CALGARY, Alberta, Oct. 24, 2017 (GLOBE NEWSWIRE) — Leucrotta Exploration Inc. (“Leucrotta” or the “Company”) (TSXV:LXE) is pleased to announce the following update:
PRODUCTION ON 8-4 AND A8-22 LOWER MONTNEY TURBIDITE OIL WELLS
Leucrotta recently tied in and started producing the 8-4 Lower Montney Oil well. The 8-4 well had an IP30 of 747 boepd comprised of 317 bopd of light oil, 2.2 mmcf/d of gas, and 60 boepd of ngls. This compares favourably to 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. Note that this well was completed with 28 fracs versus the recently released A8-22 well noted below that had 41 fracs.
The A8-22 well has now produced beyond 90 days and had an IP90 of 838 boepd comprised of 254 bopd of light oil, 3.0 mmcf/d of gas, and 79 boepd of ngls as compared to 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. The A8-22 has produced significantly above expectations and we will continue to monitor the well to see what effect the success of this well will have on the ultimate recoveries and go forward economics of the play.
Note that the type curve as referenced above was based on 2016 reserve bookings by Leucrotta’s independent engineering firm, using then current drilling and completion technique of one-mile laterals and a 28 stage slickwater frac with 60 tonnes per stage of proppant.
Because of the success of A8-22, Leucrotta will look to further optimize the completion technique by increasing the number of frac stages to approximately 50 on its next 2 Lower Montney wells. Optimizing the completion technique is viewed as a critical step to proving up the ultimate value of the reserves as even a small change per well can be material when applied to Leucrotta’s large Montney land position (>100,000 acres).
Leucrotta’s Q317 production is estimated at approximately 3,000 boepd (27% oil and liquids). Pricing for the quarter averaged approximately $1.57 per mcf for gas (versus $1.45 for Aeco) and $50.65 per barrel for oil and liquids (89% of Edmonton Sweet).
Leucrotta is currently producing about 3,200 boepd with increases expected through Q4 as new wells come on-stream.
Leucrotta had approximately $28 million of positive working capital at the end of Q317 and an undrawn bank credit facility of $20 million. Leucrotta estimates that it will still have approximately $20 million positive working capital and no debt at year-end.
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 production, capital program, working capital and debt. 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 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 and IP90 is defined as an average production rate over 90 consecutive days. Readers are cautioned not to place reliance on such rates in calculating aggregate production for the Corporation.
This press 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 press 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.