FOR: LEUCROTTA EXPLORATION INC.
TSX VENTURE SYMBOL: LXE
Date issue: April 03, 2017
Time in: 4:25 PM e
Attention:
CALGARY, ALBERTA–(Marketwired – April 3, 2017) – Leucrotta Exploration Inc.
(“Leucrotta” or the “Company”) (TSX VENTURE:LXE) is pleased to announce its
2016 year-end reserves as independently evaluated by GLJ Petroleum Consultants
Ltd. (“GLJ”) effective December 31, 2016 (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.
2016 Highlights
/T/
— Increased proved plus probable reserves by 32% to 22.7 million barrels
of oil equivalent (“boe”)
— Increased proved reserves by 25% to 10.2 million boe
— Reserve replacement of 1,566% on a proved plus probable basis and 644%
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 $7.00 per
boe
— Cumulative booked reserves on only 5 net sections of 141 net sections in
the Doe/Mica Montney Core area
— Subsequent to year-end, converted approximately 2.8 million boes from
the non-producing category to the producing category
/T/
Overview
Leucrotta continued its plan of spending capital on wide area delineation of
the Lower Montney Turbidite in the Doe/Mica area where it has accumulated 141
net sections of Montney land. Leucrotta has maintained a conservative
philosophy to booking reserves and has only booked locations immediately
offsetting previously drilled wells but covering a large geographic area. A
total of 2 new wells and 6 new locations were booked in the Doe East and Mica
areas in 2016 while leaving the Doe bookings static from 2015 to 2016. 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. Leucrotta also has the current financial capability
(assuming pricing and performance are comparable to the GLJ Report) to execute
on the $96 million of FDC included in the GLJ Report and therefore realize on
the values presented.
Leucrotta has estimated, based on mapping and other technical data, that it has
up to 780 potential Montney drilling locations (predominantly in the Lower
Montney Turbidite) of which 20 have been booked in the reserve report. 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. Should Leucrotta be able to obtain similar drilling results
on future wells, there is a large potential value to be booked and subsequently
realized on given Leucrotta’s large unbooked drilling inventory.
Leucrotta’s capital expenditures were focused predominantly in the Doe/Mica
area to expand its land base, improve and expand infrastructure, and start to
delineate its large Montney land base. Capital allocation by category is as
follows:
Capital Expenditures
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($000s) 2016 2015
—————————————————————————-
Undeveloped land 4,882 15,381
Facility equipment not in use and held for sale 2,784 18,040
Equipment disposition (4,000) –
Property disposition – (79,342)
—————————————————————————-
Sub-total acquisitions/dispositions 3,666 (45,921)
Drilling and completion 7,657 19,460
Facilities and related infrastructure 6,859 5,643
Geological, geophysical and other 392 713
—————————————————————————-
Sub-total capital expenditures 14,908 25,816
—————————————————————————-
Total all-in capital 18,574 (20,105)
—————————————————————————-
—————————————————————————-
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During 2016 the Company added Montney acreage adjacent to its Montney land base
through both Crown land sales and private land acquisitions as well as began
the pipeline system and infrastructure required to tie-in previously drilled
wells to the Company’s Doe gas plant. This pipeline and infrastructure spending
continued into Q1 2017 and four previously drilled wells were subsequently
tied-in and began producing. In the fourth quarter of 2016 the Company drilled
three wells (3.0 net) resulting in two successful light oil wells in Mica (one
completed in Q4 2016 and the other in Q1 2017) and one vertical test well.
Reserve Additions
Leucrotta continued to have positive results in its Montney delineation and
development in the Dawson area of British Columbia.
A total of eight additional wells were booked this year in the Mica and East
Doe areas and accounted for the majority of the reserve adds this year. Based
on the GLJ Report, the additional wells accounted for an increase of 2.4 mmboes
in the proved category and 6.0 mmboes in the proved plus probable category
Leucrotta has only booked reserves to a portion of 8 sections (5 net) of its
total 141 net sections of Montney land in the greater Dawson area. The bookings
leave a material amount of land for potential future bookings and provides for
a manageable amount of FDC booked ($95.7 million on a proved plus probable
basis) relative to Leucrotta’s current financial capabilities.
Reserves Summary
Leucrotta’s December 31, 2016 reserves as prepared by GLJ effective December
31, 2016 and based on the GLJ (2017-01) future price forecast are as follows
(1,4):
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—————————————————————————-
Conventional Shale
Working Light/ Natural Natural Total Oil
Interest Medium Oil Tight Oil Gas Gas NGLs Equivalent
Reserves (2) (Mbbl) (Mbbl) (Mbbl) (Mmcf) (Mbbl) (Mboe) (3)
—————————————————————————-
Proved
—————————————————————————-
Producing 55 79 52 5,756 197 1,299
—————————————————————————-
Developed
non-
producing 0 201 144 11,578 378 2,533
—————————————————————————-
Undeveloped 0 109 0 31,894 981 6,405
—————————————————————————-
Total proved 55 388 196 49,227 1,556 10,237
—————————————————————————-
Probable 22 391 53 60,520 1,948 12,456
—————————————————————————-
Total proved &
probable 77 780 250 109,747 3,504 22,693
—————————————————————————-
Notes:
(1) Numbers may not add due to rounding.
(2) “Working Interest” 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) See the Company’s Annual Information Form (“AIF”) available on SEDAR
at www.sedar.com for the disclosure of Net reserves. “Net” reserves
means Leucrotta’s working interest (operated and non-operated) share
after deduction of royalties, plus Leucrotta’s royalty interest in
reserves.
/T/
Reserves Values
The estimated future net revenues before taxes associated with Leucrotta’s
reserves effective December 31, 2016 and based on the GLJ (2017-01) future
price forecast are summarized in the following table (1,2,3,4):
/T/
—————————————————————————-
Discount factor per year
—————————————————————————-
($000s) 0% 5% 10% 15% 20%
—————————————————————————-
Proved
—————————————————————————-
Producing 13,359 11,474 10,097 9,062 8,262
—————————————————————————-
Developed Non-producing 38,813 29,060 22,724 18,423 15,371
—————————————————————————-
Undeveloped 78,618 50,658 34,851 25,177 18,833
—————————————————————————-
Total proved 130,790 91,193 67,671 52,662 42,466
—————————————————————————-
Probable 231,069 130,389 84,053 59,322 44,511
—————————————————————————-
Total proved & probable 361,859 221,582 151,725 111,985 86,977
—————————————————————————-
Notes:
(1) Numbers may not add due to rounding.
(2) The estimated future net revenues are stated prior to provision for
interest, debt service charges or general administrative expenses and
after deduction of royalties, operating costs, estimated well
abandonment and reclamation costs and estimated future capital
expenditures.
(3) The estimated future net revenue contained in the table does not
necessarily represent the fair market value of the reserves. There is
no assurance that the forecast price and cost assumptions contained
in the GLJ Report will be attained and variations could be material.
The recovery and reserve estimates described herein are estimates
only. Actual reserves may be greater or less than those calculated.
(4) See the Company’s AIF available on SEDAR at www.sedar.com for the
after-tax present values of future net revenue attributed to
Leucrotta’s reserves.
/T/
Price Forecast
The GLJ (2017-01) price forecast is as follows:
/T/
—————————————————————————-
WTI Oil @ Edmonton Light AECO Natural Foreign
Cushing Oil Gas Exchange
Year ($US / Bbl) ($Cdn / Bbl) ($Cdn / Mmbtu) (US$/Cdn$)
—————————————————————————-
2017 55.00 69.33 3.46 0.750
—————————————————————————-
2018 59.00 72.26 3.10 0.775
—————————————————————————-
2019 64.00 75.00 3.27 0.800
—————————————————————————-
2020 67.00 76.36 3.49 0.825
—————————————————————————-
2021 71.00 78.82 3.67 0.850
—————————————————————————-
2022 74.00 82.35 3.86 0.850
—————————————————————————-
2023 77.00 85.88 4.05 0.850
—————————————————————————-
2024 80.00 89.41 4.16 0.850
—————————————————————————-
2025 83.00 92.94 4.24 0.850
—————————————————————————-
2026 86.05 95.61 4.32 0.850
—————————————————————————-
Escalate
thereafter (1) 2.0% per year 2.0% per year 2.0% per year
—————————————————————————-
Note:
(1) Escalated at two per cent per year starting in 2026 in the January 1,
2017 GLJ price forecast with the exception of foreign exchange, which
remains flat.
/T/
Reserve Life Index (“RLI”)
Leucrotta’s RLI presented below is based on Q4 2016 average production of 824
boepd.
/T/
—————————————————————————-
Reserve Category RLI
—————————————————————————-
Proved plus Probable Reserves 75.5
—————————————————————————-
Proved 34.0
—————————————————————————-
/T/
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 $11.55 per boe on a proved basis and $7.00 on a proved plus
probable basis.
FD&A costs, including FDC, were $13.05 per boe on a proved basis and $7.62 on a
proved plus probable basis. The three-year comparative which normalizes the
period costs was $31.59 on a proved basis and $11.27 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 2014 to 2016 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 2014 to 2016 were negatively affected.
Leucrotta has presented FD&A and F&D costs below.
/T/
—————————————————————————-
2016 2015 3 Year Average
($000’s, except Proved & Proved & Proved &
where noted) Proved Probable Proved Probable Proved Probable
—————————————————————————-
F&D costs (excluding
net acquisitions/
dispositions)
Exploration and
development
expenditures 14,908 14,908 25,816 25,816 71,740 71,740
Change in FDC (1) 13,269 26,642 (7,251) (13,642) 34,670 64,659
—————————————————————————-
F&D costs excluding
net acquisitions/
dispositions
(Including FDC) 28,177 41,550 18,565 12,174 106,410 136,399
FD&A costs
(including net
acquisitions/
dispositions)
Exploration and
development
expenditures 14,908 14,908 25,816 25,816 71,740 71,740
Net acquisitions
(dispositions) 3,666 3,666 (45,921) (45,921) 29,596 29,596
—————————————————————————-
FD&A costs
including net
acquisitions/
dispositions 18,574 18,574 (20,105) (20,105) 101,336 101,336
Change in FDC 13,269 26,642 (43,795) (60,077) (1,874) 18,224
—————————————————————————-
FD&A costs including
net acquisitions/
dispositions
(Including FDC) 31,843 45,216 (63,900) (80,182) 99,462 119,560
Reserve Additions
(Mboe) (2)
Exploration and
development 2,440 5,933 1,299 1,880 9,230 19,596
Net acquisitions/
dispositions – – (6,708) (9,796) (6,081) (8,992)
—————————————————————————-
Total Reserve
Additions 2,440 5,933 (5,409) (7,916) 3,149 10,604
F&D costs excluding
net acquisitions/
dispositions
($/boe)
Excluding FDC 6.11 2.51 19.87 13.73 7.77 3.66
Including FDC 11.55 7.00 14.29 6.48 11.53 6.96
FD&A costs ($/boe)
Excluding FDC 7.61 3.13 3.72 2.54 32.18 9.56
Including FDC 13.05 7.62 11.81 10.13 31.59 11.27
—————————————————————————-
—————————————————————————-
Notes:
(1) 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.
(2) Sum of drilling extensions, technical revisions and economic factors
in the reserves reconciliation included in the Company’s AIF
available on SEDAR at www.sedar.com.
(3) Leucrotta was incorporated on June 10, 2014. Leucrotta commenced
active oil and natural gas operations on August 6, 2014 as a result
of the closing of a plan of arrangement involving Leucrotta, Crocotta
Energy Inc. (“Crocotta”), Long Run Exploration Ltd. and shareholders
of Crocotta, whereby Crocotta transferred its oil and natural gas
assets located in British Columbia (“BC Assets”) to Leucrotta. The
exploration and development expenditures, acquisitions expenditures,
and reserve additions presented above include those of Leucrotta from
July 10, 2014 as well as prior periods up to August 6, 2014 from the
transferred BC Assets on a carve-out basis as if they had operated as
a stand-alone entity subject to Crocotta’s control.
/T/
For Leucrotta’s full NI 51-101 disclosure related to its 2016 year-end reserves
please refer to the Company’s AIF available on SEDAR at www.sedar.com.
Forward-Looking Information
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 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, 2016,
available on SEDAR at www.sedar.com.
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 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 780 total potential/possible Montney locations referenced in page 1 of
this press release, only the following have been assigned reserves at December
31, 2016 as independently evaluated by GLJ, in accordance with NI 51-101:
/T/
— 9 Proved Undeveloped
— 11 Probable Undeveloped
/T/
The remaining 760 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
BOEs 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.
NON-GAAP Measures
Netback per barrel and its components are calculated by dividing revenue,
royalties, operating and sales and transportation expenses by the gross
production volume during the period. Netback per barrel is a non-GAAP measure
and it is commonly used by oil and gas companies to illustrate the unit
contribution of each barrel produced.
Unaudited Financial Information
Certain financial and operating results included in this news release such as
FD&A costs, F&D costs, recycle ratio, capital expenditures, historical cost of
undeveloped land, 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, 2016, 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, 2016 on SEDAR on or before April 30, 2017.
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, “recycle ratio”, 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). The
Company uses this measure to determine how long the booked reserves will last
at current production rates if no further reserves were added.
“Recycle ratio” is calculated by dividing the operating netback (in dollars per
boe for the most recent quarter) by the FD&A costs (in dollars per boe) for the
year. The Company uses recycle ratio as an indicator of profitability of its
oil and gas activities.
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.
– END RELEASE – 03/04/2017
For further information:
Leucrotta Exploration Inc.
Robert Zakresky
President and Chief Executive Officer
(403) 705-4525
(403) 705-4526 (FAX)
OR
Leucrotta Exploration Inc.
Nolan Chicoine
Vice President, Finance and Chief Financial Officer
(403) 705-4525
(403) 705-4526 (FAX)
www.leucrotta.ca
COMPANY:
FOR: LEUCROTTA EXPLORATION INC.
TSX VENTURE SYMBOL: LXE
INDUSTRY: Energy and Utilities – Oil and Gas
RELEASE ID: 20170403CC0097
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