TIDMMSMN
RNS Number : 2813L
Mosman Oil and Gas Limited
18 April 2018
18 April 2018
Mosman Oil and Gas Limited
("Mosman" or the "Company")
Welch Project Proved Reserves
Mosman Oil and Gas Limited (AIM: MSMN) the oil exploration,
development and production company, is pleased to announce Proved
Reserves at the Welch Permian Basin Project ("Welch") in Texas.
Highlights
-- Welch Proved Reserves (1P) of 234,000 barrels oil (gross)
with a NPV10% value of USD $2.007 million.
-- Included in the Proved Reserves at Welch are incremental
Proved Undeveloped Reserves of 102,000 barrels with and NPV10%
value of USD $0.597 million for a single proposed horizontal oil
well, that represents an encouraging potential development
opportunity.
-- Welch meets the Company's stated strategy of delivering
operating cash flow and having development upside.
Moyes & Co's Reserves Report on Welch
Independent expert, Moyes and Co, has reported the Proved
Reserves at Welch under the under SPE PRMS definitions to be
234,000 barrels of oil (gross).
The identified incremental Proved Undeveloped Reserves for a
horizontal well represent an encouraging development opportunity
for Mosman. In parallel with continuing to operate Welch to
optimise cash flow, Mosman will progress with the previously
announced economic evaluation of a horizontal well development
programme in support of a drilling decision in 2018.
Only one horizontal well has been included in the Moyes and Co
reserves report at Welch but the Company believes up to three
horizontal wells may be possible. A final decision by the Board on
a horizontal well is subject to completion of the Company's
economic evaluation, a development plan, permitting, prevailing
economic conditions and funding alternatives.
Summary details of the Proved Reserves at Welch are as
follows:
Proved Reserves at Welch*
------------------------------- -------------------------------------------------------------------
Category Oil (Gross) Natural Oil (Net) Net Present Value
Gas (MMcf)
(BBL (BBL 10% discount rate(US$000)
000) 000)
------------------------------- ----------- ------------ --------- -----------------------------
Proved Developed Producing 109 0 84 1,162
------------------------------- ----------- ------------ --------- -----------------------------
Proved Developed Non-Producing 23 0 19 247
------------------------------- ----------- ------------ --------- -----------------------------
Proved Undeveloped 102 17 79 597
------------------------------- ----------- ------------ --------- -----------------------------
Total Proved (1P) 234 17 182 2,007
------------------------------- ----------- ------------ --------- -----------------------------
Notes (*):
i. Source: Moyes & Co Reserves Report on the Welch Project dated 17 April 2018
ii. Operator: Mosman Oil and Gas Limited
iii. Company's Working Interest: 100%
iv. NPV10%: Uses a USD $65 per barrel flat WTI oil price
assumption and unescalated gas price of $2.80 per MMBTU. The
potential economic value of the above Reserves will, in part,
depend on the Company's chosen field development plan and operating
strategy which is currently being evaluated.
v. The estimates of proved reserves and future revenue in this
report have been prepared in accordance with the SPE/WPC/SPEE PRMS
guidelines.
Moyes & Co's Reserves Report on Welch will shortly be
available on the Company's website.
John W Barr, Chairman, said: "Welch meets the stated strategy of
delivering operating cash flow and having development upside.
"We are pleased to achieve this milestone of Proved Reserves
that underpins our view that Welch was a sound acquisition, at the
right time, and where we have added value in less than 12 months.
Importantly, the Proved Reserves identified at Welch should provide
a basis for being able to obtain bank debt to assist in funding
further production growth. Looking forward at Welch, we continue to
evaluate horizontal wells with the objective of having a
development plan to put before the Board later in 2018."
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.
Enquiries:
Mosman Oil & Gas Limited NOMAD and Broker
John W Barr, Executive Chairman SP Angel Corporate Finance LLP
Andy Carroll, Technical Director Stuart Gledhill / Richard Hail
jwbarr@mosmanoilandgas.com / Soltan Tagiev
acarroll@mosmanoilandgas.com +44 (0) 20 3470 0470
Gable Communications Limited
Justine James / John Bick
+44 (0) 20 7193 7463
mosman@gablecommunications.com
Updates on the Company's activities are regularly posted on its
website www.mosmanoilandgas.com
Glossary
The following Glossary and definitions of oil and gas reserves
is extracted from the Moyes & Co Reserves Report on the Welch
Project dated 17 April 2018. All figure numbers and page references
herein refer to that Report.
Definitions of Oil and Gas Reserves
Adapted from the 2007 Petroleum Resources Management System
(PRMS) Approved by the Society of Petroleum Engineers (SPE)
Petroleum Resources Classification Framework
Petroleum is defined as a naturally occurring mixture consisting
of hydrocarbons in the gaseous, liquid, or solid phase. Petroleum
may also contain non-hydrocarbons, common examples of which are
carbon dioxide, nitrogen, hydrogen sulfide and sulfur. In rare
cases, non-hydrocarbon content could be greater than 50%.
The term "resources" as used herein is intended to encompass all
quantities of petroleum naturally occurring on or within the
Earth's crust, discovered and undiscovered (recoverable and
unrecoverable), plus those quantities already produced. Further, it
includes all types of petroleum whether currently considered
"conventional" or "unconventional."
Figure 1-1 is a graphical representation of the
SPE/WPC/AAPG/SPEE resources classification system. The system
defines the major recoverable resources classes: Production,
Reserves, Contingent Resources, and Prospective Resources, as well
as Unrecoverable petroleum.
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 (see Production Measurement, section 3.2
of the official PRMS document).
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: 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,
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.
Resources Categorization
The horizontal axis in the Resources Classification (Figure 1.1)
defines the range of uncertainty in estimates of the quantities of
recoverable, or potentially recoverable, petroleum associated with
a project. These estimates include both technical and commercial
uncertainty components as follows:
-- The total petroleum remaining within the accumulation (in-place resources).
-- That portion of the in-place petroleum that can be recovered
by applying a defined development project or projects.
-- Variations in the commercial conditions that may impact the
quantities recovered and sold (e.g., market availability,
contractual changes).
Where commercial uncertainties are such that there is
significant risk that the complete project (as initially defined)
will not proceed, it is advised to create a separate project
classified as Contingent Resources with an appropriate chance of
commerciality.
Range of Uncertainty
The range of uncertainty of the recoverable and/or potentially
recoverable volumes may be represented by either deterministic
scenarios or by a probability distribution (see Deterministic and
Probabilistic Methods, section 4.2 of the official PRMS
document).
When the range of uncertainty is represented by a probability
distribution, a low, best, and high estimate shall be provided such
that:
-- There should be at least a 90% probability (P90) that the
quantities actually recovered will equal or exceed the low
estimate.
-- There should be at least a 50% probability (P50) that the
quantities actually recovered will equal or exceed the best
estimate.
-- There should be at least a 10% probability (P10) that the
quantities actually recovered will equal or exceed the high
estimate.
When using the deterministic scenario method, typically there
should also be low, best, and high estimates, where such estimates
are based on qualitative assessments of relative uncertainty using
consistent interpretation guidelines. Under the deterministic
incremental (risk-based) approach, quantities at each level of
uncertainty are estimated discretely and separately (see Category
Definitions and Guidelines, section 2.2.2 of the official PRMS
document).
These same approaches to describing uncertainty may be applied
to Reserves, Contingent Resources, and Prospective Resources. While
there may be significant risk that sub-commercial and undiscovered
accumulations will not achieve commercial production, it useful to
consider the range of potentially recoverable quantities
independently of such a risk or consideration of the resource class
to which the quantities will be assigned.
Category Definitions and Guidelines
Evaluators may assess recoverable quantities and categorize
results by uncertainty using the deterministic incremental
(risk-based) approach, the deterministic scenario (cumulative)
approach, or probabilistic methods. (see "2001 Supplemental
Guidelines," Chapter 2.5). In many cases, a combination of
approaches is used.
Use of consistent terminology (Figure 1.1) promotes clarity in
communication of evaluation results. For Reserves, the general
cumulative terms low/best/high estimates are denoted as 1P/2P/3P,
respectively. The associated incremental quantities are termed
Proved, Probable and Possible. Reserves are a subset of, and must
be viewed within context of, the complete resources classification
system. While the categorization criteria are proposed specifically
for Reserves, in most cases, they can be equally applied to
Contingent and Prospective Resources conditional upon their
satisfying the criteria for discovery and/or development.
For Contingent Resources, the general cumulative terms
low/best/high estimates are denoted as 1C/2C/3C respectively. For
Prospective Resources, the general cumulative terms low/best/high
estimates still apply. No specific terms are defined for
incremental quantities within Contingent and Prospective
Resources.
Without new technical information, there should be no change in
the distribution of technically recoverable volumes and their
categorization boundaries when conditions are satisfied
sufficiently to reclassify a project from Contingent Resources to
Reserves. All evaluations require application of a consistent set
of forecast conditions, including assumed future costs and prices,
for both classification of projects and categorization of estimated
quantities recovered by each project (see Commercial Evaluations,
section 3.1 of the official PRMS document).
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.
-- 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. Based on additional data and updated
interpretations that indicate increased certainty, portions of
Possible and Probable Reserves may be re-categorized as Probable
and Proved Reserves.
Uncertainty in resource estimates is best communicated by
reporting a range of potential results. However, if it is required
to report a single representative result, the "best estimate" is
considered the most realistic assessment of recoverable quantities.
It is generally considered to represent the sum of Proved and
Probable estimates (2P) when using the deterministic scenario or
the probabilistic assessment methods. It should be noted that under
the deterministic incremental (risk-based) approach, discrete
estimates are made for each category, and they should not be
aggregated without due consideration of their associated risk (see
"2001 Supplemental Guidelines," Chapter 2.5).
Commercial Evaluations
Investment decisions are based on the entity's view of future
commercial conditions that may impact the development feasibility
(commitment to develop) and production/cash flow schedule of oil
and gas projects. Commercial conditions include, but are not
limited to, assumptions of financial conditions (costs, prices,
fiscal terms, taxes), marketing, legal, environmental, social, and
governmental factors. Project value may be assessed in several ways
(e.g., historical costs, comparative market values); the guidelines
herein apply only to evaluations based on cash flow analysis.
Moreover, modifying factors such contractual or political risks
that may additionally influence investment decisions are not
addressed. (Additional detail on commercial issues can be found in
the "2001 Supplemental Guidelines," Chapter 4.)
Cash-Flow-Based Resources Evaluations
Resources evaluations are based on estimates of future
production and the associated cash flow schedules for each
development project. The sum of the associated annual net cash
flows yields the estimated future net revenue. When the cash flows
are discounted according to a defined discount rate and time
period, the summation of the discounted cash flows is termed net
present value (NPV) of the project. The calculation shall
reflect:
-- The expected quantities of production projected over identified time periods.
-- The estimated costs associated with the project to develop,
recover, and produce the quantities of production at its Reference
Point (see section 3.2.1 of the official PRMS document), including
environmental, abandonment, and reclamation costs charged to the
project, based on the evaluator's view of the costs expected to
apply in future periods.
-- The estimated revenues from the quantities of production
based on the evaluator's view of the prices expected to apply to
the respective commodities in future periods including that portion
of the costs and revenues accruing to the entity.
-- Future projected production and revenue related taxes and
royalties expected to be paid by the entity.
-- A project life that is limited to the period of entitlement or reasonable expectation thereof.
-- The application of an appropriate discount rate that
reasonably reflects the weighted average cost of capital or the
minimum acceptable rate of return applicable to the entity at the
time of the evaluation.
-- While each organization may define specific investment
criteria, a project is generally considered to be "economic" if its
"best estimate" case has a positive net present value under the
organization's standard discount rate, or if at least has a
positive undiscounted cash flow.
Economic Criteria
Evaluators must clearly identify the assumptions on commercial
conditions utilized in the evaluation and must document the basis
for these assumptions.
The economic evaluation underlying the investment decision is
based on the entity's reasonable forecast of future conditions,
including costs and prices, which will exist during the life of the
project (forecast case). Such forecasts are based on projected
changes to current conditions; SPE defines current conditions as
the average of those existing during the previous 12 months.
Alternative economic scenarios are considered in the decision
process and, in some cases, to supplement reporting requirements.
Evaluators may examine a case in which current conditions are held
constant (no inflation or deflation) throughout the project life
(constant case).
Evaluations may be modified to accommodate criteria imposed by
regulatory agencies regarding external disclosures. For example,
these criteria may include a specific requirement that, if the
recovery were confined to the technically Proved Reserves estimate,
the constant case should still generate a positive cash flow.
External reporting requirements may also specify alternative
guidance on current conditions (for example, year-end costs and
prices).
There may be circumstances in which the project meets criteria
to be classified as Reserves using the forecast case but does not
meet the external criteria for Proved Reserves. In these specific
circumstances, the entity may record 2P and 3P estimates without
separately recording Proved. As costs are incurred and development
proceeds, the low estimate may eventually satisfy external
requirements, and Proved Reserves can then be assigned.
While SPE guidelines do not require that project financing be
confirmed prior to classifying projects as Reserves, this may be
another external requirement. In many cases, loans are conditional
upon the same criteria as above; that is, the project must be
economic based on Proved Reserves only. In general, if there is not
a reasonable expectation that loans or other forms of financing
(e.g., farm-outs) can be arranged such that the development will be
initiated within a reasonable timeframe, then the project should be
classified as Contingent Resources. If financing is reasonably
expected but not yet confirmed, the project may be classified as
Reserves, but no Proved Reserves may be reported as above.
Economic Limit
Economic limit is defined as the production rate beyond which
the net operating cash flows from a project, which may be an
individual well, lease, or entire field, are negative, a point in
time that defines the project's economic life. Operating costs
should be based on the same type of projections as used in price
forecasting. Operating costs should include only those costs that
are incremental to the project for which the economic limit is
being calculated (i.e., only those cash costs that will actually be
eliminated if project production ceases should be considered in the
calculation of economic limit). Operating costs should include
fixed property-specific overhead charges if these are actual
incremental costs attributable to the project and any production
and property taxes but, for purposes of calculating economic limit,
should exclude depreciation, abandonment and reclamation costs, and
income tax, as well as any overhead above that required to operate
the subject property itself. Operating costs may be reduced, and
thus project life extended, by various cost-reduction and
revenue-enhancement approaches, such as sharing of production
facilities, pooling maintenance contracts, or marketing of
associated non-hydrocarbons (see Associated Non-Hydrocarbon
Components, section 3.2.4 of the official PRMS document).
Interim negative project net cash flows may be accommodated in
short periods of low product prices or major operational problems,
provided that the longer-term forecasts must still indicate
positive economics.
Determination of Reserves and Cash Flows
Proved Developed Producing ("PDP") reserves were determined
using decline curve analysis based on historical gross production
rates. As of April 1, 2018 five of the six leases were producing,
with the Britt 65 lease offline awaiting well repairs. Mosman
reports seven currently producing wells on the five leases.
Production data was provided on a per lease basis and individual
well production histories were not available. All wells currently
produce from the San Andres M2 zone in the San Andres formation
which is productive across much of the Midland Basin.
Proved Non-Producing ("PDNP") reserves are associated with the
repair/replacement of tubing and rods in four currently
non-producing wells. Mosman has estimated the gross cost of repairs
for these four wells to be approximately $50M. These reserves are
associated with the Marr-2, Drennan-8 and Britt 65 1 & 2 wells.
There are two additional wells which Mosman has identified as
needing repairs, however no work plan was provided for these wells
(Fortenberry-3, Welch Townsite-2) and these wells are not included
in the reserves estimate.
Proved Undeveloped ("PUD") reserves are associated with the
proposed drilling of an approximately 3,500 ft lateral horizontal
well within the productive San Andres reservoir zone present
throughout the lease hold and the entirety of the Welch Field. This
horizontal has been designed to develop the undrained southern
portions of the Drennan and Welch Townsite units. The proposed
drilling unit is approximately 59 acres. Estimated ultimate
recoveries from the proposed horizontal well were estimated based
on volumetrics using reservoir data provided by Mosman. Mosman
provided drilling and completion (fracture treatment) cost
estimates totaling approximately $1.5MM. Mosman intends to spud the
well in the summer, with first production forecasted to occur in
September of 2018.
The average annual unadjusted prices used in this analysis are
detailed in the tables on the following page along with the
associated pricing differentials and BTU adjustments where
applicable. Mosman does not currently sell gas from the lease and
any gas produced from the Proved Undeveloped location has not been
included in net reserves or revenue. Operating costs were derived
from LOE data and estimates provided by Mosman and are estimated at
a fixed cost of $1,339/well/month with variable operating costs of
$2.84/BBL of oil and $0.50/BBL of water. Fixed operating costs for
the horizontal PUD location are estimated at $8,000/month for the
first six months of production, decreasing to $3,000/month
thereafter. Variable operating costs are assumed to be the same for
the horizontal well. The current MosmanWI and NRI for each lease
are also displayed on the following page.
This information is provided by RNS
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