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Hazloc Heaters
Copper Tip Energy Services
WEC - Western Engineered Containment
Copper Tip Energy
Hazloc Heaters
WEC - Western Engineered Containment

Leucrotta Announces Q3 2019 Financial and Operating Results

Calgary, Alberta–(Newsfile Corp. – November 27, 2019) – LEUCROTTA EXPLORATION INC. (TSXV: LXE) (“Leucrotta” or the “Company”) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2019. All dollar figures are Canadian dollars unless otherwise noted.


  • Achieved adjusted funds flow of $1.8 million in Q3 2019.
  • Maintained production at 3,065 boe/d in Q3 2019 from 3,119 boe/d in Q2 2019.
  • Maintained working capital of $2.2 million at September 30, 2019.
FINANCIAL RESULTS Three Months Ended September 30 Nine Months Ended September 30
($000s, except per share amounts) 2019 2018 % Change 2019 2018 % Change
Oil and natural gas sales 6,113 7,182 (15) 20,775 24,935 (17)
Cash flow from operating activities 950 1,975 (52) 8,367 12,485 (33)
  Per share – basic and diluted 0.01 (100) 0.04 0.06 (33)
Adjusted funds flow (1) 1,825 3,339 (45) 7,950 13,074 (39)
  Per share – basic 0.01 0.02 (50) 0.04 0.07 (43)
  Per share – diluted 0.01 0.02 (50) 0.04 0.06 (33)
Net (loss) earnings (1,181) (148) 698 611 118 418
  Per share – basic and diluted (0.01) (-) 100
Capital expenditures and acquisitions 2,841 12,155 (77) 10,837 26,015 (58)
Proceeds on sale of equipment (2) 1,625 100 4,767 100
Working capital 2,153 5,578 (61)
Common shares outstanding (000s)
  Weighted average – basic 200,525 200,522 200,525 200,518
  Weighted average – diluted 200,525 200,522 200,710 204,101 (2)
  End of period – basic 200,525 200,525
  End of period – fully diluted 226,646 227,082 (-)


(1) See “Non-GAAP Measures” section.
(2) The sale of equipment for proceeds of $4.8 million is exclusive of $2.7 million deposit received in Q4 2018.

OPERATING RESULTS (1) Three Months Ended September 30 Nine Months Ended September 30
2019 2018 % Change 2019 2018 % Change
Daily production
  Oil and NGLs (bbls/d) 829 888 (7) 838 989 (15)
  Natural gas (mcf/d) 13,414 14,724 (9) 13,669 16,066 (15)
  Oil equivalent (boe/d) 3,065 3,342 (8) 3,116 3,667 (15)
  Oil and NGLs ($/bbl) 47.81 64.32 (26) 51.96 63.71 (18)
  Natural gas ($/mcf) 2.00 1.42 41 2.38 1.76 35
  Oil equivalent ($/boe) 21.68 23.36 (7) 24.42 24.91 (2)
  Oil and NGLs ($/bbl) 5.97 (100) 2.05 (100)
  Natural gas ($/mcf)
  Oil equivalent ($/boe) 1.59 (100) 0.55 (100)
Net operating expenses (2)
  Oil and NGLs ($/bbl) 8.55 6.11 40 8.31 6.87 21
  Natural gas ($/mcf) 0.88 0.80 10 0.86 0.84 2
  Oil equivalent ($/boe) 6.17 5.13 20 6.01 5.52 9
Net transportation and marketing expenses (2)
  Oil and NGLs ($/bbl) 1.23 1.05 17 1.33 1.65 (19)
  Natural gas ($/mcf) 1.07 0.47 128 1.01 0.43 135
  Oil equivalent ($/boe) 4.99 2.36 111 4.79 2.32 106
Operating netback (2)
  Oil and NGLs ($/bbl) 38.03 51.19 (26) 42.32 53.14 (20)
  Natural gas ($/mcf) 0.05 0.15 (67) 0.51 0.49 4
  Oil equivalent ($/boe) 10.52 14.28 (26) 13.62 16.52 (18)
Depletion and depreciation ($/boe) (9.69) (9.60) 1 (9.53) (9.40) 1
General and administrative expenses ($/boe) (3.88) (3.56) 9 (4.16) (3.63) 15
Share based compensation ($/boe) (0.34) (1.58) (78) (0.61) (3.39) (82)
Gain (loss) on sale of equipment ($/boe) (0.41) 100 1.69 100
Finance expense ($/boe) (0.40) (0.25) 60 (0.33) (0.22) 50
Finance income ($/boe) 0.03 0.23 (87) 0.03 0.25 (88)
Net (loss) earnings ($/boe) (4.17) (0.48) 769 0.71 0.13 446


(1) See “Frequently Recurring Terms” section.
(2) See “Non-GAAP Measures” section.

Selected financial and operational information outlined in this news release should be read in conjunction with Leucrotta’s unaudited condensed interim financial statements and related Management’s Discussion and Analysis (“MD&A”) for the three and nine months ended September 30, 2019, which are available for review at


In Q3 2019, Leucrotta’s capital was spent predominantly on the initial upgrades of the recently acquired Two Rivers Facility. By early Q4 2019, all approvals were received to continue the expansion of the facility to accommodate the previously completed 10-08 Upper Montney well with an anticipated on-stream date of early February 2020. The 10-08 well is expected to add 800-1,000 boe/d (approximately 40% light oil) of initial production.

Production remained relatively stable at 3,065 boe/d for the quarter as wells continue to outperform expectations. Production is estimated to remain fairly flat throughout Q4 2019 with an increase in early 2020 when the 10-08 well is placed on production. Leucrotta’s product mix was 27% liquids for Q3 2019 with an estimated increase to over 40% liquids with focus on the volatile oil window combined with the installation of a gas plant capable of increased liquids extraction. Light oil and condensate ultimate recoveries (1) within the volatile light oil window are estimated at over 200 thousand barrels per well based on one-mile laterals. The substantial amount of oil recovered per well combined with low drilling cost yield a competitive finding and development (less than $20 per barrel) even when excluding all the associated gas and liquids.

Leucrotta maintained a strong balance sheet with $2.2 million net positive working capital and a $20 million credit facility at the end of Q3 2019. For the remainder of 2019 and into 2020, Leucrotta will remain conservative and protect the balance sheet given significant volatility seen in both the oil and gas markets. Leucrotta estimates it will continue to have positive working capital at year-end.

During Q4 2019, Leucrotta acquired additional gas transport at stated tolls that will allow the Company to deliver approximately 15 mmcf/d of gas into the Chicago market for 5 years. The delivery to this larger market will reduce the volatility previously experienced in the AECO market.

Leucrotta has been able to materially de-risk a large light oil resource in the Lower Montney over a minimum of 140 net sections of land and is working to de-risk additional Lower Montney lands as well as the Upper Montney and Basal Montney (Below Lower Montney) on Leucrotta’s land base. Infrastructure currently in place combined with up to 1,000 de-risked locations (2) will allow for Leucrotta to rapidly and materially increase production once the decision is made to move to the development phase.

We look forward to reporting on the results of the new wells and other business developments in the near future.

(1) See “Oil and Gas Metrics” section
(2) See “Potential Drilling Locations” section


The Company uses the following frequently recurring industry terms in this news release: “bbls” refers to barrels, “mcf” refers to thousand cubic feet, and “boe” refers to barrel of oil equivalent. Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in this news release. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.


This news release refers to certain financial measures that are not determined in accordance with IFRS (or “GAAP”). This news release contains the terms “adjusted funds flow”, “adjusted funds flow per share”, “operating netback”, “net operating expenses”, and “net transportation and marketing expenses” which do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. The Company uses these measures to help evaluate its performance.

Management considers adjusted funds flow to be a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and abandonment obligations and to repay debt, if any. Adjusted funds flow is a non-GAAP measure and has been defined by the Company as cash flow from operating activities excluding the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents adjusted funds flow per share whereby amounts per share are calculated using weighted average shares outstanding, consistent with the calculation of net earnings (loss) per share. Adjusted funds flow is reconciled from cash flow from operating activities under the heading “Cash Flow from Operating Activities and Adjusted Funds Flow” in the Company’s MD&A for the three and nine months ended September 30, 2019, which is available on SEDAR at

Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback, which is calculated as average unit sales price less royalties, net operating expenses, and net transportation and marketing expenses, represents the cash margin for every barrel of oil equivalent sold. Operating netback per boe is reconciled to net earnings per boe under the heading “Operating Netback”.

Net operating expenses is calculated as operating expenses less processing revenues. Management uses net operating expenses to determine the current periods’ cash cost of operating expenses less processing revenue and net operating expenses per boe is used to measure operating efficiency on a comparative basis. The measure approximates the Company’s operating expenses relative to its produced volumes by excluding third party operating costs.

Net transportation and marketing expenses is calculated as transportation expenses less marketing revenues. Management uses net transportation and marketing expenses to determine the current periods’ cash cost of transportation expenses less marketing revenue and net transportation and marketing expenses per boe is used to measure transportation efficiency on a comparative basis as well as the Company’s ability to mitigate the cost of excess committed capacity.


The estimated ultimate recoveries (EUR) referenced 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 estimates used by GLJ for booked undeveloped horizontal wells in the Lower Montney formation as per the year-end 2018 corporate reserves evaluation effective December 31 2018. The curves represent an internal “best-estimate” expectation.

EUR – Estimated Ultimate Recovery 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.


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 1000 total potential/possible locations referenced in the news release, only the following have been assigned reserves at December 31, 2018 as independently evaluated by GLJ, in accordance with National Instrument 51-101 (“NI 51-101”):

  • 19 Proved Undeveloped
  • 34 Probable Undeveloped

The remaining 947 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.


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 news release contains forward-looking statements and information relating to the Company’s risk management program, oil, NGLs, and natural gas production, capital programs, and working capital. 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.

Leucrotta is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in northeastern British Columbia, Canada.

Further Information

For additional information, please contact:

Mr. Robert J. Zakresky
President and Chief Executive Officer
(403) 705-4525

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

Leucrotta Exploration Inc.
Suite 700, 639 – 5th Avenue SW
Calgary, Alberta T2P 0M9
Phone: (403) 705-4525
Fax: (403) 705-4526

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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