Leucrotta Announces Update on Operations and Financial Position
CALGARY, Alberta, Jan. 23, 2018 (GLOBE NEWSWIRE) -- Leucrotta Exploration Inc. (“Leucrotta” or the “Company”) (TSXV - LXE) is pleased to announce the following update:
PRODUCTION ON 9-33, A8-22 AND 8-4 LOWER MONTNEY TURBIDITE OIL WELLS AND 4-12 LOWER MONTNEY TURBIDITE LIQUIDS RICH GAS WELL
During 2017, Leucrotta started to experiment with higher intensity fracs with several wells moving from the standard Leucrotta type curve well of 28 fracs used in 2016 to up to 51 stages used in the 9-33 well. The type curves, as referenced below, are based on 2016 reserve bookings by Leucrotta’s independent engineering firm, using then current drilling and completion techniques of one-mile laterals and a 28 stage slick water frac with 60 tonnes per stage of proppant. All the wells below have a lateral length of approximately one-mile with varying number of fracs. The results of the most recent wells are noted below.
Leucrotta recently tied in and started producing the 9-33 Lower Montney Turbidite Oil well that was completed with 51 fracs. The 9-33 well had an IP30 of 1,351 boepd comprised of 488 bopd of light oil, 4.5 mmcf/d of gas, and 118 boepd of ngls. This is 131% above Leucrotta’s IP30 type curve of 584 boepd that is comprised of 213 bopd of light oil, 1.9 mmcf/d of gas, and 50 boepd of ngls.
The A8-22 well (41 fracs) had an IP180 of 737 boepd comprised of 201 bopd of light oil, 2.8 mmcf/d of gas, and 73 boepd of ngls. This is 60% above Leucrotta’s IP180 type curve of 460 boepd that is comprised of 139 bopd of light oil, 1.7 mmcf/d of gas, and 43 boepd of ngls.
The 8-4 well (28 fracs) had an IP90 of 591 boepd comprised of 192 bopd of light oil, 2.1 mmcf/d of gas, and 54 boepd of ngls. This is 13% above Leucrotta’s IP90 type curve of 521 boepd that is comprised of 172 bopd of light oil, 1.8 mmcf/d of gas, and 47 boepd of ngls.
Leucrotta’s 4-12 Lower Montney Turbidite Liquids Rich Gas well (49 fracs) had an IP90 of 685 boepd comprised of 130 bopd of condensate, 2.9 mmcf/d of gas, and 75 boepd of ngls. This compares to Leucrotta’s IP90 type curve of 845 boepd that is comprised of 177 bopd of condensate, 3.5 mmcf/d of gas, and 84 boepd of ngls. Leucrotta had expected an uptick in production versus the curve given the number of fracs, however a mechanical failure during completion resulted in a material number of fracs being wholly or partially ineffective that resulted in suboptimal production conditions. The Company is highly encouraged by the performance of the well given the issues encountered.
LIGHT OIL FOCUS
Leucrotta has over 140 sections of land and a potential 900 drilling locations within its mapped area of the Lower Montney Turbidite horizon. Of the 140 sections, 80% is mapped within the light oil window with the other 20% in the condensate-rich gas window. Leucrotta’s capital budget will focus predominantly on finalizing geological delineation and well productivity within this large oil resource.
From a geological delineation perspective, the light oil pool is largely delineated given the significant amount of data collected by Leucrotta that is now integrated with older well logs available through public data. Leucrotta has determined that the turbidite reservoir, in terms of permeability and porosity, is relatively consistent throughout the 140 section block. Leucrotta plans to drill 2 vertical wells in 2018 to confirm the remaining mapping where data is currently not present.
Well productivity has improved materially with the refinement of the completion techniques as demonstrated in the A8-22 and 9-33 wells. These techniques will be used in subsequent wells as we drill to extend the proven productivity of the Lower Montney Turbidite over Leucrotta’s lands. In 2018, Leucrotta plans to drill 3 or 4 horizontal wells where productivity has not been previously established on Leucrotta’s lands. By the end of 2018, productivity will be substantially proven over the entire 140 section land block.
For 2019, Leucrotta would then move into the next phase of development and optimization that would include infill drilling and pad development in addition to looking at longer laterals and increased frac intensity.
Leucrotta had approximately $19 million of positive working capital at the end of 2017 and an undrawn bank credit facility of $20 million. Leucrotta estimates that it will be able to complete its capital program outlined above with cash flow and cash on hand.
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 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, 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.
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.
Any references to peak rates, test rates, IP30, IP90, IP180 or initial production rates or declines are useful for confirming the presence of hydrocarbons, however, such rates and declines are not determinative of the rates at which such wells will commence production and decline thereafter and are not indicative of long term performance or ultimate recovery. IP30 is defined as an average production rate over 30 consecutive days, IP90 is defined as an average production rate over 90 consecutive days and IP180 is defined as an average production rate over 180 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Corporation.
This news release contains references to type well, or “type curve”, production and economics, which are derived, at least in part, from available information respecting the well performance of other companies and, as such, may be considered “analogous information” as defined in NI 51-101. Production type curves are based on a methodology of analog, empirical and theoretical assessments and workflow with consideration of the specific asset, and as depicted in this presentation, is representative of the Company’s current program, including relative to current performance. Some of this data may not have been prepared by qualified reserves evaluators, may have been prepared based on internal estimates, and the preparation of any estimates may not be in strict accordance with COGEH. Estimates by engineering and geo-technical practitioners may vary and the differences may be significant. The Company believes that the provision of this analogous information is relevant to the Company’s oil and gas activities, given its acreage position and operations (either ongoing or planned) in the areas in question, and such information has been updated as of the date hereof unless otherwise specified.
The Montney Type Curves disclosed in this news release are an internal estimate prepared by a Qualified Reserves Evaluator (“QRE”) and are based on an average of the proved plus probable type curves used by GLJ for booked undeveloped horizontal wells in the Lower Montney formation as per the year-end 2016 corporate reserves evaluation effective December 31 2016. The curves represent an internal “best-estimate” expectation.
Potential Drilling Locations
This press 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 900 Lower Montney drilling locations referenced in this press release, only the following have been assigned reserves at December 31, 2016 as independently evaluated by GLJ, in accordance with National Instrument 51-101 (“NI 51-101”):
5 Proved Undeveloped
8 Probable Undeveloped
The remaining 887 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.
For further information, please contact:
LEUCROTTA EXPLORATION INC.
700, 639 –5th Ave SW
Calgary, Alberta T2P 0M9
Phone: (403) 705-4525
Fax: (403) 705-4526
President and Chief Executive Officer
Phone: (403) 705-4525
Vice President, Finance and Chief Financial Officer
Phone: (403) 705-4525
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