TIDMPRD
RNS Number : 4540Z
Predator Oil & Gas Holdings PLC
12 January 2024
FOR IMMEDIATE RELEASE
12 January 2024
Predator Oil & Gas Holdings Plc / Index: LSE / Epic: PRD /
Sector: Oil & Gas
LEI 213800L7QXFURBFLDS54
Predator Oil & Gas Holdings Plc
("Predator" or the "Company" and together with its subsidiaries
the "Group")
Operations update and 2024 forward work programme
Highlights
-- Phase 1 Guercif rigless well testing scheduled to commence before 25 January
with Phase 2 using Sandjet scheduled for February/March
-- Site visit to Cory Moruga scheduled for 22 - 26 January to begin planning for well workovers
-- Cory Moruga Independent Technical Report gives P50 and P90
Contingent and Prospective gross recoverable resources of 14.31 and
21.41 million barrels respectively
-- H1 2024 well workovers forecast to generate gross net
operating profit of US$ 3.1 million in 12 months from H2 2024 to H1
2025
-- Cory Moruga Field Development Plan for P90 Contingent and
Prospective gross recoverable resources of 9.13 million barrels
gives gross US$202.12 million undiscounted net operating profit
(NPV@10% US$85.14 million with IRR 240.9%)
-- Well planning for discretionary high impact Jurassic well commenced for April/May drilling
-- Fully funded for all 2024 firm commitments
-- Potential for gas monetisation and Cory Moruga production
revenues to fund discretionary drilling
-- Low corporate and operating overhead maintained despite increase in activity
Predator Oil & Gas Holdings Plc (LSE: PRD), the Jersey based
Oil and Gas Company with near-term operations focussed on Morocco
and Trinidad, is pleased to provide an operations update.
CORY MORUGA PRODUCTION LICENCE ONSHORE TRINIDAD
Further to the announcement of 7 November 2023 in respect of the
acquisition of T-Rex Resources (Trinidad) Limited ("T-Rex"), the
Company is publishing today an Independent
Technical Report ("ITR") by Scorpion Geoscience Ltd. for the
Cory Moruga block and resource potential of the Snowcap
Discovery.
https://wp-predatoroilandgas-2020.s3.eu-west-2.amazonaws.com/media/2024/01/Cory-Moruga_ITR_20230111-final-11.01.24-13.11-hours.pdf
Oil resources
Table 1 Unrisked Gross(1) Contingent and Prospective
Oil-in-Place
and Recoverable Resources (million barrels oil)
Herrera Sand P90 P50 P10 Category
# 8 in place 4.57 5.94 7.54 Contingent
--------- -------------- ------------- ------------
# 8 recoverable 1.04 1.40 1.84 Contingent
--------- -------------- ------------- ------------
Recovery Factor
(%) 22.75 23.57 24.4
--------- -------------- ------------- ------------
# 1 to 7 in place 35.03 54.9 81.71 Prospective
--------- -------------- ------------- ------------
# 1 to 7 recoverable 8.09 12.91 19.57 Prospective
--------- -------------- ------------- ------------
Recovery Factor
(%) 23.09 23.51 23.95
--------- -------------- ------------- ------------
(1) Discussions commenced to acquire, subject to regulatory
consent, the remaining 16.2%
interest in Cory Moruga for an overriding royalty
Field size is indicated as being similar to the nearby mature
producing oil fields at Moruga West and Inniss-Trinity. Production
and reservoir data from these fields have been incorporated in
assessing the primary recovery factors used for the generation of
the resource figures shown in Table 1.
Wax suppression and pressure maintenance are seen as key aspects
of ensuring longer term productivity and improved Expected Ultimate
Recovery ("EUR"). Gas injection undertaken by BP in a single
compartment of the Moruga West Field boosted EUR recovery by an
additional 10% in 1963 but was abandoned due to a lack of gas. The
ITR notes that a 30% recovery factor may be achievable given that
Cory Moruga has a range of 5.67 to 13.8 BCF of associated gas
available for reinjection over a scoping 15-year production life of
the field modelled for the purpose of generating project
economics.
Later in field life CO2 EOR could be considered to potentially
boost EUR.
Geological risk in relation to the Prospective Resources are
summarised as the chances of not encountering reservoir;
encountering reservoir that is not saturated with oil; encountering
reservoir from which oil will not flow to surface and is not
producible.
Risks associated with the Herrera #8 Sand Contingent Resources
relate to the continuity and producibility of oil in the context of
tight borehole conditions, incomplete logging and limited well
testing.
Flow assurance relies on effective treatment for wax suppression
and the potential requirement for gravel-packed completions.
Uncertainty regarding future oil prices may also create
commercial risks from time to time during field life.
Workovers of existing Snowcap-1 and Snowcap-2ST1 discovery
wells
Management is making a site visit to Trinidad in the week of 22
January 2024 to meet with
local well services contractors and to identify workover rigs to
prepare for implementing the
Snowcap-1 and Snowcap-2ST1 well re-entries.
Subject to wireline well surveys to confirm borehole conditions,
a workover and wax treatment will be performed in H1 2024 on
Snowcap-1 for the Herrera #8 Sand. Initial Production Rate ("IPR")
is forecast to be 200 bopd declining to 130 bopd after 12
months.
A workover and wax treatment will be performed on Snowcap-2ST1
for the Herrera #7 and #8 Sands. Initial Production Rate ("IPR") is
forecast to be 200 bopd declining to 130 bopd after 12 months (with
an upside IPR potential of 300 to 400 bopd).
Wax treatment and gas management will be critical to reducing
the decline rates.
Total estimated gross costs for the workovers and for
re-establishing Cory Moruga oil production facilities are forecast
by the Company to be GBP500,000. The Company is fully funded to
execute the well workovers from discretionary cash in its 2024
working capital forecast.
Workovers will be completed as early as possible in H1 2024 with
forecast, ITR-supported, operating profits after all costs and
taxes for the 12 months from H2 2024 shown in Table 2 below.
Table 2 Unrisked post-tax net operating profit (US$)
12 months commencing June 2024 (WTI flat at US$76/barrel)
Q2/Q3 2024 Q4 2024 Q1 2025 Q2 2025
Snowcap-1 workover 623,084 420,611 374,667 220,148
----------- --------- ------------ -----------
Snowcap-2ST1 workover 557,712 372,966 334,122 201,163
----------- --------- ------------ -----------
Combined 1,180,796 793,577 708,789 421,311
----------- --------- ------------ -----------
Cory Moruga Field Development Plan ("FDP")
A Snowcap-3 appraisal well would be located to test the Herrera
#1 - 3 and #6 to 8 Sands and would be the first step in
implementing the FDP. The thickest Herrera #1 and #2 Sands were not
reached in either Snowcap-1 or Snowcap-2ST1 legacy wells within the
Snowcap structure defined by 3D seismic. Herrera #1 and #2 Sands
are the primary reservoir units in the adjoining Moruga West
Field.
Potential production from co-mingling the Herrera H#1, H#2 and
H#3 Sands is forecast to be 1,000 bopd IPR declining by 35% over 12
months .
Once H#1, H#2 and H#3 Sands are at equal pressure H#6, H#7 and
H#8 sands could be added to production for an additional 400 bopd
IPR declining by an estimated 35% over the first 12 months.
Snowcap-3 is estimated to cost a gross amount of US$3 million to
drill. Currently the appraisal well is planned for 2025 and could
be fully funded by the operating profits from the well workover
programme (Table 2 above).
A preliminary Base Case 15-year production profile and compared
with that for the adjoining former BP and Shell Moruga West field,
uses only the P90 oil resources and is presented in the ITR. It
assumes 14 new production wells and a peak scoping gross production
rate of 3,500 bopd.
Projected gross operating profits for the first 10 years of
production are shown in Table 3 below.
Table 3 Unrisked post-tax net operating profit (US$ millions)
10 years commencing 2025 (WTI flat at US$76/barrel)
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034
2.989 11.899 27.168 21.541 25.600 29.228 23.890 20.132 9.609 9.587
------- ------- ------- ------- ------- ------- ------- ------ ------
Phased development drilling is expected to be funded from
post-tax operating profits to allow the Company to be fully funded
for all of its projected capital expenditures.
Project economics
At WTI US$76/barrel spot price the gross undiscounted operating
profit based on the above FDP is US$202.12 million.
NPV @10% is US$ 85.14 million.
IRR is 240.9%.
Undiscounted net-back is US$19.61 per barrel of oil.
In the case of a 100 bopd production rate and a WTI spot price
of US$50 per barrel, gross net operating revues are still strongly
positive generating US$434,870.
Future potential development upside
Potential exists to re-enter and re-perforate the RD-6 and RD-7
wells, which are located in the Cory Moruga Block but are within
the Moruga West oil field and have previously been produced.
Additionally there may also be an opportunity to re-enter Green
Hermit-1 to evaluate an untested thick interval of the Herrera #1
Sand which had oil shows whilst drilling. Low resistivity oil pays
have been shown to be productive in the Moruga West field and
potentially could be evaluated using the Sandjet perforating
technology that the Company intends to deploy in Morocco.
GUERCIF TESTING PROGRAMME ONSHORE MOROCCO
An updated Independent Technical Report ("ITR"), incorporating
the 2023 MOU-3 and MOU-4 well results is currently being prepared
by Scorpion Geoscience Ltd. for the Guercif block and resource
potential of the prospective area tested by MOU-1, MOU-2, MOU-3 and
MOU-4. The Company will use it best endeavours to publish the ITR
before the Phase 1 rigless testing commences.
Phase 1
Phase 1 is planned to commence before 25 January 2024 and is
expected to take up to 14 days to complete.
The unforeseen regulatory issue relating to Guercif Petroleum
Agreement Amendment No.3 has now been successfully resolved.
Intervals to be tested are as previously announced.
MOU-3
1,406.0 to 1,412.0 metres RKB (within Moulouya Fan interval);
and
845.0 to 849.0 metres RKB (Ma Sand)
MOU-1
1,236.5 to 1,241.1 metres RKB (TGB-2 Sand); and
844.0 to 848.0 metres RKB (Ma Sand)
Successfully perforating the Ma and TGB-2 Sands, whilst
depending on test rates and any evidence of reservoir depletion,
may justify an 10-year production profile at a plateau rate of 10
mm cfgpd based on anticipated volumes within the structures tested
by these wells.
Depending on test results and the potential to comingle
production from the two different horizons in MOU-1, a 20 mm cfgpd
profile for up to 5 years may also be achievable.
Production forecasts are dependent on a successful outcome to
the perforating programme.
The Phase 1 rigless testing of a small interval of the MOU-3
Moulouya Fan reservoir has only currently been programmed to
evaluate reservoir quality and potential gas flow rates at this
location. This may allow the Company to improve upon the design of
the Phase 2 rigless testing programme using Sandjet to further
evaluate the Moulouya Fan.
The Company is fully funded to execute the Phase 1 rigless
testing programme.
Phase 2
Phase 2 rigless testing operations using Sandjet are planned to
commence in early February to early March. The duration of
operations is forecast to be for up to 21 days.
Regulatory approval of the Guercif Petroleum Agreement Amendment
#4, which is proposing to extend the Initial Period of the Guercif
Petroleum Agreement to 5 June 2024, is a pre-requisite before Phase
2 testing operations can commence..
Depending on the results of the Phase 1 rigless testing,
Petroleum Agreement Amendment #4 would also potentially facilitate
an application by 5 March 2024 for a single Exploitation Concession
over the area tested by MOU-1 and MOU-3, providing geological
continuity of potential gas reservoirs can be demonstrated.
The Sandjet rigless testing programme is likely to target,
subject to further refinement, the following intervals:
MOU-4
Thin Jurassic dolomitic reservoirs
Moulouya Fan
Highly porous weathered volcanic interval
Multiple thin shallow sands
MOU-3
Several thin sands within TGB-6
TGB-4
Sandjet allows multiple horizons to be tested relative to
conventional perforating guns based on cost considerations. It also
potentially perforates further beyond any formation damage relative
to conventional perforating guns.
Trialling Sandjet at Guercif may also allow the Company to
evaluate its suitability for the planned Cory Moruga well workovers
and FDP implementation to assess the ability to increase initial
well deliverability.
Sandjet will be testing intervals in MOU-3 and MOU-4 where
current conventional wireline log interpretation is adversely
impacted by possible formation damage caused by the requirement to
drill over-balanced with heavy drilling mud to control the wells
through highly mobile claystones.
NuTech petrophysical log interpretation for the above intervals
interprets the presence of gas. However the integrity of the
interpretation can only be verified after the programme of Sandjet
rigless testing has been completed.
Sandjet rigless testing results will determine in the shorter
term any ability to upscale to a 50 mm cfgpd production profile
facilitated under the Collaboration Agreement for a CNG Gas Sales
Agreement with Afriquia Gaz.
The Company is fully funded to execute the Phase 2 rigless
testing programme.
Discretionary potentially high impact Jurassic
appraisal/exploration drilling
Planning is underway based on a provisional drilling window in
April/May.
Subject to the regulatory approval of Guercif Petroleum
Agreement Amendment #4 to extend the Initial Period of the Guercif
Petroleum Agreement to 5 June 2024, the Company is seeking to drill
the Jurassic target, the extreme edge of which was penetrated in
MOU-4 downdip from the crest of the large mapped seismic closure of
126km2.
There is currently in-country rig availability within the window
for which MOU-4 NE could be ready for drilling, subject to
regulatory approvals and the schedule for delivery of long-lead
well inventory items.
MOU-4 NE is forecast to take up to 12 days to drill.
This is a higher risk but potentially high reward well close to
gas infrastructure (the Maghreb gas pipeline).
A successful well may create a new potential gas market
(gas-to-power) if the scale of the opportunity for the MOU-4 NE
structure is realised.
Funding the discretionary well would depend on final well cost
estimates; the quantum of discretionary cash on the Company's
balance sheet in Q2 2024; and the ability for potential early
monetisation of gas following a successful Phase 1 rigless testing
programme.
Discretionary appraisal/development drilling
Discretionary appraisal/development drilling is provisionally
scheduled for H2 2024.
Subject to an application and the subsequent award of an
Exploitation Concession and regulatory approval of the drilling
programme, the Company may drill two appraisal/development wells to
potentially, if successful, add incremental gas resources to
support and extend the CNG production profiles.
MOU-3-NW
MOU-3NW will target the shallow sands behind casing in MOU-3 and
not available for rigless testing in that well. MOU-3 NW will
require a revision of the well design to facilitate rigless testing
of potential shallow gas at higher than normal reservoir pressure
for the shallow depth.
MOU-3-SW
MOU-3SW will target the Ma, TGB-6 and, potentially, depending on
Phase 2 rigless testing results, TGB-4 sands.
MOU-2 re-entry and deepening
Subject to an evaluation of the Phase 1 and Phase 2 rigless
testing results, the Company has an option to re-enter the MOU-2
well and deepen it to the Moulouya Fan target.
Funding and timing of the discretionary drilling programme will
be dictated by the availability and quantum of production revenues
generated by Cory Moruga and the opportunity for partial
monetisation of gas assets in Guercif, always subject to a
successful rigless testing programme.
The discretionary drilling programme may have to be aligned with
a requirement to further develop the CNG industrial gas market
above the 50 mm cfgpd cap set in the Afriquia Gaz Collaboration
Agreement.
IRELAND
The applications for successor authorisations to Licensing
Options 16/26 (Corrib South) and 16/30 (Ram Head) remain under
consideration by the Department of the Environment, Climate and
Communications.
Paul Griffiths, Executive Chairman of Predator, commented:
"I am pleased to confirm that 2024 is set to be the busiest year
for activity since the Company was incorporated.
The addition of a substantial, near virgin, field appraisal and
development asset onshore Trinidad provides the Company with the
potential to generate strongly positive cashflows in 2024 to
contribute organically towards further development of its
assets.
The milestones to be met for potential monetisation of gas in
Morocco, subject to the results of the Phase 1 rigless testing, are
now clearly defined from a regulatory, technical, marketing and
operational perspective. The objective over the last six months
since the completion of the 2023 drilling programme has always been
focussed on ensuring that all the elements for monetising gas are
put in place to support an application for an Exploitation
Concession.
Management's appetite for efficiently drilling within pre-drill
budgets moderate risk but high impact wells that potentially
generate a multiple uplift on drilling costs remains strong and
aligned with current market sentiment. For this reason we are also
focussed on accelerating the drilling of the Jurassic target in
Morocco and a high impact appraisal well in Cory Moruga at a later
date. The Company is in a position of strength where it can dictate
the timing of exercising high impact discretionary drilling
opportunities either through eventual Cory Moruga production
revenues or through an accelerated process triggered by potential
early partial monetisation of gas assets, which are subject to a
successful rigless testing programme.
The Company is however also able to fund its firm 2024
commitments whilst maintaining some discretionary cash on the
balance sheet without considering potential production revenues
from Cory Moruga in 2024.
Funding the CNG development can be achieved using discretionary
cash on the balance sheet combined with a leasing arrangement for
CNG trailers and equipment. For this reason it has been important
to develop the scale of potential CNG gas sales in Guercif, in a
success case, to provide greater leverage to negotiate leasing
agreements with greater materiality for potential service
providers..
The CNG development schedule will be updated after the Phase 1
rigless testing results.
The Company has maintained strict oversight over its operating
and commercial overheads and despite the exponential increase in
activity we will continue to practice restraint when it comes to
controlling costs."
For further information visit www.predatoroilandgas.com
Follow the Company on twitter @PredatorOilGas.
This announcement contains inside information for the purposes
of Article 7 of the Regulation (EU) No 596/2014 on market abuse
For more information please visit the Company's website at
www.predatoroilandgas.com :
Enquiries:
Predator Oil & Gas Holdings Plc Tel: +44 (0) 1534 834 600
Paul Griffiths Executive Chairman Info@predatoroilandgas.com
Lonny Baumgardner Managing Director
Novum Securities Limited Tel: +44 (0)207 399 9425
David Coffman / Jon Belliss
Flagstaff Strategic and Investor Communications Tel: +44 (0)207 129 1474
Tim Thompson predator@flagstaffcomms.com
Mark Edwards
Fergus Mellon
Notes to Editors:
Predator is operator of the Guercif Petroleum Agreement onshore
Morocco which is prospective for Tertiary and Jurassic gas. The
current focus of the exploration and appraisal drilling programme
is located less than 10 kilometres from the Maghreb gas pipeline.
The MOU-1 well drilled in 2021 and the MOU-3 and MOU-4 wells
drilled in 2023 have been completed for rigless testing in early
2024. Near-term focus is on supplying compressed natural gas
("CNG") to the Moroccan industrial market. A Collaboration
Agreement for potential CNG gas sales of up to 50 mm cfgpd has been
executed with Afriquia Gaz. Further drilling activity is
anticipated in 2024 to further evaluate the MOU-4 Jurassic
prospect.
Predator is seeking in the medium term to apply CO2 EOR
techniques onshore Trinidad which have the advantage of
sequestrating anthropogenic carbon dioxide. The acquisition of
T-Rex Resources (Trinidad) Ltd. ("T-Rex") is a first step to
realising this objective. T-Rex holds the Cory Moruga Production
Licence. Cory Moruga is a largely undeveloped near-virgin oil field
of similar potential size to the nearby Moruga West and
Inniss-Trinity mature oil fields. The Cory Moruga Production
Licence is a potentially significant asset for the Company with the
capability of generating positive operating profits in the
near-term. Capital required for staged field development can be
implemented potentially utilising operating profits generated from
an increasing level of gross production revenues.
Predator owns and operates exploration and appraisal assets in
licensing options offshore Ireland, for which successor
authorisations have been applied for, adjoining Vermilion's Corrib
gas field in the Slyne Basin on the Atlantic Margin and east of the
decommissioned Kinsale gas field in the Celtic Sea. The
applications for successor authorisations remain "under
consideration" by the DECC.
Predator has developed a Floating Storage and Regasification
Project ("FSRUP") for the import of LNG and its regassification for
Ireland and is also developing gas storage concepts to address
security of gas supply and volatility in gas prices during times of
peak gas demand.
Further progress for the Mag Mell FSRUP will be dependent on
government policy in relation to security of energy supply. A
generalised FSRUP concept has now been recognised by the government
as an option for security of energy supply.
The Company has a small but highly experienced management team
with a proven track record in successfully executing drilling
operations in the oil and gas sector and in acquiring assets where
there is a potential to generate multiple returns for relatively
low and manageable levels of investment.
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END
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