24 September 2018
Mosman Oil and Gas Limited
("Mosman" or the "Company")
Two US Acquisitions and Baja Strategic Alliance Update
Mosman Oil and Gas Limited (AIM: MSMN) the oil exploration, development and production company, is pleased to announce two new acquisitions and provide an update to the Baja Strategic Alliance.
Mosman entered into a Strategic Alliance with Baja Oil and Gas LLC ("Baja") in July 2018. This Alliance led to the participation by Mosman in the Stanley-1 well in east Texas, which is now producing.
At the time Mosman noted that Baja owned a portfolio of oil and gas projects and was continuing to add projects to its inventory. Under the umbrella of the Strategic Alliance, Mosman would work with Baja to invest in the development of existing projects and to source and evaluate additional projects in Texas.
The results from the Stanley-1 well are most significant as the well penetrated multiple reservoir sands and provided evidence on logs of oil in multiple zones. Stanley-1 is now on production and the additional zones may be produced by the existing well in due course or production can be accelerated by drilling additional development wells. Two Mosman Directors recently visited the site in Texas, to see the Stanley-1 well and the production facilities. The well is producing through a separator to a permanent oil line to tanks and a temporary gas line to the sales gas meter. The current gas line has limited capacity and will be upgraded shortly as required to increase production.
The Company is working with Baja to optimize development of the oil zones identified by Stanley-1. The first follow up well, Stanley-2, is now in the planning stages and may be drilled in the next few months. Other development wells may follow in due course.
Project Acquisition and Strategic Alliance
Two Mosman Directors met with the Managing Partners of Baja in both Dallas and Houston to discuss all the Baja projects and to progress the Strategic Allaince. Mosman and Baja have now signed detailed Strategic Alliance documention that facilitates both companies working together on Baja projects, seeking new ventures in east Texas, and the contractual basis for technical work and operations on those projects with a Technical Services Agreement, all effective 1 September 2018. Mosman will have a 50% interest in all existing and new projects, other than the acquisition of interests in two existing projects (Champion and Challenger) where Baja has an interest in leases which are detailed below:
The Baja team have demonstrated they can source opportunities, negotiate lease positions, do the technical work to identify high return exploration and development projects in Texas, where the oil and gas business has social licence, existing infrastructure, low costs, and a well priced market for sale of production.
The significant advantage for Mosman with this Strategic Alliance is the synergy of working with Baja to source new projects, and to develop existing projects with a very strong local business development and technical team, without the cost of establishing such a team and the associated infrastructure.
Acquisition of 60% of the Champion Project
Mosman has agreed to acquire a 60% working interest in the 240 acre Champion Project for USD 108,000. This Project is also located in East Texas and has several drilling locations identified using the same 3D seismic techniques as Stanley-1. Baja retains the other 40% interest, and will be the Operator.
Acquisition of 16% of the Challenger Project
Mosman has also acquired a 16% working interest (half of Baja's 32% interest) in the 352 acre Challenger Project, in East Texas, for USD 43,500. This project includes a lease which is Held By Production (HBP) with two production wells in the Wilcox, with nominal periodic production. The intention is to use 3D seismic to identify development well locations within the existing lease area. A Reserve Report indicates the project has Reserves (gross) as follows (thousands of barrels of oil equivalent "MBOE"):
This Reserves Report was prepared by a third party independent petroleum engineering firm for Barry Lasker, a Managing Partner at Baja, in June 2017 and conforms to SPE-PRMS petroleum guidelines. The royalties on the lease are circa 25%.
Mosman and Baja will continue the technical and other work required to drill wells on these Projects. The first well locations are already identified and could be drilled as early as the first quarter 2019. Drilling locations are selected based on sub-surface technical work, and also locations with, or close to, existing production infrastructure are prioritised so that any successful well can be quickly completed and brought on production, as demonstrated by Stanley-1.
Stanley-2 and the two US acquisitions will be funded from existing cash resources.
John W Barr, Chairman, said:
"Given the significant results at Stanley-1, we have determined to prioritise existing resources towards the projects that hold the most chance of further increasing production and cashflows, which includes the potential Stanley-2 well, and the Champion and Challenger projects."
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.
Market Abuse Regulation (MAR) Disclosure
Certain information contained in this announcement would have been deemed inside information for the purposes of Article 7 of Regulation (EU) No 596/2014 until the release of this announcement.
Mosman Oil & Gas Limited
John W Barr, Executive Chairman
Andy Carroll, Technical Director
NOMAD and Broker
SP Angel Corporate Finance LLP
Stuart Gledhill / Richard Hail / Soltan Tagiev
+44 (0) 20 3470 0470
Gable Communications Limited
Justine James / John Bick
+44 (0) 20 7193 7463
SVS Securities Plc
Elliot Hance/Tom Curran
+44 (0) 203 700 0078
Updates on the Company's activities are regularly posted on its website www.mosmanoilandgas.com
Glossary of Oil and Gas Terms
a unit of land being 4,840 square yards
barrels of oil equivalent.
Thousand of barrels of oil equivalent.
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.
an estimated quantity of all hydrocarbons statistically defined as crude oil or natural gas, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Society of Petroleum Engineers-Petroleum Resources Management System.
means services providing specific engineering, geoscience, or other professional skills, such as those performed by engineers, geologists, geophysicists, and technicians, required to handle specific operating conditions and problems for the benefit of joint operations.
USD or $
United States Dollar.
(Extracted from Reserves Report)
Glossary of Oil and Gas Terms
Petroleum Reserves and Resources Classifications, Definitions, and Guidelines
Reference is made herein to the Petroleum Resources Management System approved by the Society of Petroleum Engineers (SPE) Board of Directors,March 2007.
Reference is made herein to the Petroleum Reserves and Resources Classification, Definitions and Guidelines jointly published in 2007 by SPE, the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE), hereinafter denoted as the SPE-PRMS Definitions.
Table 1: Recoverable Resources Classes and Sub-Classes
Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from the given date forward under defined conditions.
Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in the accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/ or characterized by their development and production status.
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 period.
A reasonable period 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 based on 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.
On Production: The development project is currently producing and selling petroleum to market.
The key is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project "chance of commerciality" can be said to be 100%.
The project "decision gate" is the decision to initiate commercial production from the project.
Approved for Development: All necessary approvals have been obtained, capital funds have been committed, and implementation of the development project is under way.
At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regularity approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity's current or following year's approved budget.
The project "decision gate" is the decision to start investing capital in the construction of production facilities and/ or drilling development wells.
Justified for Development: Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time reporting, and there are reasonable expectations that all necessary approvals/ contracts will be obtained.
In order to move this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity's assumptions of future prices, costs, etc. ("forecast case") and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable period will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regularity approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/ contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class).
The project "decision gate" is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time.
Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable 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 level of certainty associated with the estimates and may be sub-classified based on project maturity and/ or characterized by their economic status.
Development Pending: A discovered accumulation where project activities are ongoing to justify commercial development in the near future.
The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/ or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable period. Note that disappointing appraisal/ evaluation results could lead to a re- classification of the project to "On Hold" or "Not Viable" status.
The project "decision gate" is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.
Development Unclarified or in Hold: A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant.
The project is seen to have potential for eventual commercial development, but further appraisal/ evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/ evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to "Not Viable" status.
The project "decision gate" is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporary suspend or delay further activities pending resolution of external contingencies.
Development Not Viable: A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.
The project is not seen to have is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized inthe event of amajor change in technology or commercial conditions.
The project "decision gate" is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future.
Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.
Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily onanalog developments in the earlier phases of exploration.
Prospect: A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target.
Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program.
Lead: A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/ or evaluation in order to be classified as a prospect.
Project activities are focused on acquiring additional data and/ or undertaking further evaluation designed to confirm whether the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery under feasible development scenarios.
Play: A project associated with a prospective trend of potential prospects, but which requires more data acquisitions and/ or evaluation to define specific leads or prospects.
Project activities are focused on acquiring additional data and/ or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical scenarios.
Table 2: Reserves Status Definitions and Guidelines
Developed Reservesareexpected quantities to berecovered from existing wells and facilities.
Reserves are considered developed only after the necessary equipment has been installed, or when the costs of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reservesmaybefurther sub-classified asProducing orNon-Producing.
Developed Producing Reserves: Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.
Improved recovery reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves: Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.
Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from the zones in existing wells which will require additional completion work or future re-completion prior to start of production.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
Undeveloped Reserves are expected quantities expected to be recovered through future investments:
(1) from new wells on un-drilled acreage in known accumulations, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to (a) re-complete and existing well or (b) install production or transportation facilities for primary or improved recovery projects.
Table 3: Reserves Category Definitions and Guidelines
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 given date forward, from known reservoirs and under defined economic conditions, operating method, and government regulations.
If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities recovered will equal or exceed the estimate.
The area of the reservoir considered as Proved includes (1) the area delineated by drilling and defined by fluid contacts, if any, and (2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see"2001 Supplement Guidelines," Chapter 8).
Reserves in undeveloped locations may be classified as Proved if:
- The locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be productive.
- Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with the drilled Proved locations.
For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.
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.
Probable Reserves may be assigned to areas of a reservoir adjacent to Proved Reserves where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria.
Probable estimates also include incremental recoveries associated project recovery efficiencies beyond that assumed for Proved.
Possible Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered 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), which is equivalent to the high estimate scenario. 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.
Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project.
Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.
PROBABLE AND POSSIBLE RESERVES
(See above for separate criteria for Probable Reserves and Possible Reserves.)
The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/ or subject project that are clearly documented, including comparisons to results in successful similar projects.
In conventional accumulations, Probable and/ or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that structurally lower than the adjacent Proved or 2P area.
Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from known accumulation by non-productive reservoir (i.e. absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources.
In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/ or gas based on reservoir fluid properties and pressure gradient interpretations.
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