Mr. Jim Evaskevich reports
YANGARRA ANNOUNCES 2018 YEAR END CORPORATE RESERVES INFORMATION
Yangarra Resources Ltd. has released the results of the 2018 year-end oil and gas reserves evaluation.
In 2018, Yangarra drilled 36 wells with a continued emphasis on developing new areas through exploration and further delineation of existing areas. Of the 36 wells drilled, 30 wells were brought on production in 2018, with the remaining six wells put on production in early 2019 as oil price differentials improved.
As previously disclosed, Yangarra spent a significant amount of infrastructure capital in 2018 and, as a result, expects a smoother quarterly production growth profile going forward. This infrastructure build also reduced year-over-year operating costs as reflected in the 2018 reserve report.
The company's PDP-plus-PNP (proved developed producing plus proved non-producing) NAV (net asset value) grew by 119 per cent to $3.28 per share.
Reserve report highlights
The independent reserves report prepared by Deloitte LLP is effective as of Dec. 31, 2018. All reserves information contained in this press release is based on the 2018 reserve report. Unless specifically indicated, all financial and operational information in this press release is based on estimates and is unaudited and, accordingly, such financial information is subject to change based on the results of the company's audit.
Proved developed producing (PDP) reserves:
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23.4 million barrels of oil equivalent (96-per-cent increase from 2017);
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Net present value before tax discounted at 10 per cent (NPV10) of $393-million (93-per-cent increase from 2017), including abandonment capital for producing and non-producing wells of $8-million;
-
Finding and development costs of $10.15 per barrel of oil equivalent, resulting in a PDP recycle ratio of 2.7 times;
- PDP net asset value per fully diluted common share of $2.75;
-
PDP additions replaced 434 per cent of 2018 production.
Proved non-producing (PNP) reserves:
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1.9 million barrels of oil equivalent;
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NPV10 of $47-million;
-
The majority of the PNP value consists of the six wells that were drilled before year-end but not completed; four of these wells are now producing and the remainder are expected to be brought on stream before the end of February.
Total proved reserves (1P):
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75.5 million barrels of oil equivalent (35-per-cent increase from 2017);
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NPV10 of $1.12-billion (55-per-cent increase from 2017);
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1P future development costs of $393-million;
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Finding and development costs of $6.63 per barrel of oil equivalent, resulting in a recycle ratio of 4.1 times;
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1P NAV per FD share of $11.01;
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1P reserve life index (RLI) based on 2018 fourth quarter production of 17.0 years;
-
1P additions replaced 672 per cent of 2018 production.
Proved plus probable reserves (2P):
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126.3 million barrels of oil equivalent (44-per-cent increase from 2017);
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NPV10 of $1.69-billion (64-per-cent increase from 2017);
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2P future development costs of $607-million;
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Finding and development costs of $4.90 per barrel of oil equivalent, resulting in a recycle ratio of 5.6 times;
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2P NAV per FD share of $17.46;
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2P reserve life index (RLI) of 28.4 years;
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2P additions replaced 1,220 per cent of 2018 production.
Oil and gas reserves
The attached tables summarize certain information contained in the 2018 reserve report. The 2018 reserve report encompasses 100 per cent of Yangarra's oil and gas properties and was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities, by Deloitte.
Deloitte used its Dec. 31, 2018, price forecasts of $58 (U.S.) per barrel WTI (West Texas Intermediate) and $60 (U.S.) per barrel WTI for light oil ($65.80 per barrel and $71.05 per barrel for Edmonton Par) for 2019 and 2020, respectively, and $1.75 per thousand cubic feet and $2.15 per thousand cubic feet for AECO natural gas in 2019 and 2020, respectively.
SUMMARY OF OIL AND GAS RESERVES (1) (2)
(company share gross volumes based on forecast price and costs)
Reserves category Light and Natural gas Natural Total boe Total boe
medium oil liquids gas 2018 2017
(mbbl) (mbbl) (mmcf) (mboe) (mboe)
Proved developed
Producing 5,211 5,028 79,043 23,412 11,965
Proved developed
non-producing 730 327 5,157 1,917 684
Proved undeveloped 13,624 10,278 157,656 50,178 43,217
Total proved 19,565 15,632 241,856 75,507 55,866
Probable 13,051 10,739 162,049 50,799 32,023
Total proved
plus probable 32,617 26,371 403,905 126,305 87,889
Notes:
(1) Total values may not add due to rounding.
(2) Barrels of oil equivalent are derived by converting gas to oil equivalent
in the ratio of 6,000 cubic feet of gas to one barrel of oil.
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE (BEFORE TAX) (1) (4)
(based on forecast price and costs)
As at
As at Dec. 31, 2018 (2) Dec. 31,
2017 (3)
Reserves category 0% 5% 10% 15% 20% 10%
(M$) (M$) (M$) (M$) (M$) (M$)
Proved developed
producing $ 599,868 $ 473,024 $ 393,103 $ 338,640 $ 299,286 $ 203,513
Proved developed
non-producing 68,895 55,691 47,202 41,331 37,036 10,993
Proved undeveloped 1,361,923 936,893 678,893 510,805 395,185 507,455
Total proved 2,030,686 1,465,608 1,119,198 890,776 731,506 721,962
Probable 1,731,291 925,108 566,699 380,463 272,280 304,626
Total proved
plus probable 3,761,978 2,390,716 1,685,897 1,271,239 1,003,786 1,026,588
Notes:
(1) Total values may not add due to rounding.
(2) Forecast pricing used is based on Deloitte's published price forecasts
effective Dec. 31, 2018.
(3) Forecast pricing used is based on Deloitte's published price forecasts
effective Dec. 31, 2017.
(4) Cash flows include the effects of the current Alberta royalty framework.
The estimated future net reserves are stated before deducting future estimated
site restoration costs and are reduced for future abandonment costs and
estimated capital for future development associated with the reserves.
Finding and development (F&D)
costs
Yangarra's F&D costs for 2018, 2017 and the three-year average are presented in the attached tables. The costs used in the F&D calculation are the capital costs related to: land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties. Due to the timing of capital costs and the subjectivity in the estimation of future costs, 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 reserve additions for that year. The reserves used in this calculation are company net reserve additions, including revisions.
PROVED DEVELOPED PRODUCING FINDING AND DEVELOPMENT COSTS
(in millions of dollars)
2018 2017 2016 to 2018
Capital expenditures 151.0 83.0 265.0
Reserve additions, net production (mboe) 14,878 6,213 24,395
Proved developed producing F&D costs
-- including future capital ($/boe) 10.15 13.36 10.86
Proved recycle ratio ($27.30/boe operating netback) 2.69 2.10
Proved finding and development costs ($ millions) 2018 2017 2016 to 2018
Capital expenditures 151.0 83.0 265.0
Change in future capital 1.9 140.8 198.3
Total capital for F&D 152.9 223.8 463.3
Reserve additions, net production (mboe) 23,072 21,504 57,404
Proved F&D costs -- including future capital ($/boe) 6.63 10.41 8.07
Proved F&D costs -- excluding future capital ($/boe) 6.54 3.86 4.62
Proved recycle ratio ($27.30/boe operating netback)
Including future capital 4.12 2.69
Excluding future capital 4.17 7.25
Proved plus probable finding and development costs ($ millions) 2018 2017 2016 to 2018
Capital expenditures 151.0 83.0 265.0
Change in future capital 54.2 186.3 339.9
Total capital for F&D 205.2 269.3 604.9
Reserve additions, net production (mboe) 41,84 729,349 92,307
Proved plus probable F&D costs -- including future capital ($/boe) 4.90 9.18 6.55
Proved plus probable F&D costs -- excluding future capital ($/boe) 3.61 2.86 2.87
Proved plus probable recycle ratio ($27.30/boe operating netback)
Including future capital 5.57 3.05
Excluding future capital 7.57 9.90
NET ASSET VALUE (NAV)
As at Dec. 31, 2018 PDP Total proved Proved plus
probable
Present value reserves, before tax
(discounted at 10 per cent) ($ million) $ 393.0 $1,119.2 $1,685.9
Total net debt ($ million) (unaudited) (155.0) (155.0) (155.0)
Proceeds from the exercise of options (2) 3.4 3.4 3.4
Net asset value 241.4 967.6 1,534.3
Fully diluted common shares
outstanding (million) 87.9 87.9 87.9
Net asset value per share $2.75 $11.01 $17.46
Notes:
(1) The preceding table shows what is customarily referred to as a produce-out
net asset value calculation, under which the current value of Yangarra's reserves
would be produced at the Deloitte forecast future prices and costs. The value is
a snapshot in time as at Dec. 31, 2018, and is based on various assumptions,
including commodity prices and foreign exchange rates that vary over time.
In this analysis, the present value of the proved and probable reserves is
calculated at a before-tax 10-per-cent discount rate.
(2) The calculation of proceeds from exercise of stock options and the diluted
number of common shares outstanding only include stock options that are in the
money based on the closing price of Yangarra of $2.62 as at Dec. 31, 2018.
(3) Net debt or adjusted working capital (deficit), which represent current assets
less current liabilities, excluding current derivative financial instruments, are
used to assess efficiency, liquidity and the general financial strength of the
company. There is no IFRS (international financial reporting standards) measure
that is reasonably comparable with net debt or adjusted working capital (deficit).
Year-end disclosure
The financial statements for the year ended Dec. 31, 2018, are scheduled to be released on March 7, 2019.
Additional reserve information as required under National Instrument 51-101 will be included in the company's annual information form, which will be filed on SEDAR on or before March 31, 2019.
We seek Safe Harbor.
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