3 September 2015
Mosman Oil and Gas Limited
("Mosman" or the "Company")
SPA signed to acquire NZ producing oil and gas assets
Mosman Oil and Gas Limited (AIM: MSMN) the New Zealand ("NZ") and Australia focussed oil exploration and development company, has today executed a conditional sale and purchase agreement ("SPA") to acquire onshore NZ producing oil and gas assets for NZ$10 million (approximately £4.2 million) (the "Acquisition" or the "Project").
Mosman has also today entered into a participation agreement ("STEP Agreement") with WRDLS Pty Ltd ("WRDLS"). WRDLS is a private company with resource and energy sector experienced personnel, including Dr Ray Shaw. Dr Shaw has more than 30 years' experience, including former Director, MD and Chairman Roles of resource companies listed on the Australian Securities Exchange Ltd. ("ASX"). WRDLS has agreed to acquire at least 30% of the Project.
Mosman's intention is to own at least 40% and no more than 70% of the Project and is actively considering further offers from potential JV partners.
The Acquisition remains subject to a number of matters including financing.
Acquisition Highlights
· The Project assets include fully operational and established oil and gas processing facilities, equipment, permits, excellent infrastructure, assignment of key employee contracts and the assignment of relevant commercial contracts including oil and gas sales contracts.
· It currently produces oil, condensate, gas, LPG and electricity, which deliver several revenue streams. The facilities were the subject to a major refurbishment in 2014 and since restart in October 2014 have been producing an average 603 boepd * which would generate annual revenue of approximately NZ$8 million based on current production rates, oil price and exchange rates.
· The Project will be renamed the South Taranaki Energy Project ("STEP"). It will be operated under a joint operating agreement ("JOA") and Mosman will be the operator. The assets being acquired include the Rimu Production Station and two petroleum mining permits ("PMP"). The Project also includes:
o 2P reserves of 1.9 Bcf gas and 1.4 MMbbl oil*
o 2C resources of 13.7 Bcf gas and 4.1 MMbbl oil*
o Prospective resources estimated at 179 Bcf and 166 MMbls*
· Historically the Project facility has produced over 10 Bcf (10.9 PJ) gas and 1.58 MMbbl oil*
· Mosman has identified 12 low cost projects that could potentially significantly increase production at an estimated cost of NZ$ 2.6 million. None of these projects require drilling of new wells (which will be considered in due course).
· Total consideration of NZ$10 million (approximately £4.2 million) to be paid in two tranches, the first tranche of NZ$7 million is payable upon completion of the Acquisition and the second tranche of NZ$3 million six months following completion. A 5% deposit was paid by Mosman upon executing the SPA. Mosman's total contribution towards the consideration for the Acquisition is subject to final percentage ownership. Based on 70% ownership, it would be NZ$7 million (approximately £2.9 million), the first tranche being NZ$4.9m (approximately £2.1m) and the second tranche being NZ$2.1m (approximately £0.9m). Mosman's first tranche of consideration will be reduced by the deposit of NZ$0.5M (approximately £0.2m), which deposit has been paid by Mosman in full.
· Mosman intends to finance its share of the Acquisition through a combination of existing cash, sale of a royalty on future production, debt, equity, and convertible securities.
· The SPA remains conditional upon a number of conditions precedent including: Mosman and its JV partners providing reasonable assurance of its financial capability to pay the total consideration due for the Project assets on or before 30 September 2015; and the granting of certain approvals from the NZ Government before settlement.
· Mosman's aggregate liability under the SPA is limited to NZ$7.5 million, for example should a JV party default on its obligations to Mosman after 30 September.
*Represents numbers supplied by Origin that have been subject to due diligence by Mosman. Prepared to be consistent with the Society of Petroleum Engineers definitions as set out in Appendix 2
The Chairman of Mosman, John W Barr, said: "We are delighted to have signed the SPA and the STEP agreement on a deal that the Board believes will be transformational for Mosman. Numerous opportunities to increase production in the short term have been identified and there is significant upside in development of the Manutahi oil field that originally had 30 million barrels of oil in place. *
Acquisition and Funding
Mosman has now signed the SPA to acquire the Project; paid a 5% deposit and entered into the STEP agreement. Each party will contribute a share of the consideration in proportion to their final ownership percentages in the Project.
The total consideration payable is NZ$10m (approximately £4.2m) which is payable in two tranches. The first tranche is due on completion of the Acquisition, and the second tranche is due six months following completion of the Acquisition.
Mosman has received a number of expressions of interest from other Companies seeking to participate in the Acquisition. Currently, due diligence is being undertaken and that may result in a change to the final ownership structure. It is not intended that Mosman will hold less than 40% or more than 70% of STEP.
Mosman intends to finance its share of the Acquisition through a combination of existing cash, sale of a royalty on future production, debt, equity, and convertible securities. Mosman is in receipt of term sheets for the proposed royalty and debt instruments. Further information will be provided when the Board completes its assessment of the various proposals.
Historical Financial Information
The STEP Project forms part of Origin's NZ operations which in turn are part of Origin's overall oil and gas operations. In addition, Origin applies a distribution of overheads to its various operations. Accordingly it has not been possible to isolate the STEP operations as a discrete financial reporting centre independent of the current corporate structure.
Mosman has prepared a ground up cash flow financial model taking into account current production; future production potential; oil and gas prices, exchange rates; fixed and variable costs; and operation development requirements such as 12 low-cost projects that could potentially increase production significantly at an estimated cost of NZ$ 2.6 million.
The Mosman cash flow model is dependent on many variables including the matters referred to above. It will also be influenced by the final funding arrangements which include existing cash, sale of royalty on future production, and debt and equity mix.
Given the planned reduction in current corporate overheads, and the anticipated operational success of the identified 12 low-cost upgrades referred to in this announcement, Mosman expects that STEP will be largely self-funding, apart from the NZ$2.6 million of investment referred to above.
Joint Operating Agreement ("JOA")
Mosman has a draft joint operating agreement with its partner on the Project, based on a standard oil field JOA.
The JOA provides for the establishment of an operating committee ("OC"), to provide for the overall supervision and direction of joint operations on the Project. Mosman and its partner will each appoint a representative to the OC.
Management and Operational Continuity Plan in Place
Mosman will be the operator and as part of that process it has retained key operational staff. Mosman's transition plans for the Acquisition provide it and stakeholders with the operational guidelines to manage the transition safely and efficiently.
An operations manager has been contracted by Mosman to implement the transition and approvals process.
Initial Production and Operational Upgrades
Having completed detailed due diligence, Mosman's technical team has identified areas that would have the potential to significantly increase production levels within a reasonable time period.
Mosman has verified and prioritised a list of 12 opportunities that are expected to increase production, following completion of the Acquisition, quickly and at modest cost, some of which are as simple as changing level sensors to avoid false alarms.
Initial production upgrade projects include:
· Restoring production to shut-in wells such as the two Rimu oil wells;
· Workover operations such as removing fluid and solids build up with coiled tubing;
· Reducing the frequency of production shut down at the Manutahi D pilot plant by connecting additional (existing) tanks
Subsequent Production Upgrades
The oil in the Manutahi field is in a good quality reservoir at modest depth of 1,100m and had OOIP of 30 million barrels*. The initial development wells were vertical wells. One of these has been a steady producer for more than ten years.
In a thermal water flood pilot containing one central oil producer and two water injector wells, Origin has also demonstrated that horizontal wells are effective producers flowing at several hundred of barrels of oil per day. This is a process known as Cold Heavy Oil Production with Sand ("CHOPS") which brings the fine solids to surface with the produced oil. Origin also demonstrated the benefits of re-injection of the hot produced water, which is expected to increase the recovery factor.
Mosman also intends to increase water injection (voidage replacement to maintain reservoir pressure) and develop the Manutahi oil field with horizontal wells. Whilst further work is required, initial studies confirm the Origin mapping and target recoverable oil of 4 million barrels*. Further studies will be conducted to consider the economics of increasing the recovery factor in due course.
Completion and Risks
The Acquisition remains conditional on a number of factors including financing and various NZ Government approvals. In addition to the purchase consideration, at completion the Acquisition will require initial working and development capital. Further risks are disclosed in appendix 4.
Competent Person's Statement
The information contained in this announcement has been reviewed and approved by Andy Carroll, Technical Director for Mosman, who has over 35 years of relevant experience in the oil industry. Mr Carroll is a member of the Society of Petroleum Engineers.
Enquiries
Mosman Oil & Gas Limited John W Barr, Executive Chairman Andy Carroll, Technical Director [email protected] [email protected] |
NOMAD and Broker SP Angel Corporate Finance LLP Stuart Gledhill / Richard Hail +44 (0) 20 3470 0470 |
Gable Communications Limited John Bick / Justine James +44 (0) 20 7193 7463 [email protected] |
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Updates on the Company's activities are regularly posted on its websitewww.mosmanoilandgas.com
About Mosman
Mosman (AIM: MSMN) is an Australia and New Zealand focused oil exploration and development company with a strategy to build a sustainable mid-tier oil and gas business by acquisition and organic growth. Currently, Mosman has a total of ten permits or accepted permit applications in New Zealand and Australia.
Petroleum Creek Project, New Zealand
Mosman owns 100% of permit PEP 38526, the Petroleum Creek Project, which is a 143 sq. km low cost onshore exploration project located near Greymouth on the South Island in the southern extension of the proven Taranaki oil system.
Taramakau, Murchison and East Coast Permits, New Zealand
These permits were granted to Mosman on 9 December 2014 as part of the 2014 Block Offer, a sixteen-fold increase in the exploration area in NZ from 143 sq. km to 2,317 sq. km.
Officer Basin Project, Australia (Application)
Mosman has a 25% investment in the Officer Basin Project, a 22,527 sq. km large land holding with significant exploration potential, which lies in one of the more explored parts of the Basin with road access. The project area is in the Western Australian part of the Officer Basin and offers both conventional and unconventional potential with hydrocarbon shows reported and all elements of a petroleum system are present.
Amadeus Basin Projects, Australia
Mosman owns 100% of two granted permits and one application in the Amadeus Basin in Central Australia which total of 5,458 sq. km. The Amadeus Basin is considered one of the most prospective onshore areas in the Northern Territory of Australia for both conventional and unconventional oil and gas, and hosts the producing Mereenie, Palm Valley and Surprise fields.
Otway Basin Project, Australia
Mosman owns 30% of VIC/P62 in the Otway Basin. The permit was recently renewed and is in relatively shallow water. The 70% permit holder funded a 3D seismic survey in 2013. The results of the 3D seismic survey are now being integrated into a geological model to allow identification and ranking of drilling targets. Within the Otway Basin there is commercial production both onshore and offshore.
APPENDIX 1
Glossary of Oil and Gas Terms
% |
per cent |
API |
American Petroleum institute gravity is a measure of how heavy or light a petroleum liquid is compared to water: if its API gravity is greater than 10, it is lighter and floats on water, if less than 10, it is heavier than water and sinks |
bbl |
barrel |
Bcf or BCF |
billion standard cubic feet of gas |
boep |
barrels of oil equivalent |
boepd |
barrels of oil equivalent per day |
CSG |
coal seam gas |
km |
kilometre |
m |
metre |
LPG |
liquefied petroleum gas |
Md or md |
millidarcy |
MMbbl |
million barrels of oil |
Mmboe |
million barrels of oil equivalent |
MMscf |
million standard cubic feet of gas |
MMscfd |
million standard cubic feet of gas per day |
NZP&M |
New Zealand Petroleum & Minerals, the New Zealand Government body charged with managing New Zealand's oil, gas, mineral and coal resources |
OOIP |
Oil originally in place |
PECPR Regulations |
Pressure Equipment, Cranes, and Passenger Ropeways Regulations, enacted by the NZ Government |
Permeability |
measure of the ease with which a fluid flows through a rock. The units are millidarcies or darcies |
Porosity |
measure of how much of a rock is open space. This space can be between grains or within cracks or cavities of the rock. Measured in %. |
PMP |
Petroleum Mining Permit |
Tcf |
trillion standard cubic feet of gas |
Tight Gas Formation |
a reservoir that cannot be produced at economic flow rates nor recover economic volumes of natural gas unless the well is stimulated by a large hydraulic fracture treatment or produced by use of a horizontal wellbore or multilateral wellbores |
APPENDIX 2
Category Definitions of Petroleum Reserves and Resources
For further details on the definitions and guidelines, please see the original document (Society of Petroleum Engineers (SPE), 2007)
The following Resources Classification Framework (taken from the World Petroleum Council) presents 1P 2P and 3P category definitions. Furthermore, it provides guidelines designed to promote consistency in resource assessments. The following summarizes the definitions for each Reserves category in terms of both the deterministic incremental approach and scenario approach and also provides the probability criteria if probabilistic methods are applied.
Resources Classification Framework
Proved Reserves are those quantities of petroleum, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations. If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.
Possible Reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than Probable Reserves. The total quantities ultimately recovered from the Project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P) Reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.
The "Range of Uncertainty" reflects a range of estimated quantities potentially recoverable from an accumulation by a project, while the vertical axis represents the "Chance of Commerciality", that is, the chance that the project that will be developed and reach commercial producing status.
The following definitions apply to the major subdivisions within the resources classification:
TOTAL PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production plus those estimated quantities in accumulations yet to be discovered (equivalent to "total resources").
DISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.
PRODUCTION is the cumulative quantity of petroleum that has been recovered at a given date. While all recoverable resources are estimated and production is measured in terms of the sales product specifications, raw production (sales plus non-sales) quantities are also measured and required to support engineering analyses based on reservoir voidage.
Multiple development projects may be applied to each known accumulation, and each project will recover an estimated portion of the initially-in-place quantities. The projects shall be subdivided into Commercial and Sub-Commercial, with the estimated recoverable quantities being classified as Reserves and Contingent Resources respectively, as defined below.
RESERVES are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria's: they must be discovered, recoverable, commercial, and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status.
CONTINGENT RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.
UNDISCOVERED PETROLEUM INITIALLY-IN-PLACE is that quantity of petroleum estimated, as of a given date, to be contained within accumulations yet to be discovered.
PROSPECTIVE RESOURCES are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity.
UNRECOVERABLE is that portion of Discovered or Undiscovered Petroleum Initially-in-Place quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur, the remaining portion may never be recovered due to physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
ESTIMATED ULTIMATE RECOVERY (EUR) is not a resources category, but a term that may be applied to any accumulation or group of accumulations (discovered or undiscovered) to define those quantities of petroleum estimated, as of a given date, to be potentially recoverable under defined technical and commercial conditions plus those quantities already produced (total of recoverable resources).
In specialized areas, such as basin potential studies, where alternative terminology has been used, the total resources may be referred to as Total Resource Base or Hydrocarbon Endowment. Total recoverable or EUR may be termed Basin Potential. The sum of Reserves, Contingent Resources and Prospective Resources may be referred to as "remaining recoverable resources". When such terms are used, it is important that each classification component of the summation also be provided. Moreover, these quantities should not be aggregated without due consideration of the varying degrees of technical and commercial risk involved with their classification.
Project-Based Resources Evaluations
The resources evaluation process consists of identifying a recovery project, or projects, associated with a petroleum accumulation(s), estimating the quantities of Petroleum Initially-in-Place, estimating that portion of those in-place quantities that can be recovered by each project, and classifying the project(s) based on its maturity status or chance of commerciality.
This concept of a project-based classification system is further clarified by examining the primary data sources contributing to an evaluation of net recoverable resources that may be described as follows:
Resources Classification
The basic classification requires establishment of criteria for a petroleum discovery and thereafter the distinction between commercial and sub-commercial projects in known accumulations (and hence between Reserves and Contingent Resources).
Determination of Discovery Status
A discovery is one petroleum accumulation, or several petroleum accumulations collectively, for which one or several exploratory wells have established through testing, sampling, and/or logging the existence of a significant quantity of potentially moveable hydrocarbons.
In this context, "significant" implies that there is evidence of a sufficient quantity of petroleum to justify estimating the in-place volume demonstrated by the well(s) and for evaluating the potential for economic recovery. Estimated recoverable quantities within such a discovered (known) accumulation(s) shall initially be classified as Contingent Resources pending definition of projects with sufficient chance of commercial development to reclassify all, or a portion, as Reserves.
Where in-place hydrocarbons are identified but are not considered currently recoverable, such quantities may be classified as Discovered Unrecoverable, if considered appropriate for resource management purposes, a portion of these quantities may become recoverable resources in the future as commercial circumstances change or technological developments occur.
Determination of Commerciality
Discovered recoverable volumes (Contingent Resources) may be considered commercially producible, and thus Reserves, if the entity claiming commerciality has demonstrated firm intention to proceed with development and such intention is based upon all of the following criteria:
· Evidence to support a reasonable timetable for development.
· A reasonable assessment of the future economics of such development projects meeting defined investment and operating criteria.
· A reasonable expectation that there will be a market for all or at least the expected sales quantities of production required to justify development.
· Evidence that the necessary production and transportation facilities are available or can be made available.
· Evidence that legal, contractual, environmental and other social and economic concerns will allow for the actual implementation of the recovery project being evaluated.
To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented.
To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.
Project Status and Commercial Risk
Evaluators have the option to establish a more detailed resources classification reporting system that can also provide the basis for portfolio management by subdividing the chance of commerciality axis according to project maturity. Such sub-classes may be characterized by standard project maturity level descriptions (qualitative) and/or by their associated chance of reaching producing status (quantitative).
As a project moves to a higher level of maturity, there will be an increasing chance that the accumulation will be commercially developed. For Contingent and Prospective Resources, this can further be expressed as a quantitative chance estimate that incorporates two key underlying risk components:
· The chance that the potential accumulation will result in the discovery of petroleum. This is referred to as the "chance of discovery"
· Once discovered, the chance that the accumulation will be commercially developed is referred to as the "chance of development".
Thus, for an undiscovered accumulation, the "chance of commerciality" is the product of these two risk components. For a discovered accumulation where the "chance of discovery" is 100%, the "chance of commerciality" becomes equivalent to the "chance of development".
Project Maturity Sub-Classes
Development projects (and their associated recoverable quantities) may be sub-classified according to project maturity levels and the associated actions (business decisions) required to move a project toward commercial production.
Project Maturity terminology and definitions have been modified from the example provided in the 2001 Supplemental Guidelines, Chapter 2. Detailed definitions and guidelines for each Project maturity sub-class are provided in Table I. This approach supports managing portfolios of opportunities at various stages of exploration and development and may be supplemented by associated quantitative estimates of chance of commerciality. The boundaries between different levels of project maturity may be referred to as "decision gates".
Decisions within the Reserves class are based on those actions that progress a project through final approvals to implementation and initiation of production and product sales. For Contingent Resources, supporting analysis should focus on gathering data and performing analyses to clarify and then mitigate those key conditions, or contingencies that prevent commercial development.
For Prospective Resources, these potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under appropriate development projects. The decision at each phase is to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity where a decision can be made to proceed with exploration drilling.
Evaluators may adopt alternative sub-classes and project maturity modifiers, but the concept of increasing chance of commerciality should be a key enabler in applying the overall classification system and supporting portfolio management.
Reserves Status
Once projects satisfy commercial risk criteria, the associated quantities are classified as Reserves. These quantities may be allocated to the following subdivisions based on the funding and operational status of wells and associated facilities within the reservoir development plan.
Developed Reserves are expected quantities to be recovered from existing wells and facilities.
Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
Undeveloped Reserves are quantities expected to be recovered through future investments.
Where Reserves remain undeveloped beyond a reasonable timeframe, or have remained undeveloped due to repeated postponements, evaluations should be critically reviewed to document reasons for the delay in initiating development and justify retaining these quantities within the Reserves class. While there are specific circumstances where a longer delay (see Determination of Commerciality, section 2.1.2) is justified, a reasonable time frame is generally considered to be less than 5 years.
Development and production status are of significant importance for project management. While Reserves Status has traditionally only been applied to Prove Reserves, the same concept of Developed and Undeveloped Status based on the funding and operational status of wells and producing facilities within the development project are applicable throughout the full range of Reserves uncertainty categories (Proved, Probable and Possible).
Quantities may be subdivided by Reserves Status independent of sub-classification by Project Maturity. If applied in combination, Developed and/or Undeveloped Reserves quantities may be identified separately within each Reserves sub-class (On Production, Approved for Development, and Justified for Development).
Economic Status
Projects may be further characterized by their Economic Status. All projects classified as Reserves must be economic under defined conditions.
Based on assumptions regarding future conditions and their impact on ultimate economic viability, projects currently classified as Contingent Resources may be broadly divided into two groups:
· Marginal Contingent Resources are those quantities associated with technically feasible projects that are either currently economic or projected to be economic under reasonably forecasted improvements in commercial conditions but are not committed for development because of one or more contingencies.
· Sub-Marginal Contingent Resources are those quantities associated with discoveries for which analysis indicates that technically feasible development projects would not be economic and/or other contingencies would not be satisfied under current or reasonably forecasted improvements in commercial conditions. These projects nonetheless should be retained in the inventory of discovered resources pending unforeseen major changes in commercial conditions.
Where evaluations are incomplete such that it is premature to clearly define ultimate chance of commerciality, it is acceptable to note that project economic status is "undetermined." Additional economic status modifiers may be applied to further characterize recoverable quantities; for example, non-sales (lease fuel, flare, and losses) may be separately identified and documented in addition to sales quantities for both production and recoverable resource estimates (see also Reference Point, section 3.2.1). Those discovered in-place volumes for which a feasible development project cannot be defined using current or reasonably forecast improvements in, technology are classified as Unrecoverable.
Economic Status may be identified independently of, or applied in combination with, Project Maturity sub-classification to more completely describe the project and its associated resources.
