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Leucrotta Exploration Announces 2020 Year-End Reserves


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These translations are done via Google Translate

Calgary, Alberta–(Newsfile Corp. – April 28, 2021) – Leucrotta Exploration Inc. (TSXV: LXE) (“Leucrotta” or the “Company”) is pleased to announce its 2020 year-end reserves as independently evaluated by GLJ Ltd. (“GLJ”) effective December 31, 2020 (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 2020 and early 2021, Leucrotta made the decision to focus future capital primarily on the Mica Project as outlined in our previous news release dated March 15, 2021. To better align corporate plans with the GLJ Report, Leucrotta decided to remove certain undrilled locations in the Doe and Two Rivers areas that were previously booked but did not fit into Leucrotta’s near term plans. Proved and probable reserves totaling 13.8 million Boe and the associated future development capital (“FDC”) totaling $97 million were removed from the 2020 GLJ Report. As a result, Leucrotta will be left with a more manageable $ 227 million of FDC booked.

Subsequent to year-end, the Doe property was disposed of for gross proceeds of $30 million which will further reduce reserves in the year-end 2021 evaluation. Current (Year-end 2020) proved plus probable reserves booked to the disposition lands are 10.8 million Boe (86% associated with undrilled locations) and the related future development capital totaling $38 million.

The 2020 GLJ Report books reserves on only a small percentage of the Mica Project development area and uses existing wells that had one-mile lateral lengths and approximately 40 fracs per well to project performance of future wells. In 2021, Leucrotta plans to drill and complete its test Pad that will have approximately 1.5-mile lateral lengths and materially increase the frac intensity. Performance of the new wells will have an effect on locations booked in 2020 as well as any additional lands booked in the future.

For 2021, Leucrotta will use production data from the pad development to build out the reserve base for the Mica Project.

2020 Review

During 2020, Leucrotta invested $13.7 million in capital projects that were offset by $8.2 million in dispositions that resulted in net capital expenditures of $5.5 million. Capital was primarily at Two Rivers where it drilled and completed one well and completed construction of the Two Rivers facility. While minimal capital was spent on Leucrotta’s main property in Mica, more production data was collected to prove out the existing production curves.

Leucrotta wells continue to experience year after year increased recoveries. For 2020, producing wells had additional increased recoveries of 6% due to well performance. For additional information on recoveries please see “Well Recoveries” at the end of this news release.

Outlook for 2021

Leucrotta estimates that it currently has $57.5 million in cash and working capital and no debt.

Leucrotta is planning a 2021 capital program of approximately $30 million that includes a 3 well test pad in the Montney that incorporates longer horizontal lengths and materially increased frac intensity.

A more detailed capital program for 2021 is anticipated to be released in the near future.

Overview of 2020 Reserve Bookings

Leucrotta decreased the number of locations booked by 14 net wells on a proved plus probable basis. As previously noted, locations removed and associated FDC of $97 million will better align the GLJ Report with the planned development. On a cumulative basis, Leucrotta has booked 17 horizontal Montney wells and 42 horizontal Montney locations. These locations are booked based on one-mile horizontal lengths and previously used frac intensity.

For additional information on reserves assigned to these drilling locations please see “Potential Drilling Locations” at the end of this news release.

Capital Expenditures

Capital allocation by category is as follows:

($000s) 2020 2019
Property acquisition 1,543
Undeveloped land 1,115 897
Property and equipment dispositions (8,206 ) (4,767 )
     Sub-total acquisitions/dispositions (7,091 ) (2,327 )
Drilling and completion 5,828 4,203
Facilities and related infrastructure 6,630 8,112
Geological, geophysical and other 143 242
     Sub-total capital expenditures 12,601 12,557
Total all-in capital 5,510 10,230

 

Reserves Summary

Leucrotta’s December 31, 2020 reserves as prepared by GLJ effective December 31, 2020 and based on the GLJ (2021-01) 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 467 22,543 286 4,511
     Developed non-producing 0 4,328 77 799
     Undeveloped 800 44,481 1,268 9,482
Total proved 1,268 71,352 1,632 14,791
Probable 3,150 135,008 3,120 28,772
Total proved & probable 4,418 206,360 4,752 43,563

 

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, 2020 and based on the GLJ (2021-01) 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 42,386 36,926 32,580 29,137 26,382
     Developed Non-producing 4,925 3,573 2,642 2,000 1,548
     Undeveloped 69,192 40,906 23,625 12,777 5,745
Total proved 116,503 81,406 58,847 43,914 33,675
Probable 297,680 170,565 103,075 64,141 40,008
Total proved & probable 414,183 251,971 161,922 108,054 73,684

 

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 (2021-01) price forecast is as follows:

Year WTI Oil @ Cushing
($US / Bbl)
Edmonton Light Oil
($Cdn / Bbl)
AECO Natural Gas
($Cdn / Mmbtu)
Foreign Exchange (US$/Cdn$)
2021 48.00 55.49 2.72 0.775
2022 51.50 60.78 2.67 0.765
2023 54.50 63.82 2.60 0.760
2024 57.79 68.14 2.60 0.760
2025 58.95 69.67 2.65 0.760
2026 60.13 71.22 2.71 0.760
2027 61.33 72.80 2.76 0.760
2028 62.56 74.42 2.81 0.760
2029 63.81 76.07 2.87 0.760
2030 65.09 77.59 2.92 0.760
Escalate thereafter (1) 2.0% per year 2.0% per year 2.0% per year

 

Note:
(1) Escalated at two per cent per year starting in 2031 in the January 1, 2021 GLJ price forecast with the exception of foreign exchange, which remains flat.

Net Asset Value (“NAV”)

Leucrotta’s NAV as at December 31, 2020 and based on the GLJ (2021-01) future price forecast is as follows:

($000s, except per share amounts)
     Pre-tax net present value (“NPV”) of proved & probable reserves discounted at 10% 161,922
     Undeveloped land (1) 110,842
     Working capital (5,807)
     Net asset value 266,957
     Shares outstanding (basic) 200,526
     Net asset value per share $1.33

 

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 2020 average production of 2,897 boe per day.

Reserve Category RLI
Proved plus Probable Reserves 41.2
Proved Reserves 14.0

 

Reserves Reconciliation

The following summary reconciliation of Leucrotta’s working interest reserves compares changes in the Company’s reserves as at December 31, 2020 to the reserves as at December 31, 2019 based on the based on the GLJ (2021-01) 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 27 1,482 96,084 3,665 21,188
Discoveries
Extensions and improved recovery 62 1,762 45 401
Technical revisions 2 94 (17,212) (1,856) (4,628)
Acquisitions
Dispositions
Economic factors (16) (209) (4,194) (83) (1,008)
Production (13) (162) (5,089) (138) (1,161)
Closing balance 1,268 71,352 1,632 14,791
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 28 5,133 13 271,567 10,639 61,061
Discoveries
Extensions and improved recovery 74 2,011 51 460
Technical revisions 2 (614) (11) (62,351) (5,795) (16,798)
Acquisitions
Dispositions
Economic factors (17) (13) (2) 220 (5) 2
Production (13) (162) (5,089) (138) (1,161)
Closing balance 4,418 206,360 4,752 43,563

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:

2020  2019 3 Year Cumulative
Proved & Proved & Proved &
($000’s, except where noted) Proved Probable Proved Probable Proved Probable
F&D costs (excluding net acquisitions/dispositions)
   Exploration and development expenditures 12,601 12,601 12,557 12,557 59,197 59,197
   Change in FDC (1) (44,713) (97,021) (14,515) (5,204) 5 59,795
F&D costs excluding net acquisitions/dispositions (Including FDC) (32,112) (84,420) (1,958) 7,353 59,202 118,992
FD&A costs (including net acquisitions/dispositions)
   Exploration and development expenditures 12,601 12,601 12,557 12,557 59,197 59,197
   Net acquisitions (dispositions) (7,090) (7,090) (2,327) (2,327) (6,775) (6,775)
   FD&A costs including net acquisitions/dispositions 5,510 5,510 10,230 10,230 52,421 52,421
   Change in FDC (44,713) (97,021) (14,515) (5,204) 5 59,795
FD&A costs including net acquisitions/dispositions (Including FDC) (39,203) (91,511) (4,285) 5,026 52,426 112,216
Reserve Additions (Mboe) (2)
   Exploration and development (5,236) (16,337) 1,469 3,018 3,305 10,077
   Net acquisitions/dispositions
Total Reserve Additions (5,236) (16,337) 1,469 3,018 3,305 10,077
F&D costs excluding net acquisitions/dispositions ($/boe)
   Excluding FDC (2.41) (0.77) 8.55 4.16 17.91 5.87
   Including FDC 6.13 5.17 (1.33) 2.44 17.91 11.81
FD&A costs ($/boe)
   Excluding FDC (1.05) (0.34) 6.96 3.39 15.86 5.20
   Including FDC 7.49 5.60 (2.92) 1.67 15.86 11.14

 

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 2020 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, 2020, 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.

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 42 Montney locations referenced in page 1 of this news release have been assigned reserves in the following categories at December 31, 2020, as independently evaluated by GLJ, in accordance with NI 51-101:

  • 13 Proved Undeveloped
  • 29 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.

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 “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.

“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 Oklahoma

 

For further information, please contact:

LEUCROTTA EXPLORATION INC.
700, 639 -5th Ave SW
Calgary, Alberta T2P 0M9
Phone: (403) 705-4525
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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