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Leucrotta Exploration Inc.

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Leucrotta Exploration Announces 2019 Year-End Reserves

Calgary, Alberta--(Newsfile Corp. - April 29, 2020) - Leucrotta Exploration Inc. (TSXV: LXE) ("Leucrotta" or the "Company") is pleased to announce its 2019 year-end reserves as independently evaluated by GLJ Petroleum Consultants Ltd. ("GLJ") effective December 31, 2019 (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.

2019 Highlights

During 2019, Leucrotta invested capital primarily in the infrastructure for the Two Rivers Project and drilling an exploratory well in the Below Lower Montney at Mica. Additional reserves were not attributed to either project as Two Rivers reserves were booked in 2018 and the Below Lower Montney well is not completed. Leucrotta added 3 million boe of proved plus probable reserves in 2019 with positive revisions to producing wells and booking three additional development locations. This resulted in overall positive reserve additions on a year over year basis as well as low finding and development costs.

Highlights are as follows:

  • Increased proved plus probable reserves by 3% to 61.1 million boe.
  • Increased proved reserves by 2% to 21.2 million boe.
  • Reserve replacement of 272% on a proved plus probable basis and 132% on a proved basis.
  • Achieved finding and development costs including changes in future development capital ("FDC") on a proved plus probable basis of $2.44 per boe.

Overview

Leucrotta is characterized by two distinct Montney Projects - the Doe/Mica Montney Development Project ("Doe/Mica Project") and the Two Rivers Exploration Project ("Two Rivers Project"). The Doe/Mica Project accounts for 95% of proved plus probable reserves booked and 96% of booked reserve value while the Two Rivers Project accounts for substantially all of the remaining booked reserves at 5% of proved plus probable reserves and 4% of booked reserve value. Both projects are more fully described below.

Doe/Mica Montney Development Project

The Doe/Mica Project spans over 100 net sections of land south of the Peace River in the Doe and Mica areas of northeast BC and northwest Alberta. Leucrotta has internally estimated that over three Montney intervals there are potentially over 4.7 billion barrels of light oil originally in place in addition to potentially over 8.4 TCF of original gas in place on its lands. Leucrotta lands span the volatile light oil window and the condensate-rich gas window of all three intervals. Two of the intervals (the Upper Montney and the Lower Montney Turbidite) have production and reserves assigned on Leucrotta lands while the Below Lower Montney has no production or reserves assigned on Leucrotta lands but is being successfully developed by other area operators.

The Doe/Mica Project is lightly booked with only 16 net sections having assigned reserves. Leucrotta has delineated a large portion of the lands with vertical and horizontals wells and constructed an extensive gathering system such that material production and corresponding reserves can be added once the project moves to full-scale development.

Two Rivers Montney Exploration Project

The Two Rivers Project spans over 100 net sections of land north of the Peace River in the Two Rivers area of northeast BC. As of the end of 2019, Leucrotta had drilled and tested one Upper Montney well (10-08) and one Lower Montney well (5-19) in the area. No wells were producing on the lands during 2019 due to lack of infrastructure in the area. In late Q1 2020, Leucrotta completed its planned Two Rivers facility and the 10-08 well was placed on production. Reserves were assigned to 2 net sections of land in the Two Rivers area.

Outlook for 2020

Leucrotta estimates as at March 31, 2020 it will have approximately $5 million of debt and the bank credit facility is $20 million.

During Q1 2020, Leucrotta completed the Two Rivers facility and has no plans to spend additional capital in the remainder of 2020. A capital program for 2021 will be released once there is more clarity on future commodity prices.

Overview of 2019 Reserve Bookings

Leucrotta had several positives in the 2019 GLJ Report which include:

  • Positive technical revisions of 1.1 million mboe (Proved plus probable).
  • Reduced future development costs of approximately $0.5 million per booked location due to drilling and completion modifications.

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. Due to decreased capital activity, no new wells were booked in 2019 and only 3 new locations were booked. The positive reserve revisions of 1.1 million boe were due to well performance.

On a cumulative basis, Leucrotta has booked 17 horizontal Montney wells and 56 horizontal Montney locations in two of the three prospective Montney zones.

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 Two Rivers area to acquire and enhance infrastructure and in the Doe/Mica area to drill a Below Lower Montney well. Capital allocation by category is as follows:

  ($000s) 2019   2018  
  Property acquisition 1,543   -  
  Undeveloped land 897   2,642  
  Equipment disposition (4,767 ) -  
       Sub-total acquisitions/dispositions (2,327 ) 2,642  
           
  Drilling and completion 4,203   26,737  
  Facilities and related infrastructure 8,112   6,806  
  Geological, geophysical  and other 242   496  
       Sub-total capital expenditures 12,557   34,039  
      
   Total all-in-capital 10,230     36,681  


Reserves Summary

Leucrotta's December 31, 2019 reserves as prepared by GLJ effective December 31, 2019 and based on the GLJ (2020-01) future price forecast are as follows (1,4):

Working Interest Reserve (2)Light/
Medium Oil (Mbbl)
Tight Oil
(Mbbl)
Conventional Natural Gas
(Mmcf)
Shale
Natural Gas (Mmcf)
NGLs
(Mbbl)
Total Oil Equivalent (Mboe) (3)
Proved
  Producing27401021,6657084,747
  Developed non-producing0003,61445647
  Undeveloped01,081070,8052,91115,794
Total proved271,482096,0843,66521,188
Probable13,6510175,4836,97439,873
Total proved & probable285,1330271,56710,63961,061

 

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 are included in Company's AIF available on SEDAR at www.sedar.com. "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, 2019 and based on the GLJ (2020-01) future price forecast are summarized in the following table (1,2,3,4):

Discount factor per year
($000s)0% 5% 10% 15% 20%
Proved
  Producing55,84448,58442,84138,30834,692
  Developed Non-producing3,9022,8982,2191,7551,428
  Undeveloped159,937103,90568,88246,22331,056
Total proved219,682155,388113,94286,28667,177
Probable601,503339,405206,565132,30087,308
Total proved & probable821,185494,793320,507218,586154,485

 

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 are included in Company's AIF available on SEDAR at www.sedar.com.

Price Forecast

The GLJ (2020-01) price forecast is as follows:

YearWTI Oil @ Cushing
($US / Bbl)
Edmonton Light Oil
($Cdn / Bbl)
AECO Natural Gas
($Cdn / Mmbtu)
Foreign Exchange (US$/Cdn$)
202061.0071.712.080.760
202163.0074.032.350.770
202266.0076.922.550.780
202368.0080.132.650.780
202470.0082.692.750.780
202572.0085.262.850.780
202674.0087.822.910.780
202775.8190.142.970.780
202877.3392.093.030.780
202978.8894.083.090.780
Escalate thereafter (1)2.0% per year2.0% per year2.0% per year

 

Note:

(1) Escalated at two per cent per year starting in 2030 in the January 1, 2020 GLJ price forecast with the exception of foreign exchange, which remains flat.

Net Asset Value ("NAV")

Leucrotta's NAV as at December 31, 2019 and based on the GLJ (2020-01) future price forecast is as follows:

 ($000s, except per share amounts)   
Pre-tax net present value ("NPV") of proved & probable reserves discounted at 10%320,507
Undeveloped land (1)112,960
Working capital125
Net asset value433,592
  
Shares outstanding (basic)200,526
Net asset value per share$2.16

 

Note:

(1) Undeveloped land is included at cost of approximately $660 per acre.

Reserve Life Index ("RLI")

Leucrotta's RLI presented below is based on estimated Q4 2019 average production of 2,830 boe per day.

Reserve CategoryRLI
Proved plus Probable Reserves59.1
Proved Reserves20.5

 

Reserves Reconciliation

The following summary reconciliation of Leucrotta's working interest reserves compares changes in the Company's reserves as at December 31, 2019 to the reserves as at December 31, 2018 based on the based on the GLJ (2020-01) future price forecast (1,2) :

  Total Proved   Light/Medium Oil    Tight Oil    Conventional Natural Gas   Shale Natural Gas    NGLs    Total Oil Equivalent   
      (Mbbl)   (Mbbl)   (Mmcf)    (Mmcf)    (Mbbl)   (Mboe) (3)  
  Opening balance   43   1,425   9   95,152   3,502   20,830  
  Discoveries   -   -   -   -   -   -  
  Extensions and improved recovery   -   117   -   2,442   76   601  
  Technical revisions   (7 ) 72   (9 ) 4,140   276   1,030  
  Acquisitions   -   -   -   -   -   -  
  Dispositions   -   -   -   -   -   -  
  Economic factors   -   (6 ) -   (779 ) (26 ) (162 )
  Production   (9 ) (126 ) -   (4,872 ) (164 ) (1,111 )
  Closing balance   27   1,482   -   96,084   3,665   21,188  
                             
                             
  Proved plus Probable   Light/Medium Oil   Tight Oil   Conventional Natural Gas   Shale Natural Gas   NGLs   Total Oil Equivalent  
      (Mbbl)   (Mbbl)   (Mmcf)   (Mmcf)   (Mbbl)   (Mboe) (3 )
  Opening balance   63   4,706   13   266,214   10,013   59,154  
  Discoveries   -   -   -   -   -   -  
  Extensions and improved recovery   -   477   -   9,415   294   2,341  
  Technical revisions   (16 ) 81   (11 ) 2,980   499   1,060  
  Acquisitions   -   -   -   -   -   -  
  Dispositions   -   -   -   -   -   -  
  Economic factors   (11 ) (5 ) (2 ) (2,171 ) (4 ) (383 )
  Production   (9 ) (126 ) -   (4,872 ) (164 ) (1,111 )
  Closing balance   28   5,133   -   271,567   10,639   61,061  

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")

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 ($1.33) per boe on a proved basisable basis.

FD&A costs, including FDC, were ($2.92) per boe on a proved basis and $1.67 per boe on a proved plus probable basis and $2.44 per boe on a proved plus prob. The three-year cumulative which normalizes the period costs was $14.34 per boe on a proved basis and $8.80 per boe on a proved plus probable basis.

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

       2019     2018     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   12,557   12,557   34,039   34,039   102,748   102,748  
     Change in FDC(1)   (14,515 ) (5,204 ) 59,233   162,020   67,264   228,726  
  F&D costs excluding net acquisitions/dispositions (Including FDC)   (1,958 ) 7,353   93,272   196,059   170,012   331,474  
                             
  FD&A costs (including net acquisitions/dispositions)                          
     Exploration and development expenditures   12,557   12,557   34,039   34,039   102,748   102,748  
     Net acquisitions (dispositions)   (2,327 ) (2,327 ) 2,642   2,642   36,577   36,577  
     FD&A costs including net acquisitions/dispositions   10,230   10,230   36,681   36,681   139,325   139,325  
     Change in FDC   (14,515 ) (5,204 ) 59,233   162,020   67,264   228,726  
  FD&A costs including net acquisitions/dispositions (Including FDC)   (4,285 ) 5,026   95,914   198,701   206,589   368,051  
                             
  Reserve Additions (Mboe) (2)                          
     Exploration and development   1,469   3,018   7,072   23,396   14,403   41,522  
     Net acquisitions/dispositions   -   -   -   -   -   298  
  Total Reserve Additions   1,469   3,018   7,072   23,396   14,403   41,820  
                             
  F&D costs excluding net acquisitions/dispositions ($/boe)                          
     Excluding FDC   8.55   4.16   4.81   1.45   7.13   2.47  
     Including FDC   (1.33 ) 2.44   13.19   8.38   11.80   7.98  
                             
  FD&A costs ($/boe)                          
     Excluding FDC   6.96   3.39   5.19   1.57   9.67   3.33  
     Including FDC   (2.92 ) 1.67   13.56   8.49   14.34   8.80  


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.

For Leucrotta's full NI 51-101 disclosure related to its 2019 year-end reserves please refer to the Company's AIF available on SEDAR at www.sedar.com.

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.

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 is contained in the Company's Annual Information Form for the year ended December 31, 2019, available on SEDAR at www.sedar.com.

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 three categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; and (iii) an aggregate total of (i) and (ii).

The 56 Montney locations referenced in page 2 of this news release have been assigned reserves in the following categories at December 31, 2019, as independently evaluated by GLJ, in accordance with NI 51-101:

  • 20 Proved Undeveloped
  • 36 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").

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, 2019 prepared by a qualified reserves evaluator in accordance with the COGEH 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 and Mica areas of Northeast British Columbia, north of the Town of Dawson Creek and east of Fort St. John. Leucrotta owns 101 net sections (108 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.

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.

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

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 Oklahom


For further information, please contact:

LEUCROTTA EXPLORATION INC.

700, 639 -5th 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.

To view the source version of this press release, please visit https://www.newsfilecorp.com/release/55021

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