CALGARY, March 5, 2012 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX-V:YGR) is pleased to announce the results of its independent reserves evaluation effective December 31, 2011 as prepared by AJM Deloitte in accordance with the requirements prescribed by National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities.
Reserve Report Highlights:
- Proved plus probable reserves, net present value discounted at 10% ("NPV 10") at December 31, 2011 was $156.1 million, an increase of 94% compared to December 31 2010.
- Increased proved plus probable reserves by 65% to 8.7 million barrels of oil equivalent (7.8 million barrels of working interest and 0.9 million barrels for the royalty interest) and proved reserves by 117% to 5.5 million barrels of oil equivalent (4.8 million barrels of working interest and 0.7 million barrels for the royalty interest).
- The proven reserves component of proved plus probable reserves has increased to 63% from 48% in 2010.
- Replaced 2011 production by 672% on a proved basis and 782% on a proved plus probable basis.
- Achieved finding and development costs of $21.83 per proved plus probable barrel of oil equivalent excluding changes in future development costs ($24.79/boe including changes in future development costs).
- Generated a finding and development recycle ratio of 1.80 times, excluding changes in future development costs, (1.59 times including changes in future development costs) on proved plus probable reserves based on the Company's estimated 2011 operating netback of $39 per barrel of oil equivalent.
- Reserve life index of 10.5 years on a total proved plus probable basis based on the Company's December, 2011 production rate of 2,270 boe/d.
- The Company owned 15% royalty interest has an undiscounted value of $52.9 million ($28.8 million NPV 10) on a proved plus probable basis in the reserve report.
Capital Program Update
The Company's 2011 capital expenditures were approximately $64 million versus the originally budgeted amount of $50 million. The 2011 capital program included the following items:
- The Company drilled 13 gross (9.83 net) operated horizontal wells during 2011 as planned, however working interests were higher than anticipated due to partners going penalty on several wells.
- The Company participated in 14 non-operated wells, with the original budget identifying 6 non-operated wells.
- The Company drilled two unplanned vertical wells and completed a standing well to assist in advancement of new pools and to manage land expiries. Based on the information from these wells Yangarra was able to proceed with industries' first horizontal well into the SWS formation using current horizontal drilling and completion techniques.
- 92 sections of land were purchased during 2011, including the significant position the Company has established in the Duvernay play.
- Year end working capital deficiency, excluding non cash items, is estimated to be $34 million, against a $40 million credit facility.
Oil and Gas Reserves
The following tables summarize certain information contained in the independent reserves report prepared by AJM Deloitte as of December 31, 2011. The report was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook") and National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). Additional reserve information as required under NI 51-101 will be included in the Company's Annual Information Form which will be filed on SEDAR by April 30, 2012.
Summary of Oil and Gas Reserves
(based on forecast price and costs)
|Reserves Category|| Light and
| Natural Gas
|Proved Developed Producing||759||812||695||246||301||225||6,924||8,573||7,464|
|Proved Developed Non-Producing||35||40||33||21||30||21||1,451||1,713||1,465|
|Total Proved Plus Probable||2,203||2,298||1,932||866||993||748||28,660||32,496||28,485|
|Reserves Category|| Total BOE
as at December 31, 2011
| Total BOE
as at December 31, 2010
|Proved Developed Producing||2,159||2,542||2,164||553||598||507|
|Proved Developed Non-Producing||298||355||299||249||274||220|
|Total Proved Plus Probable||7,846||8,706||7,427||5,054||5,267||4,495|
Notes to table:
|(1)||Total values may not add due to rounding.|
|(2)||In the case of BOEs, using BOEs derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl).|
|(3)||"Working Interest Gross" reserves are the Company's working interest (operating or non-operating) share before deducting royalty obligations and without including any royalty interests of the Company.|
|(4)||"Company Share Gross" reserves are the Company's working interest (operating or non-operating) share and before deducting royalty obligations but including any royalty interests of the Company.|
|(5)||"Net" Reserves are the Company's working interest (operating or non-operating) share after deduction of royalty obligations plus any royalty interests of the Company.|
Summary of Net Present Values of Future Net Revenue (Before Tax)
(based on forecast price and costs)
|As At December 31, 2011(2)|| As At
|Reserves Category|| 0.0%
|Proved Developed Producing||98,958||79,604||67,283||13,734|
|Proved Developed Non-Producing||7,910||6,267||5,198||5,996|
|Total Proved Plus Probable||287,304||203,754||156,145||80,670|
Notes to table:
|(1)||Total values may not add due to rounding.|
|(2)||Forecast pricing used is based on AJM Deloitte published price forecasts effective December 31, 2011.|
|(3)||Forecast pricing used is based on AJM Deloitte published price forecasts effective December 31, 2010.|
|(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.|
|(5)||It should not be assumed that the net present values of future net revenues estimated by AJM Deloitte represent fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material.|
|(a)||"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.|
|(b)||"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.|
|(c)||"Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production.|
|(d)||"Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.|
|(e)||"Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.|
|(f)||"Undeveloped" reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned.|
|(g)||The Net Present Value (NPV) is based on AJM Deloitte Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the AJM Deloitte evaluations will be attained, and variances could be material.|
Finding and Development Costs ("F&D")
Yangarra's F&D costs for 2011, 2010 and the three year average are presented in the tables below. 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. The 2011 costs are unaudited as the financial results are in the process of being finalized; and, are subject to change upon completion of the audited financial statements.
Proved Finding & Development Costs ($ millions)
|2011||2010||2008 - 2011|
|Change in future capital||10.3||17.1||29.8|
|Total capital for F&D||74.3||39.3||118.9|
|Reserve additions, net (Mboe)||2,514||1,141||3,953|
|Proved F&D costs - including future capital ($/boe)||29.56||34.38||30.07|
|Proved F&D costs - excluding future capital ($/boe)||25.45||19.43||22.54|
|Proved Recycle Ratio|
|Including future capital||1.33||0.69|
|Excluding future capital||1.55||1.22|
Proved plus Probable Finding & Development Costs ($ millions)
|2011||2010||2008 - 2010|
|Change in future capital||8.7||30.9||45.0|
|Total capital for F&D||72.7||53.1||134.1|
|Reserve additions, net (Mboe)||2,932||1,891||5,353|
|Proved plus Probable F&D costs - including future capital ($/boe)||24.79||28.08||25.05|
|Proved plus Probable F&D costs - excluding future capital ($/boe)||21.83||11.73||16.64|
|Proved plus Probable Recycle Ratio|
|Including future capital||1.59||0.84|
|Excluding future capital||1.80||2.02|
The Company is planning to release its 2011 year-end financial and operating results early April 2012.
Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas.
Certain information regarding Yangarra set forth in this news release, including management's assessment of future plans, operations and operational results may constitute forward-looking statements under applicable securities law and necessarily involve risks associated with oil and gas exploration, production, marketing and transportation such as loss of market, volatility of prices, currency fluctuations, imprecision of reserves estimates, environmental risks, competition from other producers and ability to access sufficient capital from internal and external sources. As a consequence, actual results may differ materially from those anticipated in the forward-looking statements.
The initial production rates discussed in this press release are not necessarily indicative of long-term performance or of ultimate recovery due to high initial decline rates.
All reference to $ (funds) are in Canadian dollars.
Neither the TSX Venture Exchange nor its Regulation Service Provider (as that term is defined in the Policies of the TSX Venture Exchange) accepts responsibility for the adequacy and accuracy of this release.
For further information:
James Evaskevich, President and CEO, at (403) 262-9558.