HOUSTON, TX--(Marketwired - Dec 31, 2013) - EFLO Energy, Inc. ("EFLO" or the "Company") (
The following summarizes certain reserve information based on an independent assessment by Deloitte LLP ("Deloitte") effective August 31, 2013 using pricing forecasts effective June 30, 2013 (the "EFLO Deloitte Reserve Report"). The EFLO Deloitte Reserve 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"). Reserve information required under NI 51-101 and effective for the EFLO's fiscal year ended August 31, 2013 has been included in NI 51-101 forms which have been filed in Canada on the System for Electronic Document Analysis and Retrieval (SEDAR) at www.sedar.com.
SUMMARY OF RESERVES
|Before Tax Net Present Value ($Cdn) Discounted @|
|Oil and NGL's (Mbbl)||Gas (MMcf)||Combined (Mboe)||0%||5%||10%||15%|
|Proved Developed Producing||-||-||-||-||-||-||-|
|Total Proved plus Probable||-||17,732||2,956||19,177||14,483||10,900||8,167|
|Total Proved plus Probable plus Possible||-||25,547||4,259||43,937||31,826||23,384||17,405|
Gas prices for the report were based on delivery and sale at Station 2 in British Columbia. The EFLO Deloitte Reserve Reports base case forecast effective June 30, 2013 is as follows: 2014 - $3.45; 2015 - $3.75; 2016 - $4.05; 2017 - $4.35; 2018 - $4.80; 2019 - $5.10; 2020 - $5.5.45; 2021 - $5.80; 2022 - $6.15; and thereafter escalated at 2% per annum. Prices are in Canadian dollars per Mcf.
NOTICE REGARDING PRESENTATION OF THE COMPANY'S RESERVE INFORMATION
The determination of reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserve classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability, statistics and deterministic and probabilistic estimation methods is required to properly use and apply reserve definitions.
Disclosure in this document of reserves is presented in accordance with NI 51-101 as prescribed by Canadian securities laws. Following is a summary of the principal differences between the methodology and other requirements applicable under NI 51-101 and those applicable under corresponding U.S. standards:
- NI 51-101 requires the use and application of terminology, estimation standards, and classification frameworks contained in the COGEH Handbook, whereas issuers reporting in accordance with U.S. standards prepare estimates in accordance with SEC rules and regulations (and corresponding FASB requirements, as applicable) and generally accepted industry practices in the United States;
- NI 51-101 requires disclosure of both proved and probable reserves, and permits the disclosure of possible reserves at the issuer's discretion, whereas U.S. standards require disclosure of proved reserves only but provide for the option, at the issuer's discretion, to disclose probable and possible reserves;
- NI 51-101 requires disclosure of reserves and related future net revenue estimates based on forecast prices and costs, whereas U.S. standards require that reserves and related future net revenue be estimated using constant prices and costs (with prices based on a historical 12-month average price;
- NI 51-101 requires proved undeveloped reserves to be drilled within two or three years (depending on the magnitude of the capital expenditures required for development) and probable undeveloped reserves within five years of the date of the evaluation, whereas SEC rules and regulations require proved undeveloped reserves to be drilled within five years of the date the reserves were recorded (unless the specific circumstances justify a longer time);
- technical reserves estimation standards applicable under NI 51-101 and the COGEH Handbook differ from those applicable under U.S. standards with respect to, among other things, the use of reliable technology, aerial extent around a drilled location, quantities below the lowest known oil, and quantities across an undrilled fault block;
- under NI 51-101, reserves may be recognized on undrilled properties beyond directly offsetting spacing units if there is "compelling evidence of reservoir continuity," which may be interpreted differently under U.S. standards that limit reserve bookings on undrilled acreage to "those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances";
- NI 51-101 requires reserves to show a hurdle rate of return, whereas U.S. standards require reserves to be cash flow positive on an undiscounted basis;
- NI 51-101 requires disclosure of more reserves categories and product types than U.S. standards, which require disclosure of reserves by country or geographic area;
- NI 51-101 requires the disclosure of aggregate proved plus probable reserves and related future net revenue, whereas U.S. standards do not allow proved and probable reserves to be aggregated; and
- NI 51-101 requires that issuers engaged, directly or indirectly, in oil and gas activities to appoint a qualified reserves evaluator or auditor, who must be independent of the issuer, to report to the board of directors on the issuer's reserves data, whereas U.S. standards leave the engagement of third party reserves consultants to the discretion of an issuer's board of directors.
The foregoing summary provides a general description only of the principal differences between the methodology and other requirements applicable under NI 51-101 and those applicable under U.S. standards, and is not exhaustive of all differences. The differences between NI 51-101 and U.S. standards, and their effect on the estimation and reporting of reserves, future net revenue and other oil and gas-related information disclosed thereunder, may be material.
DISCLOSURE OF RESERVES
All evaluations of future revenue are after the deduction of royalties, development costs, production costs and well abandonment costs but before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses.
The reserves estimates and related estimates of net present values presented in this document were prepared to comply with Canadian reserves disclosure standards and reserves definitions as set out in NI 51-101 and the COGE Handbook prepared jointly by The Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).
Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on:
- 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:
- Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. Often, the actual quantities recovered will exceed the estimated proved reserves;
- Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. The actual quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves; and
- Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.
Each of the reserves categories (proved, probable and possible) may be divided into developed and undeveloped categories:
- 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
- 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.
- 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.
- Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, the cost of drilling and completing 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.
In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.
The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level or the sum of individual entity estimates for which reserves estimates are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:
- at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
- at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and
- at least a 10 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.
Additional clarification for the classification of reserves and the certainty levels associated with reserves estimates is provided in the COGE Handbook.
This news release includes forward-looking statements, including but not limited to estimates of reserves and resources and the present value of revenues associated with such reserves and resources. Statements in this news release relating to reserves and resources involve the implied assessment, based on certain estimates and assumptions, that the described reserves and resources, as the case may be, exist in the quantities predicted or estimated, and can be profitably produced in the future. There is no assurance that the forecast price and cost assumptions contained in the Deloitte reports will be realized and variances could be material. Other assumptions and qualifications relating to project schedules, costs and other matters are inherent in these estimates.
In addition, all statements other than statements of historical facts, included in this news release that address activities, events, or developments that the Company believes or anticipates will or may occur in the future are forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other factors, which may cause the actual results, performance or achievements expressed or implied by such forward-looking statements. Such factors include general economic and business conditions, the ability to acquire and develop specific projects and reach commercially acceptable terms with counterparties, the ability to secure government and other third party approval, potential third party claims, the ability to fund operations, and other factors over which the Company has little or no control. The Company does not intend to update publicly any forward-looking statements, except as may be required by law.
The contents of this news release should be considered in conjunction with the warnings and cautionary statement contained in the Company's public filings, which are accessible on SEDAR at www.sedar.com.
In this news release:
(a) in relation to the Company's interest in production or reserves, its working interest share before deduction of royalties;
(b) in relation to wells, the total number of wells in which the Company has an interest; and
(c) in relation to properties, the total area of properties in which the Company has an interest.
(a) in relation to the Company's interest in production or reserves, its working interest share after deduction of royalty obligations;
(b) in relation to the Company's interest in wells, the number of wells obtained by aggregating the Company's working interest in each of its gross wells; and
(c) in relation to the Company's interest in a property, the total area of properties in which the Company has an interest multiplied by the working interest owned by the Company.
In this news release: (i) Mcf means thousand cubic feet; (ii) Mcf/d means thousand cubic feet per day; (iii) MMcf means million cubic feet; (iv) MMcf/d means million cubic feet per day; (v) bbls means barrels; (vi) Mbbls means thousand barrels; (vii) MMbbls means million barrels; (viii) bbls/d means barrels per day; (ix) Bcf means billion cubic feet; (x) Mboe means thousand barrels of oil equivalent; (xi) MMboe means million barrels of oil equivalent; (xii) boe means barrels of oil equivalent; and (xiii) boe/d means barrels of oil equivalent per day.
Boe means barrel of oil equivalent on the basis of 1 boe to 6,000 cubic feet of natural gas. References to boe may be misleading, particularly if used in isolation. A boe conversion ratio of 1 boe for 6,000 cubic feet to natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
ON BEHALF OF THE BOARD OF DIRECTORS
EFLO Energy, Inc.