CALGARY, ALBERTA–(Marketwired – April 27, 2017) – LEUCROTTA EXPLORATION INC. (TSX VENTURE:LXE) (“Leucrotta” or the “Company”) is pleased to announce its financial and operating results for the three months and year ended December 31, 2016. All dollar figures are Canadian dollars unless otherwise noted.
- Materially extended the mapping and productive boundaries of the Lower Montney Turbidite Light Oil Resource Play with the drilling of three delineation wells (two horizontal and one vertical).
- Expanded pipeline/infrastructure system in Q4 2016 and into Q1 2017 with four previously drilled wells being put on-stream in Q1 2017.
- Maintained a cash and working capital balance of $26.1 million at December 31, 2016.
- Subsequent to year-end entered into a purchase and sale agreement to acquire certain lands located within the Company’s core Doe/Mica area for an aggregate cash purchase price of approximately $36.0 million. The acquisition is expected to close on or about May 31, 2017.
- Subsequent to year-end entered into an agreement with a syndicate of underwriters with respect to an offering of common shares and flow-through common shares by way of a short form prospectus for gross proceeds of $80.0 million (the “Offering”). The Offering is for an aggregate of 33,333,400 common shares at a price of $2.25 per common share and 1,852,000 common shares on a flow-through basis at a price of $2.70 per flow-through common share, closing on April 26, 2017.
|Three Months Ended December 31||Year Ended December 31|
|($000s, except per share amounts)||2016||2015||% Change||2016||2015||% Change|
|Oil and natural gas sales||2,281||2,819||(19||)||8,844||10,859||(19||)|
|Funds (used in) from operations (1)||(98||)||464||(121||)||(996||)||615||(262||)|
|Per share – basic and diluted||–||–||–||(0.01||)||–||(100||)|
|Net (loss) earnings||(1,657||)||(15,205||)||(89||)||(12,182||)||11,412||(207||)|
|Per share – basic and diluted||(0.01||)||(0.09||)||(89||)||(0.07||)||0.07||(200||)|
|Capital expenditures and acquisitions||11,718||29,544||(60||)||22,574||59,237||(62||)|
|Sale of gas plant equipment||–||–||–||4,000||–||100|
|Common shares outstanding (000s)|
|Weighted average – basic and diluted||165,227||165,227||–||165,227||165,227||–|
|End of period – basic||165,227||165,227||–|
|End of period – diluted||189,297||189,272||–|
(1) See “Non-GAAP Measures” section.
|OPERATING RESULTS (1)||Three Months Ended December 31||Year Ended December 31|
|2016||2015||% Change||2016||2015||% Change|
|Oil and NGLs (bbls/d)||234||479||(51||)||317||316||–|
|Natural gas (mcf/d)||3,543||3,585||(1||)||4,325||6,112||(29||)|
|Oil equivalent (boe/d)||824||1,076||(23||)||1,038||1,335||(22||)|
|Oil and NGLs ($/bbl)||53.60||46.85||14||45.04||45.74||(2||)|
|Natural gas ($/mcf)||3.46||2.29||51||2.30||2.50||(8||)|
|Oil equivalent ($/boe)||30.08||28.47||6||23.35||22.29||5|
|Oil and NGLs ($/bbl)||6.99||8.90||(21||)||4.69||6.91||(32||)|
|Natural gas ($/mcf)||0.16||0.12||33||0.06||0.08||(25||)|
|Oil equivalent ($/boe)||2.68||4.37||(39||)||1.67||1.98||(16||)|
|Oil and NGLs ($/bbl)||26.24||16.58||58||18.52||12.58||47|
|Natural gas ($/mcf)||1.76||0.96||83||1.27||1.16||9|
|Oil equivalent ($/boe)||15.02||10.56||42||10.96||8.29||32|
|Oil and NGLs ($/bbl)||6.04||5.35||13||5.24||4.54||15|
|Natural gas ($/mcf)||0.47||0.32||47||0.44||0.30||47|
|Oil equivalent ($/boe)||3.71||3.46||7||3.43||2.47||39|
|Operating netback (2)|
|Oil and NGLs ($/bbl)||14.33||16.02||(11||)||16.59||21.71||(24||)|
|Natural gas ($/mcf)||1.07||0.89||20||0.53||0.96||(45||)|
|Oil equivalent ($/boe)||8.67||10.08||(14||)||7.29||9.55||(24||)|
|Depletion and depreciation ($/boe)||(13.07||)||(52.91||)||(75||)||(13.07||)||(17.67||)||(26||)|
|Asset impairment ($/boe)||–||(83.53||)||(100||)||–||(18.91||)||(100||)|
|General and administrative expenses ($/boe)||(11.08||)||(7.50||)||48||(11.11||)||(9.46||)||17|
|Share based compensation ($/boe)||(7.11||)||(10.82||)||(34||)||(9.36||)||(11.02||)||(15||)|
|Finance expenses ($/boe)||(0.81||)||(0.46||)||76||(0.49||)||(0.49||)||–|
|Finance income ($/boe)||1.54||2.26||(32||)||1.35||1.38||(2||)|
|Loss (gain) on sale of assets ($/boe)||–||(3.35||)||(100||)||(6.77||)||93.19||(107||)|
|Deferred tax expense ($/boe)||–||(7.28||)||(100||)||–||(23.14||)||(100||)|
|Net (loss) earnings ($/boe)||(21.86||)||(153.51||)||(86||)||(32.16||)||23.43||(237||)|
(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 audited financial statements and related Management’s Discussion and Analysis (“MD&A”) for the year ended December 31, 2016, which are available on SEDAR at www.sedar.com.
In Q4 2016 and early Q1 2017, Leucrotta completed its infrastructure project to tie-in four previously drilled delineation wells and has drilled three additional step-out/delineation wells that materially extend the productive boundaries of the Company’s Lower Montney Turbidite Light Oil Resource Play.
As a result of the tie-in of four wells, Leucrotta increased production to over 3,000 boe/d (25% oil and NGLs). This excludes two new Montney wells (8-4 and 12-06) that are tested but not tied-in and one well (13-07) that is temporarily shut-in due to third party restrictions.
The three step-out/delineation wells materially extended the productive boundaries of the Lower Montney Turbidite Light Oil Resource Play. The 8-4 well was drilled 5.2 km north and west of the previously drilled 8-22 well. The well encountered light oil in the Lower Montney Turbidite zone and was tested over a 7-day period with an average production of 1,060 boe/d(1). The 12-06 well was drilled 11.7 kms south of the 13-07 oil well and 4.4 kms north of the 13-19 liquids-rich gas well. The well encountered oil pay and was tested over a 7-day period with average production of 550 boe/d(1). The third step-out /delineation well was a vertical stratigraphic test drilled at 4-30 north of the Peace River. Located 7.4 km northwest of the 8-4 well, the well was logged and cored in the Upper, Middle and Lower Montney. The well encountered 55 metres of pay in the Lower Montney with core porosities on par with the core porosities in the 13-7 well. The 4-30 vertical well confirms the geological mapping and oil charge of a major northern extension of the Lower Montney Turbidite Light Oil Resource Play. Analysis of Upper and Middle Montney in the 4-30 wellbore showed potential as exploratory future targets.
Subsequent to year-end, Leucrotta signed agreements to acquire an additional 18.5 sections of land located in its core Doe/Mica Montney area and initiated a bought-deal financing for gross proceeds of $80 million to fund the acquisition and a portion of the future capital programs. Leucrotta has estimated that it will have approximately $50 million of cash and no debt on completion of the financing and funding the land acquisitions.
On a go forward basis, Leucrotta will continue its capital program focused primarily on the delineation and development of its Doe/Mica core area.
(1) See “Test Results and Production Rates” section.
FREQUENTLY RECURRING TERMS
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 “funds from (used in) operations”, “funds from (used in) operations per share”, and “operating netback” 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 uses funds from (used in) operations to analyze performance and considers it a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from (used in) operations is a non-GAAP measure and has been defined by the Company as cash flow from (used in) operating activities excluding the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents funds from (used in) operations per share whereby amounts per share are calculated using weighted average shares outstanding, consistent with the calculation of earnings (loss) per share. Funds from (used in) operations is reconciled from cash flow from (used in) operating activities under the heading “Funds from (used in) Operations” in the Company’s MD&A for the year ended December 31, 2016, which is available on SEDAR at www.sedar.com.
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, production expenses, and transportation expenses, represents the cash margin for every barrel of oil equivalent sold. Operating netback per boe is reconciled to net loss per boe under the heading “Operating Netback” in the Company’s MD&A for the year ended December 31, 2016, which is available on SEDAR at www.sedar.com.
TEST RESULTS AND PRODUCTION RATES
The 8-4-82-14W6 well was production tested for 7 days after the original cleanup and produced at an average rate of 1,060 boe/d (50% gas, 50% Oil and Condensate) over that period, excluding load fluid and energizing fluid. At the end of the test, flowing wellhead pressure and production rates were stable.
The 12-6-81-13W6 well was production tested for 7 days after the original cleanup and produced at an average rate of 550 boe/d (60% gas, 40% Oil and Condensate) over that period, excluding load fluid and energizing fluid. At the end of the test, flowing wellhead pressure and production rates were stable.
A pressure transient analysis or well-test has not been carried out on these wells and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery.