($2.23 per share including land at cost).

Strategic Focus

Since inception, Leucrotta's focus has been on defining and quantifying its large Montney resource by moving the various Montney zones from exploration through the appraisal and delineation phases and ultimately to the development ready phase. Leucrotta has identified 3 potential Montney zones on its lands that it is moving through the various phases.

Lower Montney Turbidite

The Lower Montney Turbidite is the most pervasive zone on Leucrotta's land base and characterized as being predominantly in the volatile light oil window. Leucrotta has internally estimated that there are potentially over 5 billion barrels of light oil originally in place in addition to potentially over 5 TCF of original gas in place on its lands in the Lower Montney Turbidite.

To date, Leucrotta estimates that it has moved the project from exploration phase through to development ready phase on 140 of the approximately 220 net sections of land. On the 140 sections, Leucrotta has completed the following:

• Collecting data to support the estimated resource in place including mapping the extent of such resource.
• Delineating a large portion of the lands with vertical and horizontal wells.
• Increased the frac intensity to successfully increase productivity and estimated recoveries.

Of note for 2018, the 5-19 well at north Mica not only proved a material extension of the productive area of the zone but added additional evidence that increased frac intensity has a positive effect on productivity and estimated recoveries.

The current reserve report reflects the development ready phase for the project but still has only 13 of the total approximately 220 net sections booked. When moving to full development, certain areas of focus to improve economics and enhance the values in the reserve report include:

• Reducing capital and operating costs through pad development and economies of scale.
• Increasing liquids yields through installation of deep cut plant (25% of booked reserves are currently oil and NGLs and deep cut plant could increase this to as much as an estimated 36%).
• Increasing recoveries and improving economics through extended length wells and further frac design enhancements.

The remaining 80 sections are in the appraisal phase. Leucrotta intends to drill a horizontal multi-frac well on the block in late 2019 or early 2020 to assess productivity.

Upper Montney

The Upper Montney is also pervasive on Leucrotta's land base but less delineated than the Lower Montney Turbidite. The Upper Montney lands straddle the volatile light oil window and the condensate-rich gas window, however, lack of delineation to this point leaves the line between the two somewhat interpretative. Leucrotta has internally estimated that there are potentially over 1.5 billion barrels of light oil originally in place in addition to potentially over 2.5 TCF of original gas in place on its lands in the Upper Montney.

To date, approximately 8 net sections of Leucrotta's lands that are located at Doe are considered development ready while the remaining lands are either in delineation or appraisal phases. The successful A10-08 well at Two Rivers (previously announced test rate (June 18, 2018) of 1,842 boepd including 685 boepd of light oil) will move a significant area surrounding this well to the delineation phase. Based on the success of the A10-08 well, Leucrotta intends to drill additional appraisal wells on the land base.

The current reserve base reflects the development ready phase of the Upper Montney at Doe with only 4.5 of the total approximately 220 net sections booked. Given the complementary effect of stacked zones, the Upper Montney would benefit in a similar nature from the commercial development of the Lower Montney Turbidite as described above.

Below Lower Montney ("BLM")

The BLM is the lowest portion of the Montney and has been successfully tested by other operators from Pouce Coupe to Kakwa. Leucrotta has gathered various geological information through drilling other wells on its lands and believes the lands are primarily located within the volatile light oil window. Leucrotta has internally estimated that there are potentially over 4 billion barrels of light oil originally in place in addition to potentially over 4 TCF of original gas in place on its lands in the Below Lower Montney. No reserves have been booked in this zone.

For 2019, Leucrotta intends to drill one horizontal multi-frac appraisal well to test the productivity of this zone.

Outlook for 2019

Leucrotta estimates as at March 31, 2019 it will have approximately $5 million net working capital and no debt in addition to an undrawn bank line of $25 million.

Leucrotta intends to remain conservative and debt-free during 2019 while executing on its most impactful capital projects from a value and future growth perspective. Projects would include building infrastructure to tie in existing wells to increase production and cash flow, drilling an appraisal well in the BLM and delineation wells in the Upper Montney to prove stacked zones for future development.

Expansion of infrastructure and moving to pad development is expected to start in mid-2020.

Overview of 2018 Reserve Bookings

Leucrotta had several positives in the 2018 GLJ Report which include:

• Positive technical revisions of 2,024 mboe (Proved plus probable).
• Increase of $84 million in overall value of reserves (proved plus probable 10% NPV) despite an estimated $20 million reduction due to change in pricing from 2017 to 2018.

Leucrotta has maintained a conservative philosophy to booking reserves and has only booked locations immediately offsetting previously drilled wells that cover a large geographic area. A total of 4 new wells and 21 new locations were booked. Positive reserve revisions were material at 2.0 million boe due primarily to well performance and higher liquid recoveries.

New locations booked within the Lower Montney Turbidite oil window averaged 872 mboe per well on a proved plus probable basis, which is consistent with the 2017 average booking of 855 mboe.

On a cumulative basis, Leucrotta has booked 17 horizontal Montney wells and 53 horizontal Montney locations of which 13 wells and 39 locations are in the Lower Montney Turbidite.

Leucrotta has estimated, based on mapping and other technical data, that it has over 1,000 potential Montney drilling locations (predominantly in the Lower Montney Turbidite). Leucrotta has initially estimated locations based on 3 to 4 wells per section per zone.

Leucrotta estimates that it has the current financial capability (assuming pricing and performance are comparable to the GLJ Report) to execute on the $330 million of FDC (first five year average of $60 million) included in the GLJ Report and therefore realize on the values presented. Should Leucrotta be able to obtain similar drilling results on future wells, there is a large potential value to be booked and subsequently realized given Leucrotta's large unbooked drilling inventory.

For additional information on reserves assigned to these drilling locations please see "Forward Looking Information - Potential Drilling Locations" at the end of this news release.

Capital Expenditures

Leucrotta's capital expenditures were focused predominantly in the Doe/Mica area to expand its land base, improve and expand infrastructure, and delineate its large Montney land base. Capital allocation by category is as follows:

Reserves Summary

Leucrotta's December 31, 2018 reserves as prepared by GLJ effective December 31, 2018 and based on the GLJ (2019-01) future price forecast are as follows ^(1,4):

Reserves Values

The estimated future net revenues before taxes associated with Leucrotta's reserves effective December 31, 2018 and based on the GLJ (2019-01) future price forecast are summarized in the following table ^(1,2,3,4):

Price Forecast

The GLJ (2019-01) price forecast is as follows:

Net Asset Value ("NAV")

Leucrotta's NAV as at December 31, 2018 and based on the GLJ (2019-01) future price forecast is as follows:

Reserve Life Index ("RLI")

Leucrotta's RLI presented below is based on estimated Q4 2018 average production of 3,202 boe per day.

Reserves Reconciliation

The following summary reconciliation of Leucrotta's working interest reserves compares changes in the Company's reserves as at December 31, 2018 to the reserves as at December 31, 2017 based on the based on the GLJ (2019-01) future price forecast ^(1,2) :

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

F&D costs exclude net property acquisitions/dispositions, undeveloped land acquisitions, and gas plant equipment which was not in use. F&D costs, including FDC, were $13.19 per boe on a proved basis and $8.38 per boe on a proved plus probable basis.

FD&A costs, including FDC, were $13.56 per boe on a proved basis and $8.49 per boe on a proved plus probable basis. The three-year cumulative which normalizes the period costs was $15.79 per boe on a proved basis and $9.13 per boe on a proved plus probable basis.

FD&A costs were significantly affected by the large amount expended for land during 2016 to 2018 with no direct reserve additions during these periods for these expenditures. Certain infrastructure costs were also incurred during the period that affects all future projects as well as current projects. Long-term FD&A will normalize both these cost areas but 2016 to 2018 were negatively affected.

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

For Leucrotta's full NI 51-101 disclosure related to its 2018 year-end reserves please refer to the Company's AIF to be filed on SEDAR at www.sedar.com on or before April 30, 2019.

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 labour 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.

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, 2018, to be filed on SEDAR at www.sedar.com on or before April 30, 2019.

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.

Potential Drilling Locations

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

Of the 1,000 total potential/possible Montney locations referenced in page 2 of this news release, only the following have been assigned reserves at December 31, 2018 as independently evaluated by GLJ, in accordance with NI 51-101:

• 19 Proved Undeveloped
• 34 Probable Undeveloped

The remaining 947 potential/possible locations are unbooked.

Unbooked locations are based on the Company's prospective acreage and internal estimates as to the number of wells that can be drilled per section. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information and performed by a Qualified Reserves Evaluator (QRE). There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. 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. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.

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").

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 and is potentially producible. 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 press release are unaudited internal estimates effective December 31, 2018 prepared by a qualified reserves evaluator in accordance with the COGE Handbook. 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. Leucrotta owns 222 net sections (234 gross) of Montney rights in that area with an average working interest of 94%. The resource estimates quoted in this release represent Leucrotta's net working interest share.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.

Test Rates

The A10-08-83-16W6 well was production tested for 6 days after the original cleanup and produced at an average rate of 1,100 boe/d (48% gas, 52% Oil and Condensate) over that period, excluding load fluid and energizing fluid. At the end of the test, flowing wellhead pressure and production rates were stable. As noted earlier, this well had a flow rate on the last day of the test of 1,842 boepd.

A pressure transient analysis or well-test interpretation has not been carried out on this well and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.

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.

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, 2018, 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, 2018 on SEDAR at www.sedar.com on or before April 30, 2019.

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 "reserve replacement", "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 replacement" is calculated by dividing the annual proved plus probable reserve adds (in boe) by the Company's annual production (in boe). The Company uses this measure to determine the relative change of its reserves base over a period of time by measuring the amount of proved reserves and proved plus probable reserves added to a company's reserve base during the year relative to the amount of oil and gas produced.

"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.

Abbreviations

For further information, please contact:

LEUCROTTA EXPLORATION INC.
700, 639 -5^th Ave SW
Calgary, Alberta T2P 0M9
www.leucrotta.ca

Phone: (403) 705-4525
Fax: (403) 705-4526

Robert Zakresky
President and Chief Executive Officer
Phone: (403) 705-4525

Nolan Chicoine
Vice President, Finance and Chief Financial Officer
Phone: (403) 705-4525

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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