Montney Light Oil:

The Mica 8-22 horizontal well was drilled with a 1,537 meter horizontal lateral and completed using 60 tonne slickwater fracs at 55 metre intervals for a total of 26 stages. The drill and complete cost of the well was $3.9 million. At the end of an initial 8-day test period, the well was flowing at an average rate of approximately 713 boe/d (300 bopd of 41 API sweet light oil, 55 boepd of NGL's, and 2.2 mmcf/d of natural gas).⁽¹⁾

The previous Mica Light Oil well ("13-07") was completed in Q1 2015 and tested at approximately 472 boepd (195 bopd of light oil, 35 boepd of NGL's, and 1.5 mmcf/d of natural gas).⁽¹⁾ The 13-07 well was placed on production in Q4 2015 and had an IP90 of 379 boepd which significantly exceeded expectations relative to the test rate.⁽¹⁾

The Mica 8-22 well extends the oil window of the Lower Montney Turbidite play thereby placing a significant light oil resource on Leucrotta's lands as a result of new geological mapping of the oil pool. Leucrotta will look to place this well on-stream in the second half of 2016 to gather production data that will help in estimating recoveries and developing initial type curves for this resource.⁽²⁾

Leucrotta is very pleased with the results and will continue in its strategy to further delineate and develop this potentially large resource in conjunction with Leucrotta's Liquids-rich Lower Montney Turbidite play noted below.⁽²⁾

Liquids-rich Montney Gas:

Leucrotta had recently announced a delineation well at East Doe that tested at 1,290 boepd and a development well at Doe that had an IP30 of over 900 boepd demonstrating the high productivity of the area, particularly in relation to the drill and complete costs of less than $4 million.⁽¹⁾

Leucrotta has internally estimated that it has now delineated over 1 TCF of original gas in place ("OGIP") to date as mapped over 29 gross sections of Leucrotta's total of 193 gross Montney sections in the greater area.⁽³⁾

Leucrotta estimates it has de-risked over 160 gross locations in this liquids-rich gas play that have estimated per well recoveries of approximately 900 mboes (21% Liquids) and drilling costs and completion costs of less than $4 million per well.⁽⁴⁾ The estimated per well recoveries is based on nearby productive wells used as analogies.

The Company is currently working on pipeline routes to gather the gas and liquids from the East Doe area for processing at its 25 mmcf/d sweet gas plant at Doe, as well as planning infrastructure to integrate the Montney Light Oil Play at Mica. Additional delineation locations will be licensed at Doe to be drilled in conjunction with the expansion of the gathering system that is slated to be constructed in Q4 2016.

Forward-Looking Information

This press 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 plan to delineate and develop its lands and resources, the anticipated timing of putting the Mica 8-22 well on-stream, the anticipated timing of the construction of the gathering system expansion at Doe, the Company's oil, NGLs and natural gas production, and the timing and costs of capital programs. 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, Leucrotta's internal projections, expectations or beliefs relating to future events or future performance and includes information as to our future well inventory in its core areas, the Company's exploration and development drilling and other exploitation plans for 2016 and beyond, and related production expectations, and costs and expenses, the Company's plans for constructing and expanding the facilities, the volume of Leucrotta's oil and gas reserves and the volume of Leucrotta's oil and gas resources in the Northeast British Columbia Montney, 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.

Information Regarding Oil and Gas Volumes

1. Well test results are not necessarily indicative of long-term performance or of ultimate recovery.
   
   
2. Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. There is uncertainty that it will be commercially viable to produce any portion of the discovered resources. There is no certainty that any portion of the undiscovered resources will be discovered, and if discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
   
   
3. Original oil in place ("OOIP") and OGIP are not defined terms within National Instrument 51-101 and are considered equivalent to Discovered Petroleum Initially In Place ("DPIIP"). DPIIP is defined in the Canadian Oil and Gas Evaluation Handbook ("COGEH") as the quantity of hydrocarbons that are estimated to be in place within a known accumulation. DPIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources. There is no certainty that it will be economically viable or technically feasible to produce any portion of this DPIIP except for those portions identified as proved or probable reserves.
   
   The estimate of OGIP is an unaudited internal estimate effective February 25, 2016 prepared by a qualified reserves evaluator in accordance with the COGE Handbook. The discovered accumulation includes 29 gross sections (25 net) which lie within 3 miles of productive wells in the same mappable geologic horizon. 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.
   
   
4. Of the de-risked locations, only the following have been assigned reserves at December 31, 2014 as independently evaluated by GLJ Petroleum Consultants Ltd. ("GLJ"), in accordance with National Instrument 51-101 ("NI 51-101"):
   
   

• 1 Proved Developed Producing
• 2 Proved Non-producing
• 8 Proved Undeveloped
• 7 Probable Undeveloped

The remaining 142 locations are unbooked.

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

Unbooked locations are internal estimates based on the Company's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. 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. 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.

The per well recoveries referenced of approximately 900 mboes/well are based on Proved plus Probable Undeveloped reserves booked for the Company wells in the same formation in proximity to the locations referenced, based on the December 31, 2014 independent reserves evaluation performed by GLJ in accordance with NI 51-101.

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.

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.