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
- 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
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
| ($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 | ) | ||
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):
| Working Interest Reserves (2) | Light/ Medium Oil (Mbbl) |
Tight Oil (Mbbl) |
Conventional Natural Gas (Mbbl) |
Shale Natural Gas (Mmcf) |
NGLs (Mbbl) |
Total Oil Equivalent (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. | |
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):
| Discount factor per year | ||||||
| ($000s) | 0% | 5% | 10% | 15% | 20% | |
| Proved | ||||||
| Producing | 13,359 | 11,474 | 10,097 | 9,062 | 8,262 | |
| Developed Non-producing | 38,813 | 29,060 | 22,724 | 18,423 | 15,371 | |
| Undeveloped | 78,618 | 50,658 | 34,851 | 25,177 | 18,833 | |
| Total proved | 130,790 | 91,193 | 67,671 | 52,662 | 42,466 | |
| Probable | 231,069 | 130,389 | 84,053 | 59,322 | 44,511 | |
| Total proved & probable | 361,859 | 221,582 | 151,725 | 111,985 | 86,977 | |
| Notes: | ||
| (1) | Numbers may not add due to rounding. | |
| (2) | The estimated future net revenues are stated prior to provision for interest, debt service charges or general administrative expenses and after deduction of royalties, operating costs, estimated well abandonment and reclamation costs and estimated future capital expenditures. | |
| (3) | The estimated future net revenue contained in the table does not necessarily represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions contained in the GLJ Report will be attained and variations could be material. The recovery and reserve estimates described herein are estimates only. Actual reserves may be greater or less than those calculated. | |
| (4) | See the Company’s AIF available on SEDAR at www.sedar.com for the after-tax present values of future net revenue attributed to Leucrotta’s reserves. | |
Price Forecast
The GLJ (2017-01) price forecast is as follows:
| Year | WTI Oil @ Cushing ($US / Bbl) |
Edmonton Light Oil ($Cdn / Bbl) |
AECO Natural Gas ($Cdn / Mmbtu) |
Foreign Exchange (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. | |
Reserve Life Index (“RLI”)
Leucrotta’s RLI presented below is based on Q4 2016 average production of 824 boepd.
| Reserve Category | RLI |
| Proved plus Probable Reserves | 75.5 |
| Proved | 34.0 |
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.
| 2016 | 2015 | 3 Year Average | |||||||||||
| ($000’s, except where noted) | Proved | Proved & Probable |
Proved | Proved & Probable |
Proved | Proved & Probable |
|||||||
| F&D costs (excluding net acquisitions/ dispositions) | |||||||||||||
| Exploration and development expenditures | 14,908 | 14,908 | 25,816 | 25,816 | 71,740 | 71,740 | |||||||
| Change in FDC (1) | 13,269 | 26,642 | (7,251 | ) | (13,642 | ) | 34,670 | 64,659 | |||||
| F&D costs excluding net acquisitions/ dispositions (Including FDC) | 28,177 | 41,550 | 18,565 | 12,174 | 106,410 | 136,399 | |||||||
| FD&A costs (including net acquisitions/ dispositions) | |||||||||||||
| Exploration and development expenditures | 14,908 | 14,908 | 25,816 | 25,816 | 71,740 | 71,740 | |||||||
| Net acquisitions (dispositions) | 3,666 | 3,666 | (45,921 | ) | (45,921 | ) | 29,596 | 29,596 | |||||
| FD&A costs including net acquisitions/ dispositions | 18,574 | 18,574 | (20,105 | ) | (20,105 | ) | 101,336 | 101,336 | |||||
| Change in FDC | 13,269 | 26,642 | (43,795 | ) | (60,077 | ) | (1,874 | ) | 18,224 | ||||
| FD&A costs including net acquisitions/ dispositions (Including FDC) | 31,843 | 45,216 | (63,900 | ) | (80,182 | ) | 99,462 | 119,560 | |||||
| Reserve Additions (Mboe) (2) | |||||||||||||
| Exploration and development | 2,440 | 5,933 | 1,299 | 1,880 | 9,230 | 19,596 | |||||||
| Net acquisitions/ dispositions | – | – | (6,708 | ) | (9,796 | ) | (6,081 | ) | (8,992 | ) | |||
| Total Reserve Additions | 2,440 | 5,933 | (5,409 | ) | (7,916 | ) | 3,149 | 10,604 | |||||
| F&D costs excluding net acquisitions/ dispositions ($/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. | |
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:
- 9 Proved Undeveloped
- 11 Probable Undeveloped
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.
Robert Zakresky
President and Chief Executive Officer
(403) 705-4525
(403) 705-4526 (FAX)
Leucrotta Exploration Inc.
Nolan Chicoine
Vice President, Finance and Chief Financial Officer
(403) 705-4525
(403) 705-4526 (FAX)
www.leucrotta.ca
