Leucrotta Exploration Announces 2017 Year-End Reserves

CALGARY, Alberta, Feb. 27, 2018 (GLOBE NEWSWIRE) -- Leucrotta Exploration Inc. (“Leucrotta” or the “Company”) (TSX-V:LXE)  is pleased to announce its 2017 year-end reserves as independently evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) effective December 31, 2017 (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.

2017 Highlights

  • Increased proved developed producing reserves by 258% to 4.6 million barrels of oil equivalent (“boe”)
  • Increased proved plus probable reserves by 63% to 37.1 million boe
  • Increased proved reserves by 47% to 15.1 million boe
  • Reserve replacement of 1,474% on a proved plus probable basis and 561% on a proved basis
  • Achieved finding and development costs including changes in future development capital (“FDC”) but excluding land and property acquisitions/dispositions on a proved plus probable basis of $8.48 per boe
  • Cumulative booked reserves on only 9 net sections of 140 net sections in the Doe/Mica Montney Core area

Strategic Focus

Since inception, Leucrotta’s focus has been on:

  1. Geologically defining and quantifying the large Montney resource on Leucrotta’s lands.
  2. Drilling geographically significant step-out horizontal wells to define the per well productivity and reserves within the geologically defined area.
  3. Building out the infrastructure to tie-in wells to gain valuable information on type curves and recoveries and to provide capacity for future development.
  4. Expand the land base in anticipation of large scale future development.

During 2017, Leucrotta took significant steps towards accomplishing its goals and completing the initial delineation stage:

  1. Acquired several contiguous parcels of land that increased the contiguous acreage block to 140 sections.
  2. Drilled 3 net horizontal delineation wells in Doe/Mica that proved productivity over a larger portion of the land.
  3. Increased frac intensity in 2 of the Lower Montney Turbidite Oil wells with very material initial results that led to an increase in the estimated per well recoveries in the oil window.

For 2018, Leucrotta will drill a minimum of 3 additional horizontal delineation wells in the Lower Montney Turbidite oil window that will substantially complete the evaluation of productive capability over Leucrotta’s 140 section land block and provide further information on ultimate recoveries using higher frac intensity.  On completion of the program, Leucrotta estimates it will have derisked over 800 Montney horizontal drilling locations on its lands.  By early 2019, Leucrotta anticipates having collected sufficient production and geological data to enter into the development phase that will focus on cost reduction, pad development and systematically harvesting the reserves base. 

Overview of 2017 Reserve Bookings

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 12 new locations were booked in the Doe East and Mica areas in 2017. Positive reserve revisions were material at 1.7 million boe due primarily to well performance on higher frac intensity wells that resulted in higher per well reserve bookings in the Lower Montney Turbidite oil window.

New locations booked within the Lower Montney Turbidite oil window averaged 855 mboe per well on a proved plus probable basis, which is a 32% increase over the 2016 average booking of 650 mboe.

On a cumulative basis, Leucrotta has booked 13 horizontal Montney wells and 32 horizontal Montney locations of which 11 wells and 25 locations are in the Lower Montney turbidite.

Leucrotta has estimated, based on mapping and other technical data, that it has over 800 potential Montney drilling locations (predominantly in the Lower Montney Turbidite). 

Leucrotta estimates that it has the current financial capability (assuming pricing and performance are comparable to the GLJ Report) to execute on the $168 million of FDC 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:

   
Unaudited (1)  
($000s)2017 2016 
Property acquisition  35,550    - 
Undeveloped land   1,812    4,882 
Facility equipment not in use and held for sale  -    2,784 
Equipment disposition  (1,100)  (4,000)
  Sub-total acquisitions/dispositions  36,262    3,666 
   
Drilling and completion  34,831    7,657 
Facilities and related infrastructure  20,438    6,859 
Geological, geophysical  and other  883    392 
  Sub-total capital expenditures  56,152    14,908 
   
Total all-in capital  92,414    18,574 
     

 Note:

(1)   Numbers are unaudited.  See “Unaudited Financial Information” section.

Reserves Summary

Leucrotta’s December 31, 2017 reserves as prepared by GLJ effective December 31, 2017 and based on the GLJ (2018-01) future price forecast are as follows (1,4)

       
Working Interest Reserves (2)Light/
Medium Oil
(Mbbl)
Tight Oil
(Mbbl)
Conventional
Natural Gas
(Mmcf)
Shale
Natural Gas
(Mmcf)
NGLs
(Mbbl)
Total Oil
Equivalent
(Mboe) (3)
Proved      
  Producing334302721,1396594,649
  Developed non-producing08802,50557512
  Undeveloped0647047,4681,3339,892
Total proved331,1652770,8132,04915,054
Probable202,18216100,4903,04822,001
Total proved & probable523,34744171,3035,09737,054
       

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, 2018.  “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, 2017 and based on the GLJ (2018-01) future price forecast are summarized in the following table (1,2,3,4):

  
 Discount factor per year
($000s)0 % 5 % 10 % 15 % 20 % 
Proved     
  Producing59,657 50,853 44,312 39,385 35,587 
  Developed Non-producing10,197 7,793 6,272 5,249 4,523 
  Undeveloped105,555 65,024 40,938 25,771 15,693 
Total proved175,408 123,670 91,522 70,404 55,802 
Probable406,670 237,454 154,445 108,078 79,435 
Total proved & probable582,079 361,125 245,967 178,483 135,237 
           

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, 2018. 

Price Forecast

The GLJ (2018-01) 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$)
201859.0070.252.200.790
201959.0070.252.540.790
202060.0070.312.880.800
202163.0072.843.240.810
202266.0075.613.470.820
202369.0078.313.580.830
202472.0081.933.660.830
202575.0085.543.730.830
202677.3388.353.800.830
202778.8890.223.880.830
Escalate thereafter (1)2.0% per year2.0% per year2.0% per year 
     

Note:
 (1)  Escalated at two per cent per year starting in 2028 in the January 1, 2018 GLJ price forecast with the exception of foreign exchange, which remains flat.

Reserve Life Index (“RLI”)

Leucrotta’s RLI presented below is based on estimated Q4 2017 average production of 3,802 boe per day.

  
Reserve CategoryRLI
Proved plus Probable Reserves26.7
Proved10.8
  

Reserves Reconciliation

The following summary reconciliation of Leucrotta’s working interest reserves compares changes in the Company’s reserves as at December 31, 2017 to the reserves as at December 31, 2016 based on the based on the GLJ (2018-01) future price forecast (1,2) :

       
Total ProvedLight/Medium Oil Tight Oil Conventional
Natural Gas
Shale Natural
Gas 
NGLs Total Oil
Equivalent 
 (Mbbl)(Mbbl)(Mmcf) (Mmcf) (Mbbl)(Mboe) (3)
Opening balance  55   388   197   49,227   1,556   10,237 
Discoveries  -   -   -   -   -   - 
Extensions and improved recovery  -   846   -   21,875   639   5,131 
Technical revisions  (5)  48   (156)  4,308   55   790 
Acquisitions  -   -   -   -   -   - 
Dispositions  -   -   -   -   -   - 
Economic factors  -   -   (3)  (129)  (37)  (59)
Production  (18)  (118)  (10)  (4,468)  (164)  (1,045)
Closing balance  33   1,165   27   70,813   2,049   15,054 
       
       
Proved plus ProbableLight/Medium Oil Tight Oil Conventional
Natural Gas
Shale Natural
Gas 
NGLs Total Oil
Equivalent 
 (Mbbl)(Mbbl)(Mmcf) (Mmcf) (Mbbl)(Mboe) (3)
Opening balance  77   780   250   109,747   3,504   22,693 
Discoveries  -   -   -   -   -   - 
Extensions and improved recovery  -   2,539   -   56,027   1,537   13,414 
Technical revisions  (7)  147   (192)  8,710   151   1,711 
Acquisitions  -   -   -   1,286   84   298 
Dispositions  -   -   -   -   -   - 
Economic factors  -   -   (4)  -   (16)  (16)
Production  (18)  (118)  (10)  (4,468)  (164)  (1,045)
Closing balance  52   3,347   44   171,303   5,097   37,054 
             

 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 $13.43 per boe on a proved basis and $8.48 per boe on a proved plus probable basis.

FD&A costs, including FDC, were $19.61 per boe on a proved basis and $10.67 per boe on a proved plus probable basis.  The three-year cumulative which normalizes the period costs was $28.66 per boe on a proved basis and $9.64 per boe on a proved plus probable basis.

FD&A costs were significantly affected by the large amount expended for land and gas plant equipment which was not in use during 2015 to 2017 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 2015 to 2017 were negatively affected.
                  
Leucrotta has presented FD&A and F&D costs below. 

 

       
  2017  2016  3 Year Cumulative 
   Proved &   Proved &   Proved & 
($000's, except where noted) Proved  Probable  Proved  Probable  Proved  Probable 
       
F&D costs (excluding net acquisitions/dispositions) (1)      
  Exploration and development expenditures  56,152   56,152   14,908  14,908  96,876   96,876 
  Change in FDC (2)  22,546   71,910   13,269  26,642  28,564   84,910 
F&D costs excluding net acquisitions/dispositions (Including FDC)  78,698   128,062   28,177  41,550  125,440   181,786 
       
FD&A costs (including net acquisitions/dispositions)      
  Exploration and development expenditures  56,152   56,152   14,908  14,908  96,876   96,876 
  Net acquisitions (dispositions)   36,262   36,262   3,666  3,666  (5,993)  (5,993)
  FD&A costs including net acquisitions/dispositions  92,414   92,414   18,574  18,574  90,883   90,883 
  Change in FDC  22,546   71,910   13,269  26,642  (7,980)  38,475 
FD&A costs including net acquisitions/dispositions (Including FDC)  114,960   164,324   31,843  45,216  82,903   129,358 
       
Reserve Additions (Mboe) (3)      
  Exploration and development  5,862   15,108   2,440  5,933  9,601   22,921 
  Net acquisitions/dispositions  -   298   -  -  (6,708)  (9,498)
Total Reserve Additions  5,862   15,406   2,440  5,933  2,893   13,423 
       
F&D costs excluding net acquisitions/dispositions ($/boe)      
  Excluding FDC  9.58   3.72   6.11  2.51  10.09   4.23 
  Including FDC  13.43   8.48   11.55  7.00  13.07   7.93 
       
FD&A costs ($/boe)      
  Excluding FDC  15.76   6.00   7.61  3.13  31.41   6.77 
  Including FDC  19.61   10.67   13.05  7.62  28.66   9.64 
       

 Notes:

(1)   F&D and FD&A costs are unaudited.  See “Unaudited Financial Information” section.

(2)   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.

(3)   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 2017 year-end reserves please refer to the Company’s AIF to be filed on SEDAR at www.sedar.com on or before April 30, 2018.

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, 2017, to be filed on SEDAR at www.sedar.com on or before April 30, 2018.

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 800 total potential/possible Montney locations referenced in page 1 of this news release, only the following have been assigned reserves at December 31, 2017 as independently evaluated by GLJ, in accordance with NI 51-101:

  • 13 Proved Undeveloped
  • 19 Probable Undeveloped

 The remaining 768 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. 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.

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, 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, 2017, 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, 2017 on SEDAR at www.sedar.com on or before April 30, 2018.

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, 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.

"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

Bblbarrel
MMbtumillions of British thermal units
Mcfthousand cubic feet
Mbblthousands of barrels
MMcfmillion cubic feet 
BOEbarrel of oil equivalent
WTIWest Texas Intermediate at Cushing Oklahoma
MBOEthousands of barrels of oil equivalent

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