Operations Update and 2024 Forward Work Programme

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 Gross¹ 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 £500,000. 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 Paul Griffiths                Executive Chairman Lonny Baumgardner    Managing Director	Tel: [phone] [e-mail]
Novum Securities Limited David Coffman / Jon Belliss	Tel: [phone]
Flagstaff Strategic and Investor Communications Tim Thompson  Mark Edwards Fergus Mellon	Tel: [phone]  [e-mail]

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.

 

END